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Design considerations for multiyear Public Utility rate plans
Utilities Policy 59 (2019) 100923
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Design considerations for multiyear Public Utility rate plans Kenneth W. Costello
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ABSTRACT
Regulatory experts generally agree that good regulation leads to high economic efficiency, fairness, and moderate regulatory costs. These three features have characterized good regulation going back to the beginning of the previous century. This paper will try to show that wellstructured and executed multiyear rate plans (MRPs) can be more compatible with the public interest, compared with the traditional rate-of return approach to setting utility rates. Substandard MRPs, however, can produce worse outcomes for utility customers.
1. Criticisms of traditional ratemaking in the United States Rate-of-return ratemaking (hereinafter “traditional ratemaking”) refers to the application of cost-of-service principles for setting rates that determine the utility's authorized rate of return. Features include: (1) rates remain fixed until the regulator approves new rates following a general rate case; (2) the utility has a reasonable opportunity to earn its authorized rate of return; (3) the balancing of utility shareholder and ratepayer interests is an overriding goal; (4) the selected test year matches revenues with costs over the first year of new rates; (5) the utility's actual rate of return between rate cases deviates from the authorized return when actual sales or costs differ from their test-year levels; and (6) regulatory lag can either benefit or harm utilities, depending on whether average cost is decreasing or increasing (Kahn, 1971). Traditional ratemaking has been criticized over the years based on one or more of the following arguments made: it fails to update rates for changes in costs beyond the test period, meaning that during an inflationary-cost period, utilities would tend to file frequent rate cases or that during a deflationary period earn excessive profits; it can give utilities weak incentive to innovate because of an imbalanced risk-reward relationship; it can create excessive delay for utilities in recovering their costs for new capital projects; it provides utilities with weak incentives to control their costs due to frequent rate cases (less lag); it can create rate shock under inflationary and other conditions, leading to political problems for regulators and a disruptive effect on consumption; it places high demands on regulatory staff and utility resources, especially when rate cases are also complex; it motivates utilities to try to increase both sales and rate base when alternative actions would be in the public interest; it allows utilities to decide the timing of rate cases, thereby manipulating the regulatory process to
their advantage (for example, not filing a rate case when profits are far above the authorized level. A related criticism originates with the Averch-Johnson (A-J) effect, which says that a utility would use excessive capital input relative to other inputs such as labor, fuel, and materials. This outcome assumes that a utility faces a binding rate-of-return constraint on its rate base and its allowed rate of return exceeds its actual cost of capital (Averch and . Johnson, 1962). The transformation of the electric industry, driven by major developments in technology, public policy objectives emphasizing clean energy and customer activism, calls into question whether traditional ratemaking can accommodate the public interest by establishing just and reasonable rates, which have two prominent traits. First, they should reflect prudent and efficient expenditures. Second, they allow the utility a reasonable opportunity to receive sufficient revenues to attract new capital and avoid serious financial problems not caused by incompetent management. In the 1990s, when the U.S. electric industry went through major restructuring, many experts believed that traditional ratemaking would come to an end (Borenstein and Bushnell, 2014). Some of this sprung from the experience in the telecommunications industry and the electric industry's concern over whether its earnings under traditional ratemaking would fall short of financial viability. One idea was to implement price caps or other more flexible ratemaking mechanisms to replace it. What actually transpired was that state utility regulators were unwilling to give up traditional ratemaking, although they were open to modifications. A lesson learned is that supporters of new ratemaking mechanisms, such as multiyear rate plans (MRPs), must make a compelling case for why regulators should reject traditional ratemaking, which has prevailed from almost the beginning. For many regulators, traditional ratemaking has performed admirably in protecting consumer interests.
E-mail address: [email protected]. Regulatory Economist/Independent Consultant. The funding for this article came from the Center for Business and Regulation (CBR), University of Illinois Springfield. The author presented an earlier draft at the Conference on Frameworks for Regulation of Public Utilities in the 21st Century: Part 2, sponsored by CBR, September 28, 2017. 1
https://doi.org/10.1016/j.jup.2019.05.009 Received 25 January 2019; Received in revised form 13 May 2019; Accepted 13 May 2019 Available online 25 May 2019 0957-1787/ © 2019 Elsevier Ltd. All rights reserved.
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The burden seems to fall on those to show that an alternative approach is superior.
rate cases. Although in some instances regulators encountered initial difficulties, including the broad one of evaluating the reasonableness of a utility's forecasts, they were able to eventually overcome them (Costello, 2013 (a)). But as pointed out later, an FTY confront regulators with various challenges, an important one being whether the forecasted costs reflect a prudent utility. The second part of MRPs involves calculating the changes in base rates or revenues outside the test period. This is where MRPs are distinguished from traditional ratemaking. A utility can apply detailed cost forecasts or escalation factors attached to the base rate or revenue. An escalation factor acts as an attrition adjustment to rates. As discussed later, this gives utilities a stronger incentive to control their costs and is a common feature of MRPs outside the U.S. The Alberta Utilities Commission went from using detailed cost forecasts for each year of the MRP to using indices to escalate rates, mainly for this reason. Alternatively, rate changes can be a function of a predetermined amount forecast during the previous rate case. California went in the direction of going from an index approach to using 3-year forecasts of revenue requirements (Brown et al., 2014). Forecasts can derive from detailed cost of service analysis, a utility's budget, or a combination of both. Forecasting a utility's costs three to five years out poses special challenges for regulators to determine their accuracy (discussed in more detail later). The third part is the duration of MRPs. With MRPs predetermining the timing of general rate cases, the length of regulatory lag becomes known to the utility and other stakeholders. The longer is the duration the more incentive a utility has to control its costs (Posner, 1969). General rate cases would also be less frequent. As a downside, a longer duration would increase the likelihood that a utility's rate of return will fluctuate farther from the regulator's authorized level. The optimal duration therefore becomes case-specific, with the regulator having to consider the trade-off between cost efficiency and stable earnings.
2. Basic information about MRPs 2.1. Primary features An MRP is a comprehensive regulatory pricing mechanism that allows base rates to change outside of a general rate case and have the following features: 1. Predetermination of rate changes either in dollars or according to a formula beyond the test period (for example, three to five years); 2. A process for setting a utility's rates and revenue requirements for longer than a single 12-month period; 3. Fixed frequency of general rate cases (i.e., regularized regulatory lag); 4. Forward-looking that commits the regulator for a multiyear period, giving utilities greater certainty of cost recovery for new investments; 5. Earnings attrition relief between rate cases beyond the test period based on a formula, index, or multiyear forecasts2; and 6. Typically, incentives on utility functional areas (e.g., reliability, customer service) whose performance may suffer from stronger incentives for cost reductions (Hauge and Sappington, 2010). Some MRPs specify allowable revenue changes, which have a different effect on utility behavior than specifying allowable rate changes. The former specification would give utilities less disincentive to promote demand management and conservation, which has become a major objective for many state utility regulators. Concerning the second feature, one interpretation is that an MRP establishes the rates a utility can charge for each year of the plan's duration, based only on the utility's reasonable and prudent costs of service over this period. Ratemaking, as practiced today in the U.S., represents a hybrid of features of different rate mechanisms that have evolved over time. By forecasting revenue requirements out (say) to three years, an MRP is just an extension of setting rates based on a future test year. Traditional ratemaking today applies a future test year that reduces lag by accounting for expected changes in costs and attrition after the test year (Costello, 2013 (b)). Because of this distinction, MRPs give utilities different incentives to operate efficiently, invest in socially-beneficial capital projects, and perform well in other functions.
2.3. Noncore elements The noncore elements of an MRP are optional features necessary for implementation. These address political acceptability and the avoidance of “extreme” outcomes that might jeopardize the sustainability of an MRP, and may reflect the bargaining strengths of the various stakeholders. In the U.S., MRPs for utilities reflect compromises that have diminished their effectiveness in maximizing a utility's incentive for cost efficiency. This is something that is ostensibly unavoidable, especially in the electric industry where cost efficiency typically takes a back seat to other regulatory objectives. As a side note, economists sometimes forget that the main goal of regulation is not merely to promote economic efficiency, of which cost efficiency is a component: Regulation originated and developed prior to the ideas of economic efficiency and the principles of welfare economics. Most enabling legislation mandates just, reasonable and fair rates, not efficient rates per se. Throughout the history of state utility regulation, “fairness” has been a major determinant of ratemaking (Bonbright et al., 1988). MRPs can protect ratepayers from events that were not anticipated when the regulator approved the plan. Such events can include poor performance in service quality and operations, abnormally high rates of return, exceptionally high capital costs, and imprudent utility costs. “Protection” mechanisms include refunds for an “excessive” high rate of return, caps on recoverable capital costs, monitoring of utility performance, and detailed audits to determine appropriate cost recovery.4 One caveat is that if carried to an extreme, protecting ratepayers from
2.2. Core elements MRPs have three structural parts. The first is the starting base price or revenue, which derives from test-year cost and sales statistics.3 Most plans use a future test year (FTY). One general finding from a 2013 survey was that most state utility regulators using an FTY have had an overall positive experience, with no intention to discard an FTY in later 2 Attrition refers to the tendency for a utility's rate of return or profits to fall since the last rate case. Attrition exists when revenue growth falls short of revenue-requirement increases, eroding the utility's rate of return over time in the absence of a rate change. On the opposite side of the spectrum is the term accretion, which refers to a utility “over-earning" between rate cases. In an environment where a utility's productivity is growing rapidly and inflation is low, a utility's earnings are likely to exceed between rate cases the authorized rate of return set in the last rate case. 3 A test year is an actual or hypothetical 12-month period over which a utility calculates its costs, including both operating and capital costs, and sales to determine the need for a rate change. At the core of a rate test year is the “matching principle” for achieving consistency between costs and revenues. The utility would accordingly consider jointly revenue requirements and billing determinants in setting new rates.
4 Utility cost recovery in the absence of regulatory oversight would tend to create a “moral hazard” problem that diminishes a utility's incentive to manage its costs. Detailed audits to determine prudence, however, is time-consuming, information-intensive, and highly contentious.
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unexpected outcomes could compromise a utility's actions that benefit ratepayers in the long run. As argued by some analysts, a utility earning a higher profit because of exceptional cost-efficiency attributed to superb management should be able retain those benefits for a reasonable minimum time before transferring them to ratepayers. One element common to MRPs is performance metrics for non-cost utility functions, such as reliability and customer service. A concern is that utilities under an MRP may jeopardize their service quality by controlling costs to increase their rate of return (Hauge and Sappington, 2010). Some MRPs have performance standards or incentives for service quality and reliability (Hesmondhalgh et al., 2012.) When the utility receives additional revenues from higher performance, an obvious question is what share of the benefits should transfer to ratepayers. These benefits should at least cover the additional revenues that ratepayers have to pay the utility, or else ratepayers are worse off.
