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Targeting Attrition: Some Familiar Ratemaking Tools
Kenneth Gordon is a Special Consultant at NERA and specializes in utility regulation and related issues. He was previously Chairman of the Massachusetts Department of Public Utilities. He came to the Massachusetts Commission from the Maine Public Utilities Commission, where he also held the office of Chairman. Prior to that, he was an Industry Economist at the Federal Communications Commission’s Office of Plans and Policies. Dr. Gordon was an active member of the National Association of Regulatory Utility Commissioners (NARUC) and served as President of that organization in 1992. He was also a member of NARUC’s Executive Committee and Committee on Communications. In addition, he has served as Chairman of the New England Conference of Public Utilities Commissioners Telecommunications Committee and is a former Chairman of the Power Planning Committee of the New England Governors’ Conference. Wayne P. Olson is a Senior Consultant at NERA and focuses on economic, finance, accounting, and public policy issues in the electric utility, gas distribution, oil and gas pipeline, and telecommunications industries. Prior to joining NERA, he was Director of Finance of the Maine Public Utilities Commission, where he was involved in electric restructuring and telecommunications activities as well as the full gamut of rate case and other regulatory issues. He has also served as a Manager at Palmer Bellevue Corporation, an International Banking Officer at Westpac Banking Corporation, and a Financial Analyst in the Economics and Rates Department of the Illinois Commerce Commission. Kurt G. Strunk is a Senior Consultant at NERA and has extensive experience working on strategic, regulatory, and corporate financial issues in the energy industry. In the U.S., he has advised utilities on sector restructuring, contract and asset valuation, origination, hedging and risk management, regulatory strategy, prudence, cost of capital, affiliate transactions, and retail market issues. He has been a key member of the NERA team implementing auctions for the provision of default electric service in New Jersey and Illinois. Mr. Strunk has also advised governments, regulators, and energy companies on issues relating to industry structure, regulation, and sector reform in Latin America and Europe. He coauthored the white paper outlining structural reform and partial privatization of the Mexican power sector, which was developed for Mexico’s National Congress in 2000. In 2002 and 2003, Mr. Strunk advised the Commission for Energy Regulation in Ireland on the development of a solicitation for the construction of a 400 MW power generation facility and associated offtake contract. He has also advised Mexico’s Comisio´n Federal de Electricidad on the development of its independent power program and, in 1996, was part of the NERA team working on power sector restructuring in Spain.
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Targeting Attrition: Some Familiar Ratemaking Tools Because of their investment in long-lived assets with little value in alternative uses, special attention to meeting the terms of the regulatory compact is appropriate. This need not always take the form of full-blown rate cases—there are more targeted tools as well. Targeted and formula-based approaches can play a role in setting just and reasonable rates, based on prudently incurred costs. Kenneth Gordon, Wayne P. Olson and Kurt G. Strunk
I. Introduction Public utilities invest in longlived, specialized assets. This ‘‘infrastructure’’ supports economic growth and, as such, helps to explain why public utilities are regulated.1 Public policymakers—at the federal level and in many states—have made modernization of the nation’s electric transmission and distribution infrastructure a priority.2 There are a variety of
policies and practices that can be considered ‘‘standard’’ public utility regulatory methods and that can support investment in infrastructure. tate utility commissions use a variety of regulatory policies and practices—variations on a theme but distinctive enough to suit the needs of the state. For utility investors, it is not the tiny details that matter, but rather whether there is a credible commitment to treat both utility
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customers and utility investors fairly, over the short and long runs. Public utilities are regulated to protect utility customers from the consequences of the unfair exercise of market power. hat purpose would targeted and formulabased regulatory approaches serve? The answer to that question would vary from state to state and from case to case, but, in the current economic climate, we would suggest that there are three major challenges that many electric utilities are now facing: (1) attrition, which is a persistent inability to recover the real costs of providing utility services; (2) the need to invest capital to build utility infrastructure, some of which is mandated by the makers of public policymakers, which can exacerbate the attrition problem; and (3) credit ratings that are above investment grade, but that remain weak by historical standards. A utility’s persistent inability to recover the real costs of providing utility service would harm customers. Direct solutions to the attrition problem may be difficult to achieve, so the focus of this article is on investigating new applications of traditional regulatory tools, aiming to provide commissions and utilities with examples of approaches that could meet current challenges. In this article, we review key regulatory building blocks that could accommodate regulatory approaches that result in more timely recovery of costs. Examples of regulatory approaches that are increasingly
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being used by state commissions when setting utility rates include: Asset ‘‘trackers’’ for defined categories of capital expenditures (‘‘cap ex’’) as they enter rate base. Construction work in progress (CWIP) in rate base with a cash return. Indexing procedures of various sorts. Alternative forms of regulation, such as broad-based, formula-rate plans.
With any application of these regulatory building blocks, there needs to be an assurance that each ratemaking tool can work correctly and not simply end-run the regulator. Some form of ‘‘preapproval’’ of the regulatory policies and practices to be used for a major capital addition, often generation- or transmissionrelated, but that could also apply to major distribution investments. Next, we survey and review specific examples of these approaches. This article identifies regulatory building blocks that are squarely part of standard regulatory methods, but that, given the challenges currently facing the electric utility industry, may have a greater role to play. In conclusion, we review some of the crucial public policy considerations, e.g., economic
efficiency and consumer benefits, which state commissions should consider. With any application of these regulatory building blocks, there needs to be an assurance that each ratemaking tool can work correctly and not simply end-run the regulator. The approaches described in this article have the potential to provide benefits to utility customers.