But not everyone shares this optimism. One observer opines that he does “not envisage any near-term expansion of that particular form of rate control [MRPs] for the North American electricity industry.” One reason is the trend toward partial or targeted-based incentive regulation. He also argued that the changes occurring in the electric industry will make it difficult for any multiyear plan to handle the dynamics of future utility investment costs (Makholm, 2018). As a rebuttal to his first reason, partial and MRPs can coexist since they have different objectives. In fact, as discussed later, partial incentive mechanisms for such functions as customer and service reliability can complement an MRP. The second point has more merit, as multiyear plans have struggled with the treatment of capital expenditures. The basic challenge for regulators is to balance the trade-off between giving a utility a strong incentive to control its capital costs and a reasonable opportunity to achieve a rate of return that is within the authorized range.
3. Major arguments for multiyear rate plans (MRPs)
4. Theoretical issues
Support for MRPs derives from four sources. First, from the perspective of utilities new market and operating conditions, namely, rising average cost and the slowdown of demand growth, argues for a ratemaking mechanism to address earnings erosion beyond the test period. Under traditional ratemaking, no matter how much the actual utility's costs and revenues deviate from their test-year levels, base rates remain fixed until the regulator approves new ones in a future rate case. The exception is when a regulator allows for interim rate relief under abnormal and unexpected conditions that jeopardize a utility's financial well-being. The fact that most MRPs for U.S. electric utilities involve vertically integrated utilities suggests that one of their main purposes is to expedite the recovery of capital costs for generation (Lowry et al., 2017). Second, instead of a utility filing a new general rate case due to earnings attrition (associated with revenues falling below costs over time) under traditional ratemaking, an MRP may forecast future conditions over a multiyear period or use cost indices to adjust rates over the plan's duration within the confines of a single rate case. This means that a utility can recover operating costs, normally recoverable only after filing a general rate case, prior to a future rate case. Third, given the resource constraints of many state utility regulators, an MRP can lower regulatory costs and enhance regulatory efficiency by conducting fewer cases. Major rate cases absorb a substantial amount of staff resources and time, jeopardizing the regulatory agency's ability to address other issues that in recent years have become more complex. Fourth, well-structured MRPs also have the potential to improve a utility's operating performance. This results from regularized regulatory lag and rate adjustments based on an index for exogenous factors. As early as the late 1960s and early 1970s utilities and other stakeholders sought for nontraditional rate mechanisms because of technological developments, new public policies, and a changing market and operating environment (Joskow, 1974). Beginning in the 1980s, theoretical research on incentive regulation evolved to address directly asymmetric information problems (discussed later) and related contracting constraints, regulatory credibility issues, dynamic considerations, regulatory capture, and other issues that analysts have been grappling with for decades in the absence of a comprehensive theoretical framework to guide them. (Joskow, 2014). These mechanisms reflect a departure, although largely marginal ones, from traditional ratemaking practices (Brown et al., 1991; and Harunuzzaman et al., 1994). The main objective of this article is to present the features of an MRP that utilities and regulators may want to consider if they are to advance the public interest. While the question of whether utilities should operate under an MRP only under exceptional conditions and circumstances may have some merit, the proposal here is that MRP has potential to gain wider acceptance in utility ratemaking.
4.1. The downsides of MRPs Utility regulators must set reasonable rates that allow a utility making prudent decisions to operate successfully, maintain its financial integrity, attract capital, and compensate investors in line with actual risks.5 Regulation can be undermined by ideology, ignorance, and inertia. Basing ratemaking policies on political leanings, inadequate information, and past conditions that no longer exist may lead to failure, regardless of the ratemaking method. Different versions and variations of MRPs have different outcomes depending on their structure and implementation. A poorly designed MRP is unlikely to improve outcomes compared with traditional ratemaking, and it could actually make matters worse, especially for utility ratepayers. Specifically, a poorly designed MRP can: (1) create perverse incentives whereby societal benefits become negative; (2) impose undue restrictions on utilities preventing them from pricing flexibly or managing their operational activities; (3) excessively allocate the benefits of utility efficiencies to either shareholders or ratepayers without recognizing tradeoffs; or (4) omit as its chief objective the long-term welfare of utility customers, which aligns with the widely-held public-interest perspective of regulation. In other words, like other ratemaking mechanisms, MRPs can produce inferior results to traditional ratemaking. While the concept of multiyear ratemaking has merit, the details determine how it compares to other ratemaking methods. For example, formula-rate plans prevent utilities from earning extremely high or low profits between formal rate reviews. They adjust base rates between general rate cases, which in that sense falls under the meaning of an MRP, on the basis of a utility's actual costs. Some analysts consider formula rate plans as a comprehensive cost tracker, placing them outside the category of MRPs (Lowry and Woolf, 2016). 4.2. The U.S. Experience U.S. utility regulators were receptive to MRPs in the form of price caps for the telecommunications industry. The industry took the initiative in proposing them and later market forces replaced them in setting prices for different services. Regulators and legislatures accepted price caps in the telecommunications industry largely because of growing problems with traditional ratemaking. These problems harmed different interest groups in addition to distorting and discouraging emerging competitive forces in the industry. Regulators allowed Regional Bell Operating Companies to enter non-regulated lines of 5 The U.S. Supreme Court outlined these conditions in its order for FPC v. Hope Natural Gas Co., 320 U.S. 591, 605 (1944).
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businesses as technology evolved rapidly. In response, they were searching for a more streamlined and effective method of regulation, which they found in price caps (Sappington and Weisman, 2016). A small minority of U.S. energy utilities operate under MRPs. The empirical evidence thus far has been generally favorable (Lowry et al., 2017). Regulators’ rejection or non-consideration of an MRP may be more of a rational response than inertia favoring the status quo (Sappington and Weisman, 2016). The lack of wide acceptance of MRPs may reflect the reluctance of risk-averse regulators to accept a mechanism with uncertain outcomes that could make matters worse, which is conceivable with poorly structured and implemented MRPs. Perceived problems with MRPs include inaccurate or biased multiyear forecasts that favor the utility, premature utility recovery of costs for capital projects, and the compromise of service quality and other noncost performance areas. Consumer groups are generally opposed to MRPs for these and other reasons (Larkin & Associates, PLLC, 2012). Regulators and utilities may prefer more incremental changes to address attrition, such as revenue decoupling and expanded use of cost trackers (Washington Utilities and Transportation Commission, 2013). Under revenue decoupling, the utility adjusts its rates between rate cases for sales deviating from some baseline level, illustrated by a periodic adjustment of rates for a gap between actual sales and test-year sales per customer. Cost trackers allow a utility to recover costs from ratepayers that vary from those costs embedded in rates established at the last general rate case (Costello, 2009). Utilities may view these mechanisms as less risky than MRPs. Regulators and non-utility stakeholders may also see MRPs as easier to manipulate by utilities in terms of shifting excessive risk to ratepayers. Other countries have also been more supportive of MRPs for the energy sector (Lowry et al., 2017). The Ontario Energy Board (OEB), for example, supports MRPs because they avoid annual rate cases, increase regulatory efficiency, and provide utilities stronger incentives to achieve higher productivity. Unlike some U.S. MRPs, the OEB emphasizes good incentives for cost efficiency. According to the OEB, MRPs also require a sophisticated performance monitoring and reporting process. The OEB makes available to the public a scorecard that measures electric-distributor performance in four areas: customer focus, operational effectiveness, public policy responsiveness, and financial performance. One study (Sappington and Weisman, 2016) discusses different reasons for the lack of general support for MRPs in the U.S. electric industry relative to the telecommunications industry: (1) more competition in the telecommunications sector than in electric transmission and distribution; (2) utilities are more receptive to MRPs when they expect future changes in total factor productivity to exceed historical levels (which happened in the telecommunications sector); (3) fewer discretionary services in the electric sector than in the telecommunications industry; (4) in telecommunications, the regulatory bargain was that companies could institute price caps for basic local telephone service in exchange for little regulatory oversight of discretionary services; (5) deep concern in the electric sector over inadequate reliability; and (6) the recent emphasis in the electric sector on conservation and the environment. On the last point, MRPs may encourage a utility to sell more of its product and thus conflict with other publicpolicy goals. Another possible reason for the greater interest in MRPs for the telecommunications industry is the nature of costs in the telecommunications industry compared to the electric industry. In the latter industry, costs tend to increase, and are lumpier and more capital intensive. From the utility perspective, other available alternatives for facilitating recovery of capital costs, like construction work in progress (CWIP) and cost-recovery riders for capital projects, may be preferable to MRPs (Lowry, 2007).
5. Three major challenges for regulators 5.1. Information asymmetry The classic problem for regulators is that they observe only a utility's performance, not the effect of management effort on cost, service quality, and other outcomes affecting customer welfare. This means, among other things, that regulators lack the ability to determine the minimum level of costs compatible with a utility operating efficiently (Joskow, 2014). Because of this limitation, if given the chance, utilities have an incentive to engage in strategic behavior producing a zero-sum game where they benefit from higher profits or other managerial goals at the expense of their customers. Utilities inherently have better information that motivates them to overestimate the cost of operating efficiently: The higher the allowed costs the less risk there would be for the utility that unanticipated additional expenditures would result in the utility earning a return on capital below its authorized return. Information asymmetry is analogous to what economists call the “market for lemons” in which the party with better information will leverage its favorable position to its advantage (Akerlof, 1970). For utility ratemaking, the inference is that any outcome would be favorable to the utility and harmful to its ratepayers. When a utility files a cost forecast, how does the regulator know whether it reflects prudent management? The analyst or auditor can evaluate the forecast applying state-of-the-art techniques, but what remains unknown is whether the costs mirror a prudent utility. The utility knows that information about its realized costs is relevant for renegotiating new rates. This will affect its behavior ex ante; it may try to convince the regulator it is a high-cost utility so that it can continue to earn above-normal profits subsequent to the next general rate case. Information asymmetry has two important implications. The first is that utilities can misrepresent their performance to regulators. The second is that regulators need to exercise caution in interpreting a utility's actual performance. Regulators could wrongly penalize utilities for prudent actions because their performance appears subpar. Problematic on the opposite end of the spectrum, utilities could recover all of their costs even when they acted imprudently. Either of these outcomes is antithetical to the public interest. They can happen when regulators narrow their focus to just outcomes, to the exclusion of other information that could convey a more accurate picture of a utility's managerial competence. Repeated interaction between the utility and the regulators can mitigate information asymmetry. The regulator will inevitably learn more about the utility as they interact over time. By observing a utility's realized costs ex post, the regulator can exploit that information to reset the prices that the utility receives (commonly known by industry observers as a “ratchet”). 5.2. Evaluating utility forecasts As previously mentioned, a serious challenge with some multiyear rate plans is trying to derive reasonably accurate forecasts over a threeor five-year period. Even though the utility has the burden of showing that its forecasts are reasonably accurate, how can the regulator verify this? Are forecasts accurate enough for setting rates at a just and reasonable level? The uncertainty of forecasting costs and sales gives theoretical support for regulators to consider a range of possible future forecasts, rather than focusing only on the most probable future state (i.e., the “best guess” forecast). In setting rates, however, regulators have no choice but to select a single forecast, knowing with almost absolute certainty that it will contain a margin of error. Forecasts require extra time, as well as special skills, by the regulatory-agency staff and other parties to evaluate them, in addition to
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increasing the complexity of rate cases. Poor forecasts can lead to extreme utility earnings, either on the high side or the low side. Sources of distorted forecasts include (1) the propensity of utilities to overstate costs and understate revenues under present rates; (2) inferior forecasting capability; and (3) the inherent difficulty in forecasting certain costs or sales, especially for a multiyear period. Poor forecasts can therefore result from ignorance, bias, or both. Forecasting has become more complex because of the rapid changes occurring in the public utility industries. As an information-asymmetry problem, how does a regulator know that the utility's forecasts are reasonable and objective? One approach to eliminating forecasting bias comes from the United Kingdom. The country's distribution utilities have a choice of different plans that have dissimilar combinations of revenue requirements and earnings-sharing arrangements. A utility can opt for a plan that has a high revenue requirement for which it retains a low share of the cost savings; or a plan that has a lower revenue requirement for which the utility keeps a higher share of the cost savings. The utility would tend to select the option that reveals its own unbiased estimate of future costs, thereby mitigating the probability of over-forecasting its costs (Brown et al., 2014). Forecasting problems call into question the use of MRPs that require multiyear forecasts. When regulators are unable to determine whether a utility's revenue-requirement forecasts reflect prudent management and are unbiased, they should deliberate whether the MRP would be beneficial. They should seriously consider, as an alternative, indices that preclude the need to forecast costs and other items beyond the first year of an MRP. Indexes are more defensible for O&M cost than for capital costs, which are lumpy in nature and vary widely across utilities, depending on the age of existing capital assets, demand growth and the social obligations of utilities to comply with public policy (Brown et al., 2014; and Lowry et al., 2017).
6. MRP outcomes A sound MRP accounts for the concerns discussed here and promotes the public interest. Although economic and political factors in a given jurisdiction are pertinent factors, this section focuses on design features, both primary and secondary as discussed earlier, and their ability to foster predefined regulatory objectives.9 6.1. Desirable outcomes Following is a list of desirable outcomes that regulators should consider in the design of MRPs: 1. Long-term cost and non-cost benefits to ratepayers from efficient utility performance; 2. A financially healthy utility; 3. Improved utility cost efficiency, which may require an attrition allowance in the form of indices delinked from a utility's actual cost; 4. Lower costs for capital projects because of more certain and prompt cost recovery by the utility along with adequate regulatory oversight; 5. Consolidation of different cost-recovery mechanisms under an MRP and elimination of dubious cost tracking mechanisms; 6. Profit-sharing between utility shareholders and ratepayers; 7. Flexibility in setting prices, with a price floor and ceiling; and 8. Timely benefits to ratepayers from enhanced utility efficiency. Achieving these outcomes coincides with the concept of just and reasonable rates, defined earlier. They balance incentives for utility price and cost efficiency with its financial health, achieving the overall objective of enhancing long-term consumer welfare. The question for regulators is whether MRPs can achieve these outcomes and do so more effectively than other ratemaking options.
5.3. Determining the optimal time period
6.2. Discussion on cost trackers, earnings-sharing and flexible rates
Under an MRP, major factors affecting a utility's incentive to control costs include the length of regulatory lag, the “ratchet effect”, the threat of prudence reviews,6 and ex-post profit sharing.7 Especially when the utility under MRP overperforms against the target, ratepayers eventually benefit at the next rate review. A negative effect from frequent rate cases is that they tend to diminish the incentive of utilities to control costs, since the associated benefits are more quickly passed on to ratepayers. A recent study provided empirical evidence to support this position (Lowry et al., 2017).8 U.S. regulators have generally (though not always) been willing to allow utilities to earn higher returns than their cost of capital when these returns derive from cost savings beyond the benchmark (e.g., forecast O&M costs or price index), knowing that the next “ratchet” will allocate these benefits back to ratepayers. Under traditional U.S. ratemaking, the strengthening of incentives through regulatory lag is primarily by design and typically regulators set the authorized rate of return above the cost of capital (Beecher and Kihm, 2016).
Cost trackers or riders have the following potential problems: (1) Reduction of management incentives from mitigating regulatory lag and (2) uneven incentives across utility functions, likely leading to lessthan-optimal overall utility performance and the possibility of inadequate regulatory oversight and auditing of costs (Costello, 2009). Examples of cost trackers are fuel adjustment clauses, purchased gas adjustment clauses, riders for recovery of energy efficiency and environmental abatement costs, property taxes and bad debt. Many of the new cost trackers fail the “extraordinary circumstances” test. Whether these “marginal” cost trackers are in the public interest is hard to say when evaluated against the sphere of regulatory objectives. One concern is that, although they unequivocally benefit utilities and their shareholders, it is less clear how they benefit utility ratepayers. Cost trackers can improve a utility's cash-flow situation and reduce the number of rate cases, but they also can diminish a utility's incentive to efficiently manage its costs. According to some economic experts, a pure price-cap plan (which is a form of MRP) without any earnings-sharing is likely to be sub-optimal given asymmetrical information and uncertainty about future cost-efficiency opportunities. The argument is that prices would have to be set too high to satisfy the regulated firm's financial constraints and “too much rent will be left on the table for the firm” (Schmalensee, 1989; and Lyon, 1996). Critics of earnings-sharing have pointed to its less robust incentives for utility cost efficiency, lower rate stability and predictability, and
6 Costs that were approved during the general rate cases may be subject to expost review. 7 Staying power requires (a) avoidance of unworkable plan outcomes through a sharing mechanism to temper extremely high or low achieved rate of return and (b) up-front commitments by the regulator and non-utility stakeholders. 8 Specifically, the study found that for a utility with normal operating efficiency, long-run cost performance on average improves 0.51 percent more rapidly each year in an MRP with a five-year term and no earnings sharing than it does under traditional regulation with rate cases every three years. This means that the cost will be about 5 percent lower after 10 years under the MRP. For a utility with an annual revenue requirement of $1 billion, this would be an annual cost saving of $50 million in real terms.
9 Ontario has sought a superior ratemaking mechanism by emphasizing continuous efforts to develop a mechanism compatible with its economic and political environment.
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Table 1 MRP design considerations and recommendations. Component
Design Issue
Recommendation
Initial revenue requirements
What initial-period (test-year) costs should form the basis for subsequent ratemaking?
Base-rate changes
What should be the magnitude of allowable annual rate changes? What factors should determine the allowable changes?
Duration of plan
How long should an MRP operate before the filing of a general rate case?
Plan suspension (off-ramps)
What conditions should exist to suspend or terminate the operation of the MRP prior to the next scheduled rate case?
Earnings sharing
Should annual rates be adjusted to account for actual utility earnings outside of a predetermined range? What should be the criteria for making such adjustments?
True-ups and deferrals
Should rates be adjusted to account for actual costs that depart substantially from expected levels as the beginning of the MRP's cycle?
Revenue decoupling
Should rates be adjusted for actual sales deviating from some baseline level?
Capital cost recovery
What mechanism should utilities use to recover their capital costs?
Cost trackers
What costs should utilities be allowed to recover outside the internal operation of the MRP plan?
Performance review
What non-cost functional areas should be subject to regulatory review? What actions should regulators take when performance is “abnormal”?
Stay-out period
Should utilities be able to reopen a rate case when unexpected conditions “significantly” affect their earnings? Should other stakeholders request a reopening when unexpected conditions cause a utility earnings to be “unreasonably” high?
Stretch factor for efficiency gains
Should an MRP include a higher offset to account for the expectation that a utility would achieve higher productivity or cost efficiency than historical levels because of stronger incentives?
Initial revenue requirements should derive from either an adjusted historical test year or future test year. Whatever test year a regulator uses under traditional ratemaking can apply to an MRP. Historical and future test years each have advantages and disadvantages (the latter requires particular skills). Base-rate changes should deploy a hybrid approach, with indexing for operation and maintenance costs and forecasting for capital costs. Multiyear forecasts are susceptible to acute information asymmetry and pose special challenges for regulators. Indexes may provide incentives for operating cost control but are infeasible for capital projects that are “lumpy,” with highly variable year-to-year expenditures The duration of the plan should initially be set for three years, with a possible extension to five years. The duration can extend to five years if there are no serious earnings extremes. A shorter duration weakens cost incentives while a longer duration makes more likely “abnormal” earnings. Any conditions for plan suspension (off-ramps) should be clearly specified up front. A well-structured MRP − e.g., one that balances shareholder and ratepayer interests − along with utility compliance should avoid the need to suspend a plan. Re-litigation could diminish the effectiveness of the MRP in addition to increasing the cost of the regulatory process for all parties. Earnings sharing could mitigate earnings extremes that could have negative political as well as economic implications. It can, however, weaken a utility's incentives for cost efficiency and cause gaming by a utility. If used, earnings sharing should include symmetrical sharing of the return on equity (ROE) outside the dead band; the regulator needs to approve specifics, such as the width of the dead band, the sharing ratios for different actual ROE, and the post-rate adjustment ROE target. Earnings sharing allows ratepayers to benefit sooner from exceptional utility cost performance, which is why some analysts consider it an optimal regime These adjustments should occur only under certain conditions, namely (1) large unexpected costs beyond a utility's control, (2) unexpected reduction or elimination of a major cost item, or (3) capital-cost recovery on an interim basis deviating substantially from actual costs. Earnings sharing can have the same purpose in protecting ratepayers from excessive utility profits; it would expand the concept of line item true-ups to the entire cost of service and involve one annual compliance filing. Decoupling should be optional and included as a core component only if deemed necessary by regulators to address energy efficiency or distributed energy resources. This mechanism stabilizes a utility's revenues and earnings, but it also tends to shift risk from shareholders to ratepayers when a utility's sales fall below expectations. Recovery via a tracker should occur only when combined with a a thorough regulatory review of capital projects ex-ante and ex-post, and an annual regulatory review of actual capital costs and project status. It is infeasible to recover the costs from large-scale capital projects through an index component of an MRP. Quicker and more certain recovery of prudent costs reduces a utility's risk; regulatory vigilance and monitoring are therefore essential. Trackers, other than for purchased natural gas or fuel, are hard to justify. Cost trackers tend to weaken utility incentives for controlling various costs and reduce regulatory oversight, and always allow more prompt cost recovery by the utility, reducing its risk. The utility should operate under a system of rewards and penalties that are used when performance deviates from standard (“targeted”) levels for non-cost functional areas. Regulators should also require annual utility reporting of performance for review and possible further inquiry. Even in the absence of an MRP, subjecting utilities to non-cost standards, and taking appropriate action as needed, is desirable regulatory practice. The default should be for the utility to not file another rate case until the end of the duration of the approved plan. Exceptions should occur only under extreme circumstances articulated upfront (such as the utility earning an extremely high or low return for two consecutive years). Reopening a case signals to a utility that it can petition for a rate increase when things are not going well from its perspective, undermining efficiency incentives. Experience has shown that MRPs operate better without re-openers. Adjustments for expected efficiency gains should be optional and limited to utilities deemed by regulators as poor performers in the past or those expected to make substantial efficiency gains due to the incentives provided under an MRP. There may be better ways to motivate utility efficiency and allocate benefits to ratepayers in a reasonable timeframe.
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Table 1 (continued) Component
Design Issue
Recommendation
Ratepayer refunds
Should ratepayers receive a refund when actual capital and other major costs are below those embedded in the MRP calculations?
Pricing flexibility
Should utilities be allowed to offer a range of prices to individual ratepayers under certain conditions?
Efficiency carryover
Should utilities be able to benefit from cost-efficiency gains achieved in the past beyond the next general rate case (that is, mitigate the “ratchet effect”)?
The default should be no refunds, with exceptions only under extreme or unusual circumstances generally articulated upfront − e.g., costs recovered from ratepayers for a canceled capital project the regulator deemed imprudent ex post. Refunds are supportable only when evidence ex post shows that a utility acted imprudently or grossly over-forecast specific costs. Flexibility should be optional with predetermined price floors and ceilings, and other conditions. Pricing flexibility is uncommon in MRPS, but has potential to improve allocative efficiency by preventing uneconomic bypass and being more responsive to competitive conditions. Price floors and ceilings could result in more stable and predictable rates over time, and avoid “rate shock." A carryover mechanism to mitigate the “ratchet effect” should be optional and requires careful regulatory review. A carryover may be theoretically appealing (and has some empirical support in terms of costcontrol incentives), but is challenging to implement, including the determination of appropriate benchmarks.
7. Conclusion
added administrative burden. In Alberta, for example, the MRPs contain no earnings sharing, which according to the Utilities Commission would weaken utility incentives for cost control. The commission does allow reopeners when the actual rate of return on equity deviates from the authorized level by 500 basis points or more for two consecutive years (Brown et al., 2014). Earnings-sharing could also lead to cost shifting and misreporting by utilities, and opportunistic behavior by regulators. In the U.S. telecommunications sector, for a short time, pure price-cap regulation replaced the hybrid price-cap with earnings-sharing plans that were common earlier. Instead, regulators tended to resort to the use of “stretch factors” or initial rate cuts for benefit-sharing purposes (Sappington and Weisman, 2016). Flexible rates allow a utility to charge a price to certain customers within a specified range. A regulator would normally designate a price ceiling and floor. In retaining a customer, the utility, because of competitive market conditions or for other reasons, may have to offer a special rate that falls below the standard or fully allocated cost rate. Pricing flexibility allows the utility to recover more of its fixed costs (assuming, for example, that ratepayers offered a special rate would have lowered their consumption in its absence), thereby avoiding a reshifting of those costs to remaining ratepayers. Flexible rates could come in the form of special rates to discourage certain customers, like large business or industrial customer, from bypassing the utility system. As long as the utility is not charging below its incremental cost, according to the conventional economic argument, it is not uneconomical to offer a lower rate. The customer may have service alternatives and faces unique circumstances compelling a utility to offer the customer a special rate. The customer might otherwise leave the utility service area, not expand its business, or close its business. Special treatment to an individual customer, however, represents a discriminatory action, but one that regulators can justify under certain conditions as commensurate with the public interest.
MRPs have features with potential benefits to both utilities and ratepayers. MRPs are especially appealing in a dynamic world where utilities face rising average cost or attrition of a utility's earnings over time. This condition inevitably leads to utilities frequently filing rate cases, which impose high costs to both regulators and utilities. Either utilities or their regulators can take the initiative in proposing an MRP. The design considerations provided in Table 1 can provide guidance. It includes add-on mechanisms that regulators have either approved or required across jurisdictions in the U.S. While not the core parts of MRPs, they have elicited lively debate and are particularly major factors in the acceptability and sustainability of MRPs in a politically charged environment. Well-structured MRPs can ultimately pay dividends to utilities, their ratepayers, and society at large. Poorly structured ones, evident by the shifting of risks to utility ratepayers and the distribution of efficiency savings only to utility shareholders, are not consistent with the public interest goals of regulation. So far in the U.S., proponents have been unsuccessful in convincing regulators that MRPs are superior to traditional ratemaking in setting prices for energy utilities. MRPs could be implemented in an evolutionary process. One set of mechanisms can be tried, its performance assessed, additional data and reporting requirements identified, and refined mechanisms developed and applied. Perhaps this approach represents the most feasible course of action to expand the use of MRPs for U.S. energy utilities. References Akerlof, George A., 1970. The market for ‘lemons’: quality uncertainty and the market mechanism. Q. J. Econ. 84 (No. 3), 488–500 August. Averch, Harvey, Johnson, Leland L., 1962. Behavior of the firm under regulatory constraint. Am. Econ. Rev. 52 (December), 1052–1069. Beecher, Janice A., Kihm, Steven G., 2016. Risk Principles For Public Utility Regulators. Michigan State University Press, East Lansing, MI. Bonbright, James C., et al., 1988. Principles of Public Utility Rates, second ed. the first ed. Public Utilities Reports, Inc. authored solely by Bonbright, was published in 1961. Borenstein, Severin, Bushnell, James, September 2014. The U.S. Electricity Industry after 20 Years of Restructuring, vol. 252 EI@ Hass WP. Brown, Lorenzo, et al., 1991. Toward improved and practical incentive regulation. J. Regul. Econ. 3, 323–338. Brown, Toby, et al., May 20, 2014. Incentive-Based Ratemaking: Recommendations to the Hawaiian Electric Companies. Prepared for the Hawaiian Electric Companies. Costello, Ken, October 2013a. Future Test Years: Evidence from State Utility Commissions. NRRI 13-10. Costello, Ken, July 2013b. Future Test Years: Challenges Posed for State Utility Commissions. NRRI 13-08. Costello, Ken, September 2009. How Should Regulators View Cost Trackers? NRRI 09-13. Harunuzzaman, Mohammad, et al., March 1994. Regulatory Practices and Innovative Generation Technologies: Problems and New Rate-Making Approaches. National
6.3. Recommendations and rationales Table 1 summarizes MRP design considerations with recommendations. It reflects the end product of this article, which is to identify attributes of a good MR. One can with good reason contest these recommendations. The purpose here is to elevate the dialogue on MRPs between regulators, utilities, and other stakeholders. With surety, the participants of the regulatory process will disagree on the weights given to individual outcomes. They will also have different views on what constitutes “desirable outcomes”. The job of the regulator is to sift the evidence for reaching a decision that best advances the public interest. 7
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K.W. Costello Regulatory Research Institute Report 94-05. Hauge, Janice A., Sappington, David E.M., 2010. Pricing in network industries. In: Baldwin, Robert, Cave, Martin, Lodge, Martin (Eds.), The Oxford Handbook of Regulation. Oxford University Press, Oxford, UK, pp. 462–499. Hesmondhalgh, Serena, et al., 2012. Approaches to Setting Electric Distribution Reliability Standards and Outcomes. The Brattle Group, January. Joskow, Paul L., 2014. Incentive regulation in theory and practice: electricity distribution and transmission networks. In: Rose, Nancy L. (Ed.), Economic Regulation and what Have We Learned? University of Chicago Press, Chicago, Il, pp. 291–344. Joskow, Paul L., October 1974. Inflation and environmental concern: structural changes in the process of public utility regulation. J. Law Econ. 17, 291–327. Kahn, Alfred E., 1971. Economics of Regulation, vol. 1 John Wiley & Sons, New York. Larkin & Associates, PLLC, May 2012. Increasing Use of Surcharges on Consumer Utility Bills. Prepared for the American Association of Retired Persons. Lowry, Mark Newton, et al., July 2017. State Performance-Based Regulation Using Multiyear Rate Plans for U.S. Electric Utilities. Report prepared for the Ernest Orlando Lawrence Berkeley National Laboratory. Lowry, Mark Newton, Woolf, Tim, January 2016. Performance-Based Regulation in a High Distributed Energy Resources Future. LBL-1004130.
Lowry, Mark Newton, 2007. Alternative Regulation for Infrastructure Cost Recovery, vol. 9 Prepared for the Edison Electric Institute, January. Lyon, Thomas P., May 1996. A model of sliding-scale regulation. J. Regul. Econ. 9 (Issue 3), 227–247. Makholm, Jeff D., November 2018. The rise and decline of the X factor in performancebased electricity regulation. Electr. J. 31 (Issue 9), 38–43. Posner, Richard A., 1969. Natural monopoly and its regulation. Stanford Law Rev. 21, 548–643. Sappington, David E.M., Weisman, Dennis L., April 2016. The disparate adoption of price cap regulation in the U.S. Telecommunications and electricity sectors. J. Regul. Econ. 49 (Issue 2), 250–264. Schmalensee, Richard, Autumn 1989. Good regulatory regimes. Rand J. Regul. 20 (No. 3), 417–436. Washington Utilities and Transportation Commission, June 25, 2013. In the Matter of the Petition of Puget Sound Energy, Inc., and Northwest Energy Coalition for an Order Authorizing PSE to Implement Electric and Natural Gas Decoupling Mechanisms and to Record Accounting Entities Associated with the Mechanisms, Final Order Authorizing Rates. Dockets UE-130137 and UG-130138.
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Utilities Policy journal homepage: www.elsevier.com/locate/jup
Design considerations for multiyear Public Utility rate plans Kenneth W. Costello
1
T
ABSTRACT
Regulatory experts generally agree that good regulation leads to high economic efficiency, fairness, and moderate regulatory costs. These three features have characterized good regulation going back to the beginning of the previous century. This paper will try to show that wellstructured and executed multiyear rate plans (MRPs) can be more compatible with the public interest, compared with the traditional rate-of return approach to setting utility rates. Substandard MRPs, however, can produce worse outcomes for utility customers.
1. Criticisms of traditional ratemaking in the United States Rate-of-return ratemaking (hereinafter “traditional ratemaking”) refers to the application of cost-of-service principles for setting rates that determine the utility's authorized rate of return. Features include: (1) rates remain fixed until the regulator approves new rates following a general rate case; (2) the utility has a reasonable opportunity to earn its authorized rate of return; (3) the balancing of utility shareholder and ratepayer interests is an overriding goal; (4) the selected test year matches revenues with costs over the first year of new rates; (5) the utility's actual rate of return between rate cases deviates from the authorized return when actual sales or costs differ from their test-year levels; and (6) regulatory lag can either benefit or harm utilities, depending on whether average cost is decreasing or increasing (Kahn, 1971). Traditional ratemaking has been criticized over the years based on one or more of the following arguments made: it fails to update rates for changes in costs beyond the test period, meaning that during an inflationary-cost period, utilities would tend to file frequent rate cases or that during a deflationary period earn excessive profits; it can give utilities weak incentive to innovate because of an imbalanced risk-reward relationship; it can create excessive delay for utilities in recovering their costs for new capital projects; it provides utilities with weak incentives to control their costs due to frequent rate cases (less lag); it can create rate shock under inflationary and other conditions, leading to political problems for regulators and a disruptive effect on consumption; it places high demands on regulatory staff and utility resources, especially when rate cases are also complex; it motivates utilities to try to increase both sales and rate base when alternative actions would be in the public interest; it allows utilities to decide the timing of rate cases, thereby manipulating the regulatory process to
their advantage (for example, not filing a rate case when profits are far above the authorized level. A related criticism originates with the Averch-Johnson (A-J) effect, which says that a utility would use excessive capital input relative to other inputs such as labor, fuel, and materials. This outcome assumes that a utility faces a binding rate-of-return constraint on its rate base and its allowed rate of return exceeds its actual cost of capital (Averch and . Johnson, 1962). The transformation of the electric industry, driven by major developments in technology, public policy objectives emphasizing clean energy and customer activism, calls into question whether traditional ratemaking can accommodate the public interest by establishing just and reasonable rates, which have two prominent traits. First, they should reflect prudent and efficient expenditures. Second, they allow the utility a reasonable opportunity to receive sufficient revenues to attract new capital and avoid serious financial problems not caused by incompetent management. In the 1990s, when the U.S. electric industry went through major restructuring, many experts believed that traditional ratemaking would come to an end (Borenstein and Bushnell, 2014). Some of this sprung from the experience in the telecommunications industry and the electric industry's concern over whether its earnings under traditional ratemaking would fall short of financial viability. One idea was to implement price caps or other more flexible ratemaking mechanisms to replace it. What actually transpired was that state utility regulators were unwilling to give up traditional ratemaking, although they were open to modifications. A lesson learned is that supporters of new ratemaking mechanisms, such as multiyear rate plans (MRPs), must make a compelling case for why regulators should reject traditional ratemaking, which has prevailed from almost the beginning. For many regulators, traditional ratemaking has performed admirably in protecting consumer interests.
E-mail address: [email protected]. Regulatory Economist/Independent Consultant. The funding for this article came from the Center for Business and Regulation (CBR), University of Illinois Springfield. The author presented an earlier draft at the Conference on Frameworks for Regulation of Public Utilities in the 21st Century: Part 2, sponsored by CBR, September 28, 2017. 1
https://doi.org/10.1016/j.jup.2019.05.009 Received 25 January 2019; Received in revised form 13 May 2019; Accepted 13 May 2019 Available online 25 May 2019 0957-1787/ © 2019 Elsevier Ltd. All rights reserved.
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The burden seems to fall on those to show that an alternative approach is superior.
rate cases. Although in some instances regulators encountered initial difficulties, including the broad one of evaluating the reasonableness of a utility's forecasts, they were able to eventually overcome them (Costello, 2013 (a)). But as pointed out later, an FTY confront regulators with various challenges, an important one being whether the forecasted costs reflect a prudent utility. The second part of MRPs involves calculating the changes in base rates or revenues outside the test period. This is where MRPs are distinguished from traditional ratemaking. A utility can apply detailed cost forecasts or escalation factors attached to the base rate or revenue. An escalation factor acts as an attrition adjustment to rates. As discussed later, this gives utilities a stronger incentive to control their costs and is a common feature of MRPs outside the U.S. The Alberta Utilities Commission went from using detailed cost forecasts for each year of the MRP to using indices to escalate rates, mainly for this reason. Alternatively, rate changes can be a function of a predetermined amount forecast during the previous rate case. California went in the direction of going from an index approach to using 3-year forecasts of revenue requirements (Brown et al., 2014). Forecasts can derive from detailed cost of service analysis, a utility's budget, or a combination of both. Forecasting a utility's costs three to five years out poses special challenges for regulators to determine their accuracy (discussed in more detail later). The third part is the duration of MRPs. With MRPs predetermining the timing of general rate cases, the length of regulatory lag becomes known to the utility and other stakeholders. The longer is the duration the more incentive a utility has to control its costs (Posner, 1969). General rate cases would also be less frequent. As a downside, a longer duration would increase the likelihood that a utility's rate of return will fluctuate farther from the regulator's authorized level. The optimal duration therefore becomes case-specific, with the regulator having to consider the trade-off between cost efficiency and stable earnings.
2. Basic information about MRPs 2.1. Primary features An MRP is a comprehensive regulatory pricing mechanism that allows base rates to change outside of a general rate case and have the following features: 1. Predetermination of rate changes either in dollars or according to a formula beyond the test period (for example, three to five years); 2. A process for setting a utility's rates and revenue requirements for longer than a single 12-month period; 3. Fixed frequency of general rate cases (i.e., regularized regulatory lag); 4. Forward-looking that commits the regulator for a multiyear period, giving utilities greater certainty of cost recovery for new investments; 5. Earnings attrition relief between rate cases beyond the test period based on a formula, index, or multiyear forecasts2; and 6. Typically, incentives on utility functional areas (e.g., reliability, customer service) whose performance may suffer from stronger incentives for cost reductions (Hauge and Sappington, 2010). Some MRPs specify allowable revenue changes, which have a different effect on utility behavior than specifying allowable rate changes. The former specification would give utilities less disincentive to promote demand management and conservation, which has become a major objective for many state utility regulators. Concerning the second feature, one interpretation is that an MRP establishes the rates a utility can charge for each year of the plan's duration, based only on the utility's reasonable and prudent costs of service over this period. Ratemaking, as practiced today in the U.S., represents a hybrid of features of different rate mechanisms that have evolved over time. By forecasting revenue requirements out (say) to three years, an MRP is just an extension of setting rates based on a future test year. Traditional ratemaking today applies a future test year that reduces lag by accounting for expected changes in costs and attrition after the test year (Costello, 2013 (b)). Because of this distinction, MRPs give utilities different incentives to operate efficiently, invest in socially-beneficial capital projects, and perform well in other functions.
2.3. Noncore elements The noncore elements of an MRP are optional features necessary for implementation. These address political acceptability and the avoidance of “extreme” outcomes that might jeopardize the sustainability of an MRP, and may reflect the bargaining strengths of the various stakeholders. In the U.S., MRPs for utilities reflect compromises that have diminished their effectiveness in maximizing a utility's incentive for cost efficiency. This is something that is ostensibly unavoidable, especially in the electric industry where cost efficiency typically takes a back seat to other regulatory objectives. As a side note, economists sometimes forget that the main goal of regulation is not merely to promote economic efficiency, of which cost efficiency is a component: Regulation originated and developed prior to the ideas of economic efficiency and the principles of welfare economics. Most enabling legislation mandates just, reasonable and fair rates, not efficient rates per se. Throughout the history of state utility regulation, “fairness” has been a major determinant of ratemaking (Bonbright et al., 1988). MRPs can protect ratepayers from events that were not anticipated when the regulator approved the plan. Such events can include poor performance in service quality and operations, abnormally high rates of return, exceptionally high capital costs, and imprudent utility costs. “Protection” mechanisms include refunds for an “excessive” high rate of return, caps on recoverable capital costs, monitoring of utility performance, and detailed audits to determine appropriate cost recovery.4 One caveat is that if carried to an extreme, protecting ratepayers from
2.2. Core elements MRPs have three structural parts. The first is the starting base price or revenue, which derives from test-year cost and sales statistics.3 Most plans use a future test year (FTY). One general finding from a 2013 survey was that most state utility regulators using an FTY have had an overall positive experience, with no intention to discard an FTY in later 2 Attrition refers to the tendency for a utility's rate of return or profits to fall since the last rate case. Attrition exists when revenue growth falls short of revenue-requirement increases, eroding the utility's rate of return over time in the absence of a rate change. On the opposite side of the spectrum is the term accretion, which refers to a utility “over-earning" between rate cases. In an environment where a utility's productivity is growing rapidly and inflation is low, a utility's earnings are likely to exceed between rate cases the authorized rate of return set in the last rate case. 3 A test year is an actual or hypothetical 12-month period over which a utility calculates its costs, including both operating and capital costs, and sales to determine the need for a rate change. At the core of a rate test year is the “matching principle” for achieving consistency between costs and revenues. The utility would accordingly consider jointly revenue requirements and billing determinants in setting new rates.
4 Utility cost recovery in the absence of regulatory oversight would tend to create a “moral hazard” problem that diminishes a utility's incentive to manage its costs. Detailed audits to determine prudence, however, is time-consuming, information-intensive, and highly contentious.
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unexpected outcomes could compromise a utility's actions that benefit ratepayers in the long run. As argued by some analysts, a utility earning a higher profit because of exceptional cost-efficiency attributed to superb management should be able retain those benefits for a reasonable minimum time before transferring them to ratepayers. One element common to MRPs is performance metrics for non-cost utility functions, such as reliability and customer service. A concern is that utilities under an MRP may jeopardize their service quality by controlling costs to increase their rate of return (Hauge and Sappington, 2010). Some MRPs have performance standards or incentives for service quality and reliability (Hesmondhalgh et al., 2012.) When the utility receives additional revenues from higher performance, an obvious question is what share of the benefits should transfer to ratepayers. These benefits should at least cover the additional revenues that ratepayers have to pay the utility, or else ratepayers are worse off.
But not everyone shares this optimism. One observer opines that he does “not envisage any near-term expansion of that particular form of rate control [MRPs] for the North American electricity industry.” One reason is the trend toward partial or targeted-based incentive regulation. He also argued that the changes occurring in the electric industry will make it difficult for any multiyear plan to handle the dynamics of future utility investment costs (Makholm, 2018). As a rebuttal to his first reason, partial and MRPs can coexist since they have different objectives. In fact, as discussed later, partial incentive mechanisms for such functions as customer and service reliability can complement an MRP. The second point has more merit, as multiyear plans have struggled with the treatment of capital expenditures. The basic challenge for regulators is to balance the trade-off between giving a utility a strong incentive to control its capital costs and a reasonable opportunity to achieve a rate of return that is within the authorized range.
3. Major arguments for multiyear rate plans (MRPs)
4. Theoretical issues
Support for MRPs derives from four sources. First, from the perspective of utilities new market and operating conditions, namely, rising average cost and the slowdown of demand growth, argues for a ratemaking mechanism to address earnings erosion beyond the test period. Under traditional ratemaking, no matter how much the actual utility's costs and revenues deviate from their test-year levels, base rates remain fixed until the regulator approves new ones in a future rate case. The exception is when a regulator allows for interim rate relief under abnormal and unexpected conditions that jeopardize a utility's financial well-being. The fact that most MRPs for U.S. electric utilities involve vertically integrated utilities suggests that one of their main purposes is to expedite the recovery of capital costs for generation (Lowry et al., 2017). Second, instead of a utility filing a new general rate case due to earnings attrition (associated with revenues falling below costs over time) under traditional ratemaking, an MRP may forecast future conditions over a multiyear period or use cost indices to adjust rates over the plan's duration within the confines of a single rate case. This means that a utility can recover operating costs, normally recoverable only after filing a general rate case, prior to a future rate case. Third, given the resource constraints of many state utility regulators, an MRP can lower regulatory costs and enhance regulatory efficiency by conducting fewer cases. Major rate cases absorb a substantial amount of staff resources and time, jeopardizing the regulatory agency's ability to address other issues that in recent years have become more complex. Fourth, well-structured MRPs also have the potential to improve a utility's operating performance. This results from regularized regulatory lag and rate adjustments based on an index for exogenous factors. As early as the late 1960s and early 1970s utilities and other stakeholders sought for nontraditional rate mechanisms because of technological developments, new public policies, and a changing market and operating environment (Joskow, 1974). Beginning in the 1980s, theoretical research on incentive regulation evolved to address directly asymmetric information problems (discussed later) and related contracting constraints, regulatory credibility issues, dynamic considerations, regulatory capture, and other issues that analysts have been grappling with for decades in the absence of a comprehensive theoretical framework to guide them. (Joskow, 2014). These mechanisms reflect a departure, although largely marginal ones, from traditional ratemaking practices (Brown et al., 1991; and Harunuzzaman et al., 1994). The main objective of this article is to present the features of an MRP that utilities and regulators may want to consider if they are to advance the public interest. While the question of whether utilities should operate under an MRP only under exceptional conditions and circumstances may have some merit, the proposal here is that MRP has potential to gain wider acceptance in utility ratemaking.
4.1. The downsides of MRPs Utility regulators must set reasonable rates that allow a utility making prudent decisions to operate successfully, maintain its financial integrity, attract capital, and compensate investors in line with actual risks.5 Regulation can be undermined by ideology, ignorance, and inertia. Basing ratemaking policies on political leanings, inadequate information, and past conditions that no longer exist may lead to failure, regardless of the ratemaking method. Different versions and variations of MRPs have different outcomes depending on their structure and implementation. A poorly designed MRP is unlikely to improve outcomes compared with traditional ratemaking, and it could actually make matters worse, especially for utility ratepayers. Specifically, a poorly designed MRP can: (1) create perverse incentives whereby societal benefits become negative; (2) impose undue restrictions on utilities preventing them from pricing flexibly or managing their operational activities; (3) excessively allocate the benefits of utility efficiencies to either shareholders or ratepayers without recognizing tradeoffs; or (4) omit as its chief objective the long-term welfare of utility customers, which aligns with the widely-held public-interest perspective of regulation. In other words, like other ratemaking mechanisms, MRPs can produce inferior results to traditional ratemaking. While the concept of multiyear ratemaking has merit, the details determine how it compares to other ratemaking methods. For example, formula-rate plans prevent utilities from earning extremely high or low profits between formal rate reviews. They adjust base rates between general rate cases, which in that sense falls under the meaning of an MRP, on the basis of a utility's actual costs. Some analysts consider formula rate plans as a comprehensive cost tracker, placing them outside the category of MRPs (Lowry and Woolf, 2016). 4.2. The U.S. Experience U.S. utility regulators were receptive to MRPs in the form of price caps for the telecommunications industry. The industry took the initiative in proposing them and later market forces replaced them in setting prices for different services. Regulators and legislatures accepted price caps in the telecommunications industry largely because of growing problems with traditional ratemaking. These problems harmed different interest groups in addition to distorting and discouraging emerging competitive forces in the industry. Regulators allowed Regional Bell Operating Companies to enter non-regulated lines of 5 The U.S. Supreme Court outlined these conditions in its order for FPC v. Hope Natural Gas Co., 320 U.S. 591, 605 (1944).
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businesses as technology evolved rapidly. In response, they were searching for a more streamlined and effective method of regulation, which they found in price caps (Sappington and Weisman, 2016). A small minority of U.S. energy utilities operate under MRPs. The empirical evidence thus far has been generally favorable (Lowry et al., 2017). Regulators’ rejection or non-consideration of an MRP may be more of a rational response than inertia favoring the status quo (Sappington and Weisman, 2016). The lack of wide acceptance of MRPs may reflect the reluctance of risk-averse regulators to accept a mechanism with uncertain outcomes that could make matters worse, which is conceivable with poorly structured and implemented MRPs. Perceived problems with MRPs include inaccurate or biased multiyear forecasts that favor the utility, premature utility recovery of costs for capital projects, and the compromise of service quality and other noncost performance areas. Consumer groups are generally opposed to MRPs for these and other reasons (Larkin & Associates, PLLC, 2012). Regulators and utilities may prefer more incremental changes to address attrition, such as revenue decoupling and expanded use of cost trackers (Washington Utilities and Transportation Commission, 2013). Under revenue decoupling, the utility adjusts its rates between rate cases for sales deviating from some baseline level, illustrated by a periodic adjustment of rates for a gap between actual sales and test-year sales per customer. Cost trackers allow a utility to recover costs from ratepayers that vary from those costs embedded in rates established at the last general rate case (Costello, 2009). Utilities may view these mechanisms as less risky than MRPs. Regulators and non-utility stakeholders may also see MRPs as easier to manipulate by utilities in terms of shifting excessive risk to ratepayers. Other countries have also been more supportive of MRPs for the energy sector (Lowry et al., 2017). The Ontario Energy Board (OEB), for example, supports MRPs because they avoid annual rate cases, increase regulatory efficiency, and provide utilities stronger incentives to achieve higher productivity. Unlike some U.S. MRPs, the OEB emphasizes good incentives for cost efficiency. According to the OEB, MRPs also require a sophisticated performance monitoring and reporting process. The OEB makes available to the public a scorecard that measures electric-distributor performance in four areas: customer focus, operational effectiveness, public policy responsiveness, and financial performance. One study (Sappington and Weisman, 2016) discusses different reasons for the lack of general support for MRPs in the U.S. electric industry relative to the telecommunications industry: (1) more competition in the telecommunications sector than in electric transmission and distribution; (2) utilities are more receptive to MRPs when they expect future changes in total factor productivity to exceed historical levels (which happened in the telecommunications sector); (3) fewer discretionary services in the electric sector than in the telecommunications industry; (4) in telecommunications, the regulatory bargain was that companies could institute price caps for basic local telephone service in exchange for little regulatory oversight of discretionary services; (5) deep concern in the electric sector over inadequate reliability; and (6) the recent emphasis in the electric sector on conservation and the environment. On the last point, MRPs may encourage a utility to sell more of its product and thus conflict with other publicpolicy goals. Another possible reason for the greater interest in MRPs for the telecommunications industry is the nature of costs in the telecommunications industry compared to the electric industry. In the latter industry, costs tend to increase, and are lumpier and more capital intensive. From the utility perspective, other available alternatives for facilitating recovery of capital costs, like construction work in progress (CWIP) and cost-recovery riders for capital projects, may be preferable to MRPs (Lowry, 2007).
5. Three major challenges for regulators 5.1. Information asymmetry The classic problem for regulators is that they observe only a utility's performance, not the effect of management effort on cost, service quality, and other outcomes affecting customer welfare. This means, among other things, that regulators lack the ability to determine the minimum level of costs compatible with a utility operating efficiently (Joskow, 2014). Because of this limitation, if given the chance, utilities have an incentive to engage in strategic behavior producing a zero-sum game where they benefit from higher profits or other managerial goals at the expense of their customers. Utilities inherently have better information that motivates them to overestimate the cost of operating efficiently: The higher the allowed costs the less risk there would be for the utility that unanticipated additional expenditures would result in the utility earning a return on capital below its authorized return. Information asymmetry is analogous to what economists call the “market for lemons” in which the party with better information will leverage its favorable position to its advantage (Akerlof, 1970). For utility ratemaking, the inference is that any outcome would be favorable to the utility and harmful to its ratepayers. When a utility files a cost forecast, how does the regulator know whether it reflects prudent management? The analyst or auditor can evaluate the forecast applying state-of-the-art techniques, but what remains unknown is whether the costs mirror a prudent utility. The utility knows that information about its realized costs is relevant for renegotiating new rates. This will affect its behavior ex ante; it may try to convince the regulator it is a high-cost utility so that it can continue to earn above-normal profits subsequent to the next general rate case. Information asymmetry has two important implications. The first is that utilities can misrepresent their performance to regulators. The second is that regulators need to exercise caution in interpreting a utility's actual performance. Regulators could wrongly penalize utilities for prudent actions because their performance appears subpar. Problematic on the opposite end of the spectrum, utilities could recover all of their costs even when they acted imprudently. Either of these outcomes is antithetical to the public interest. They can happen when regulators narrow their focus to just outcomes, to the exclusion of other information that could convey a more accurate picture of a utility's managerial competence. Repeated interaction between the utility and the regulators can mitigate information asymmetry. The regulator will inevitably learn more about the utility as they interact over time. By observing a utility's realized costs ex post, the regulator can exploit that information to reset the prices that the utility receives (commonly known by industry observers as a “ratchet”). 5.2. Evaluating utility forecasts As previously mentioned, a serious challenge with some multiyear rate plans is trying to derive reasonably accurate forecasts over a threeor five-year period. Even though the utility has the burden of showing that its forecasts are reasonably accurate, how can the regulator verify this? Are forecasts accurate enough for setting rates at a just and reasonable level? The uncertainty of forecasting costs and sales gives theoretical support for regulators to consider a range of possible future forecasts, rather than focusing only on the most probable future state (i.e., the “best guess” forecast). In setting rates, however, regulators have no choice but to select a single forecast, knowing with almost absolute certainty that it will contain a margin of error. Forecasts require extra time, as well as special skills, by the regulatory-agency staff and other parties to evaluate them, in addition to
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increasing the complexity of rate cases. Poor forecasts can lead to extreme utility earnings, either on the high side or the low side. Sources of distorted forecasts include (1) the propensity of utilities to overstate costs and understate revenues under present rates; (2) inferior forecasting capability; and (3) the inherent difficulty in forecasting certain costs or sales, especially for a multiyear period. Poor forecasts can therefore result from ignorance, bias, or both. Forecasting has become more complex because of the rapid changes occurring in the public utility industries. As an information-asymmetry problem, how does a regulator know that the utility's forecasts are reasonable and objective? One approach to eliminating forecasting bias comes from the United Kingdom. The country's distribution utilities have a choice of different plans that have dissimilar combinations of revenue requirements and earnings-sharing arrangements. A utility can opt for a plan that has a high revenue requirement for which it retains a low share of the cost savings; or a plan that has a lower revenue requirement for which the utility keeps a higher share of the cost savings. The utility would tend to select the option that reveals its own unbiased estimate of future costs, thereby mitigating the probability of over-forecasting its costs (Brown et al., 2014). Forecasting problems call into question the use of MRPs that require multiyear forecasts. When regulators are unable to determine whether a utility's revenue-requirement forecasts reflect prudent management and are unbiased, they should deliberate whether the MRP would be beneficial. They should seriously consider, as an alternative, indices that preclude the need to forecast costs and other items beyond the first year of an MRP. Indexes are more defensible for O&M cost than for capital costs, which are lumpy in nature and vary widely across utilities, depending on the age of existing capital assets, demand growth and the social obligations of utilities to comply with public policy (Brown et al., 2014; and Lowry et al., 2017).
6. MRP outcomes A sound MRP accounts for the concerns discussed here and promotes the public interest. Although economic and political factors in a given jurisdiction are pertinent factors, this section focuses on design features, both primary and secondary as discussed earlier, and their ability to foster predefined regulatory objectives.9 6.1. Desirable outcomes Following is a list of desirable outcomes that regulators should consider in the design of MRPs: 1. Long-term cost and non-cost benefits to ratepayers from efficient utility performance; 2. A financially healthy utility; 3. Improved utility cost efficiency, which may require an attrition allowance in the form of indices delinked from a utility's actual cost; 4. Lower costs for capital projects because of more certain and prompt cost recovery by the utility along with adequate regulatory oversight; 5. Consolidation of different cost-recovery mechanisms under an MRP and elimination of dubious cost tracking mechanisms; 6. Profit-sharing between utility shareholders and ratepayers; 7. Flexibility in setting prices, with a price floor and ceiling; and 8. Timely benefits to ratepayers from enhanced utility efficiency. Achieving these outcomes coincides with the concept of just and reasonable rates, defined earlier. They balance incentives for utility price and cost efficiency with its financial health, achieving the overall objective of enhancing long-term consumer welfare. The question for regulators is whether MRPs can achieve these outcomes and do so more effectively than other ratemaking options.
5.3. Determining the optimal time period
6.2. Discussion on cost trackers, earnings-sharing and flexible rates
Under an MRP, major factors affecting a utility's incentive to control costs include the length of regulatory lag, the “ratchet effect”, the threat of prudence reviews,6 and ex-post profit sharing.7 Especially when the utility under MRP overperforms against the target, ratepayers eventually benefit at the next rate review. A negative effect from frequent rate cases is that they tend to diminish the incentive of utilities to control costs, since the associated benefits are more quickly passed on to ratepayers. A recent study provided empirical evidence to support this position (Lowry et al., 2017).8 U.S. regulators have generally (though not always) been willing to allow utilities to earn higher returns than their cost of capital when these returns derive from cost savings beyond the benchmark (e.g., forecast O&M costs or price index), knowing that the next “ratchet” will allocate these benefits back to ratepayers. Under traditional U.S. ratemaking, the strengthening of incentives through regulatory lag is primarily by design and typically regulators set the authorized rate of return above the cost of capital (Beecher and Kihm, 2016).
Cost trackers or riders have the following potential problems: (1) Reduction of management incentives from mitigating regulatory lag and (2) uneven incentives across utility functions, likely leading to lessthan-optimal overall utility performance and the possibility of inadequate regulatory oversight and auditing of costs (Costello, 2009). Examples of cost trackers are fuel adjustment clauses, purchased gas adjustment clauses, riders for recovery of energy efficiency and environmental abatement costs, property taxes and bad debt. Many of the new cost trackers fail the “extraordinary circumstances” test. Whether these “marginal” cost trackers are in the public interest is hard to say when evaluated against the sphere of regulatory objectives. One concern is that, although they unequivocally benefit utilities and their shareholders, it is less clear how they benefit utility ratepayers. Cost trackers can improve a utility's cash-flow situation and reduce the number of rate cases, but they also can diminish a utility's incentive to efficiently manage its costs. According to some economic experts, a pure price-cap plan (which is a form of MRP) without any earnings-sharing is likely to be sub-optimal given asymmetrical information and uncertainty about future cost-efficiency opportunities. The argument is that prices would have to be set too high to satisfy the regulated firm's financial constraints and “too much rent will be left on the table for the firm” (Schmalensee, 1989; and Lyon, 1996). Critics of earnings-sharing have pointed to its less robust incentives for utility cost efficiency, lower rate stability and predictability, and
6 Costs that were approved during the general rate cases may be subject to expost review. 7 Staying power requires (a) avoidance of unworkable plan outcomes through a sharing mechanism to temper extremely high or low achieved rate of return and (b) up-front commitments by the regulator and non-utility stakeholders. 8 Specifically, the study found that for a utility with normal operating efficiency, long-run cost performance on average improves 0.51 percent more rapidly each year in an MRP with a five-year term and no earnings sharing than it does under traditional regulation with rate cases every three years. This means that the cost will be about 5 percent lower after 10 years under the MRP. For a utility with an annual revenue requirement of $1 billion, this would be an annual cost saving of $50 million in real terms.
9 Ontario has sought a superior ratemaking mechanism by emphasizing continuous efforts to develop a mechanism compatible with its economic and political environment.
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Table 1 MRP design considerations and recommendations. Component
Design Issue
Recommendation
Initial revenue requirements
What initial-period (test-year) costs should form the basis for subsequent ratemaking?
Base-rate changes
What should be the magnitude of allowable annual rate changes? What factors should determine the allowable changes?
Duration of plan
How long should an MRP operate before the filing of a general rate case?
Plan suspension (off-ramps)
What conditions should exist to suspend or terminate the operation of the MRP prior to the next scheduled rate case?
Earnings sharing
Should annual rates be adjusted to account for actual utility earnings outside of a predetermined range? What should be the criteria for making such adjustments?
True-ups and deferrals
Should rates be adjusted to account for actual costs that depart substantially from expected levels as the beginning of the MRP's cycle?
Revenue decoupling
Should rates be adjusted for actual sales deviating from some baseline level?
Capital cost recovery
What mechanism should utilities use to recover their capital costs?
Cost trackers
What costs should utilities be allowed to recover outside the internal operation of the MRP plan?
Performance review
What non-cost functional areas should be subject to regulatory review? What actions should regulators take when performance is “abnormal”?
Stay-out period
Should utilities be able to reopen a rate case when unexpected conditions “significantly” affect their earnings? Should other stakeholders request a reopening when unexpected conditions cause a utility earnings to be “unreasonably” high?
Stretch factor for efficiency gains
Should an MRP include a higher offset to account for the expectation that a utility would achieve higher productivity or cost efficiency than historical levels because of stronger incentives?
Initial revenue requirements should derive from either an adjusted historical test year or future test year. Whatever test year a regulator uses under traditional ratemaking can apply to an MRP. Historical and future test years each have advantages and disadvantages (the latter requires particular skills). Base-rate changes should deploy a hybrid approach, with indexing for operation and maintenance costs and forecasting for capital costs. Multiyear forecasts are susceptible to acute information asymmetry and pose special challenges for regulators. Indexes may provide incentives for operating cost control but are infeasible for capital projects that are “lumpy,” with highly variable year-to-year expenditures The duration of the plan should initially be set for three years, with a possible extension to five years. The duration can extend to five years if there are no serious earnings extremes. A shorter duration weakens cost incentives while a longer duration makes more likely “abnormal” earnings. Any conditions for plan suspension (off-ramps) should be clearly specified up front. A well-structured MRP − e.g., one that balances shareholder and ratepayer interests − along with utility compliance should avoid the need to suspend a plan. Re-litigation could diminish the effectiveness of the MRP in addition to increasing the cost of the regulatory process for all parties. Earnings sharing could mitigate earnings extremes that could have negative political as well as economic implications. It can, however, weaken a utility's incentives for cost efficiency and cause gaming by a utility. If used, earnings sharing should include symmetrical sharing of the return on equity (ROE) outside the dead band; the regulator needs to approve specifics, such as the width of the dead band, the sharing ratios for different actual ROE, and the post-rate adjustment ROE target. Earnings sharing allows ratepayers to benefit sooner from exceptional utility cost performance, which is why some analysts consider it an optimal regime These adjustments should occur only under certain conditions, namely (1) large unexpected costs beyond a utility's control, (2) unexpected reduction or elimination of a major cost item, or (3) capital-cost recovery on an interim basis deviating substantially from actual costs. Earnings sharing can have the same purpose in protecting ratepayers from excessive utility profits; it would expand the concept of line item true-ups to the entire cost of service and involve one annual compliance filing. Decoupling should be optional and included as a core component only if deemed necessary by regulators to address energy efficiency or distributed energy resources. This mechanism stabilizes a utility's revenues and earnings, but it also tends to shift risk from shareholders to ratepayers when a utility's sales fall below expectations. Recovery via a tracker should occur only when combined with a a thorough regulatory review of capital projects ex-ante and ex-post, and an annual regulatory review of actual capital costs and project status. It is infeasible to recover the costs from large-scale capital projects through an index component of an MRP. Quicker and more certain recovery of prudent costs reduces a utility's risk; regulatory vigilance and monitoring are therefore essential. Trackers, other than for purchased natural gas or fuel, are hard to justify. Cost trackers tend to weaken utility incentives for controlling various costs and reduce regulatory oversight, and always allow more prompt cost recovery by the utility, reducing its risk. The utility should operate under a system of rewards and penalties that are used when performance deviates from standard (“targeted”) levels for non-cost functional areas. Regulators should also require annual utility reporting of performance for review and possible further inquiry. Even in the absence of an MRP, subjecting utilities to non-cost standards, and taking appropriate action as needed, is desirable regulatory practice. The default should be for the utility to not file another rate case until the end of the duration of the approved plan. Exceptions should occur only under extreme circumstances articulated upfront (such as the utility earning an extremely high or low return for two consecutive years). Reopening a case signals to a utility that it can petition for a rate increase when things are not going well from its perspective, undermining efficiency incentives. Experience has shown that MRPs operate better without re-openers. Adjustments for expected efficiency gains should be optional and limited to utilities deemed by regulators as poor performers in the past or those expected to make substantial efficiency gains due to the incentives provided under an MRP. There may be better ways to motivate utility efficiency and allocate benefits to ratepayers in a reasonable timeframe.
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Table 1 (continued) Component
Design Issue
Recommendation
Ratepayer refunds
Should ratepayers receive a refund when actual capital and other major costs are below those embedded in the MRP calculations?
Pricing flexibility
Should utilities be allowed to offer a range of prices to individual ratepayers under certain conditions?
Efficiency carryover
Should utilities be able to benefit from cost-efficiency gains achieved in the past beyond the next general rate case (that is, mitigate the “ratchet effect”)?
The default should be no refunds, with exceptions only under extreme or unusual circumstances generally articulated upfront − e.g., costs recovered from ratepayers for a canceled capital project the regulator deemed imprudent ex post. Refunds are supportable only when evidence ex post shows that a utility acted imprudently or grossly over-forecast specific costs. Flexibility should be optional with predetermined price floors and ceilings, and other conditions. Pricing flexibility is uncommon in MRPS, but has potential to improve allocative efficiency by preventing uneconomic bypass and being more responsive to competitive conditions. Price floors and ceilings could result in more stable and predictable rates over time, and avoid “rate shock." A carryover mechanism to mitigate the “ratchet effect” should be optional and requires careful regulatory review. A carryover may be theoretically appealing (and has some empirical support in terms of costcontrol incentives), but is challenging to implement, including the determination of appropriate benchmarks.
7. Conclusion
added administrative burden. In Alberta, for example, the MRPs contain no earnings sharing, which according to the Utilities Commission would weaken utility incentives for cost control. The commission does allow reopeners when the actual rate of return on equity deviates from the authorized level by 500 basis points or more for two consecutive years (Brown et al., 2014). Earnings-sharing could also lead to cost shifting and misreporting by utilities, and opportunistic behavior by regulators. In the U.S. telecommunications sector, for a short time, pure price-cap regulation replaced the hybrid price-cap with earnings-sharing plans that were common earlier. Instead, regulators tended to resort to the use of “stretch factors” or initial rate cuts for benefit-sharing purposes (Sappington and Weisman, 2016). Flexible rates allow a utility to charge a price to certain customers within a specified range. A regulator would normally designate a price ceiling and floor. In retaining a customer, the utility, because of competitive market conditions or for other reasons, may have to offer a special rate that falls below the standard or fully allocated cost rate. Pricing flexibility allows the utility to recover more of its fixed costs (assuming, for example, that ratepayers offered a special rate would have lowered their consumption in its absence), thereby avoiding a reshifting of those costs to remaining ratepayers. Flexible rates could come in the form of special rates to discourage certain customers, like large business or industrial customer, from bypassing the utility system. As long as the utility is not charging below its incremental cost, according to the conventional economic argument, it is not uneconomical to offer a lower rate. The customer may have service alternatives and faces unique circumstances compelling a utility to offer the customer a special rate. The customer might otherwise leave the utility service area, not expand its business, or close its business. Special treatment to an individual customer, however, represents a discriminatory action, but one that regulators can justify under certain conditions as commensurate with the public interest.
MRPs have features with potential benefits to both utilities and ratepayers. MRPs are especially appealing in a dynamic world where utilities face rising average cost or attrition of a utility's earnings over time. This condition inevitably leads to utilities frequently filing rate cases, which impose high costs to both regulators and utilities. Either utilities or their regulators can take the initiative in proposing an MRP. The design considerations provided in Table 1 can provide guidance. It includes add-on mechanisms that regulators have either approved or required across jurisdictions in the U.S. While not the core parts of MRPs, they have elicited lively debate and are particularly major factors in the acceptability and sustainability of MRPs in a politically charged environment. Well-structured MRPs can ultimately pay dividends to utilities, their ratepayers, and society at large. Poorly structured ones, evident by the shifting of risks to utility ratepayers and the distribution of efficiency savings only to utility shareholders, are not consistent with the public interest goals of regulation. So far in the U.S., proponents have been unsuccessful in convincing regulators that MRPs are superior to traditional ratemaking in setting prices for energy utilities. MRPs could be implemented in an evolutionary process. One set of mechanisms can be tried, its performance assessed, additional data and reporting requirements identified, and refined mechanisms developed and applied. Perhaps this approach represents the most feasible course of action to expand the use of MRPs for U.S. energy utilities. References Akerlof, George A., 1970. The market for ‘lemons’: quality uncertainty and the market mechanism. Q. J. Econ. 84 (No. 3), 488–500 August. Averch, Harvey, Johnson, Leland L., 1962. Behavior of the firm under regulatory constraint. Am. Econ. Rev. 52 (December), 1052–1069. Beecher, Janice A., Kihm, Steven G., 2016. Risk Principles For Public Utility Regulators. Michigan State University Press, East Lansing, MI. Bonbright, James C., et al., 1988. Principles of Public Utility Rates, second ed. the first ed. Public Utilities Reports, Inc. authored solely by Bonbright, was published in 1961. Borenstein, Severin, Bushnell, James, September 2014. The U.S. Electricity Industry after 20 Years of Restructuring, vol. 252 EI@ Hass WP. Brown, Lorenzo, et al., 1991. Toward improved and practical incentive regulation. J. Regul. Econ. 3, 323–338. Brown, Toby, et al., May 20, 2014. Incentive-Based Ratemaking: Recommendations to the Hawaiian Electric Companies. Prepared for the Hawaiian Electric Companies. Costello, Ken, October 2013a. Future Test Years: Evidence from State Utility Commissions. NRRI 13-10. Costello, Ken, July 2013b. Future Test Years: Challenges Posed for State Utility Commissions. NRRI 13-08. Costello, Ken, September 2009. How Should Regulators View Cost Trackers? NRRI 09-13. Harunuzzaman, Mohammad, et al., March 1994. Regulatory Practices and Innovative Generation Technologies: Problems and New Rate-Making Approaches. National
6.3. Recommendations and rationales Table 1 summarizes MRP design considerations with recommendations. It reflects the end product of this article, which is to identify attributes of a good MR. One can with good reason contest these recommendations. The purpose here is to elevate the dialogue on MRPs between regulators, utilities, and other stakeholders. With surety, the participants of the regulatory process will disagree on the weights given to individual outcomes. They will also have different views on what constitutes “desirable outcomes”. The job of the regulator is to sift the evidence for reaching a decision that best advances the public interest. 7
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K.W. Costello Regulatory Research Institute Report 94-05. Hauge, Janice A., Sappington, David E.M., 2010. Pricing in network industries. In: Baldwin, Robert, Cave, Martin, Lodge, Martin (Eds.), The Oxford Handbook of Regulation. Oxford University Press, Oxford, UK, pp. 462–499. Hesmondhalgh, Serena, et al., 2012. Approaches to Setting Electric Distribution Reliability Standards and Outcomes. The Brattle Group, January. Joskow, Paul L., 2014. Incentive regulation in theory and practice: electricity distribution and transmission networks. In: Rose, Nancy L. (Ed.), Economic Regulation and what Have We Learned? University of Chicago Press, Chicago, Il, pp. 291–344. Joskow, Paul L., October 1974. Inflation and environmental concern: structural changes in the process of public utility regulation. J. Law Econ. 17, 291–327. Kahn, Alfred E., 1971. Economics of Regulation, vol. 1 John Wiley & Sons, New York. Larkin & Associates, PLLC, May 2012. Increasing Use of Surcharges on Consumer Utility Bills. Prepared for the American Association of Retired Persons. Lowry, Mark Newton, et al., July 2017. State Performance-Based Regulation Using Multiyear Rate Plans for U.S. Electric Utilities. Report prepared for the Ernest Orlando Lawrence Berkeley National Laboratory. Lowry, Mark Newton, Woolf, Tim, January 2016. Performance-Based Regulation in a High Distributed Energy Resources Future. LBL-1004130.
Lowry, Mark Newton, 2007. Alternative Regulation for Infrastructure Cost Recovery, vol. 9 Prepared for the Edison Electric Institute, January. Lyon, Thomas P., May 1996. A model of sliding-scale regulation. J. Regul. Econ. 9 (Issue 3), 227–247. Makholm, Jeff D., November 2018. The rise and decline of the X factor in performancebased electricity regulation. Electr. J. 31 (Issue 9), 38–43. Posner, Richard A., 1969. Natural monopoly and its regulation. Stanford Law Rev. 21, 548–643. Sappington, David E.M., Weisman, Dennis L., April 2016. The disparate adoption of price cap regulation in the U.S. Telecommunications and electricity sectors. J. Regul. Econ. 49 (Issue 2), 250–264. Schmalensee, Richard, Autumn 1989. Good regulatory regimes. Rand J. Regul. 20 (No. 3), 417–436. Washington Utilities and Transportation Commission, June 25, 2013. In the Matter of the Petition of Puget Sound Energy, Inc., and Northwest Energy Coalition for an Order Authorizing PSE to Implement Electric and Natural Gas Decoupling Mechanisms and to Record Accounting Entities Associated with the Mechanisms, Final Order Authorizing Rates. Dockets UE-130137 and UG-130138.
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