II. Industry Challenges Each state and region has its own infrastructure needs and would focus its attention on how to best meet those needs. Utility ratepayers would be well served by a regulatory framework and company policies that serve the public interest by minimizing the overall cost of capital, while facilitating investments in needed infrastructure by the regulated utility industry. There are a variety of ways to accomplish this goal. n the current economic climate, we would suggest that there are three major challenges that many electric utilities are now facing: Attrition dilemma. Rates that are adequate for a given ‘‘test year’’ can fall short in succeeding periods given growth in rate base and increasing operating costs, leading to ‘‘attrition,’’ which is the erosion of earnings ‘‘caused by cost of services increasing more rapidly than revenues.’’3 Figure 1 provides evidence that some electric utilities have not earned
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[(Figure_1)TD$IG] 11.00
years. The ability of utilities to fund capital investment is directly dependent on their ability to raise debt and equity in the capital markets. Moreover, most states now have renewable portfolio standards (RPS) or state mandates in place,4 as shown in Figure 3. To meet RPS type mandates, many utilities will need to invest in the infrastructure needed to make use of that renewable energy. Given the nature of these infrastructure investments, some degree of regulatory pre-commitment would likely be appropriate, along with other regulatory building blocks, such as asset trackers and CWIP in rate base with a cash return. Credit quality constraint. Electric utility credit ratings are generally above investment grade, but remain weak by historical standards. Figure 4 shows the S&P bond ratings for electric utilities.5 The sharp
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goals and major challenges that face the electric utility industry— and extensive cap ex construction programs can exacerbate a utility’s attrition problem. Figure 2 shows that the cap ex plans of utilities are ambitious, requiring the raising of significant new capital over the next few
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their allowed ROE in recent years. With few exceptions, all of a utility’s activities are aimed at meeting its obligation to serve customers and, therefore, the legitimate costs incurred by a utility as part of its efforts to meet the needs of its customers would be recoverable in rates. With appropriate incentives in place, there is a strong presumption that all of a utility’s costs will be incurred to meet the utility’s obligation to serve. While there is no guarantee that a utility will actually be able to earn its cost of capital once rates have been set, if rates are set such that the utility does not have a realistic opportunity to recover its costs, harm to customers will likely result in the longer run, if not sooner. Capital expenditure challenge. Infrastructure investment in generation, transmission, and distribution plant would be needed to meet the ambitious
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Figure 2: Total Capital Expenditures for 44 Companies (Historical and Forecast-$ Billions)
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Source: Energy Information Administration, Renewable Energy Trends in Consumption and Electricity 2008.
Figure 3: States with Renewable Portfolio Standards, 2008
recovery methods would be a necessary part of that balanced approach. The ability of utilities to fund capital investment is directly dependent on their ability to raise debt and equity in the capital markets. Under current market conditions, it would be relatively more difficult for utilities to raise funds in the debt market, and
decline in electric utility credit quality (relative to 2001 levels) begs the question of whether the industry and its regulators will together be able to find ways to implement the nation’s grid modernization, energy independence, and environmental goals in a timely and efficient manner. Timely rate
[(Figure_4)TD$IG] Electric Utility Bond Ratings 1965-2009 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 1965
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Figure 4: Electric Utility Bond Ratings (1965–2011)
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when they do so, it would be at a higher cost than it would have been with a bond rating of ‘‘A-/ A300 or higher. tility ratemaking should not prevent a utility from earning an adequate return on its investment in serving the public. Attrition, which is typically discussed in the context of the combined effects of inflation and large-scale construction programs on a utility’s opportunity to actually earn its allowed ROE, should not lead to a public utility being prevented from having a reasonable opportunity to recover its prudently incurred costs, including the forward-looking cost of capital. Leonard Saul Goodman points out that‘‘[i]f attrition is an economic factor truly beyond the company’s control, and if it is a proper cost in a transitional inflationary period, there is
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unfairness in placing the entire burden of the cost on shareholders.’’6 A close reading of this comment suggests that: Economic factor truly beyond the company’s control. Infrastructure costs aimed at achieving ‘‘energy independence’’ can be considered to be a type of mandated cost, with the initial decision to construct beyond the control of the utility. To meet RPS mandates, utilities will need to invest in infrastructure and some degree of ‘‘preapproval’’ of the initial decision to construct can be justified. A proper cost. Note that the utility would continue to have control of its execution of the project and therefore would face prudence scrutiny with respect to the mandated investment. Unfairness in placing the burden entirely on shareholders. With respect to the traditional regulatory ‘‘balancing act,’’ efforts to ameliorate the economic effects of attrition by providing more timely cost recovery can be beneficial to both utility customers and investors. This is because utility customers’ rates will reflect the weighted cost of the utility’s debt, preferred stock, and common equity—and use of the regulatory building blocks can potentially reduce these capital costs. he traditional standard to justify the suitability of a fuel adjustment mechanism is whether the cost of the purchased item is beyond the control of the utility, large, and volatile.7
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Applying an analogous ratemaking approach to mandated infrastructure investments can potentially make sense from a public policy perspective. After all, the cumulative effect of numerous ratemaking adjustments should not prevent a utility from having the opportunity to earn a compensatory return on capital. Absent imprudence, a public utility should not face a persistent
An important element in this demonstration is being able to point to a supportive regulatory environment. inability to recoup its costs of providing utility service. Put more positively, a utility should be given a reasonable opportunity to realize an adequate rate of return and thereby be assured of access to the capital markets at a reasonable cost—because customers would benefit.
III. Regulatory Building Blocks The focus of utility regulation should always be on consumers, with regulation ensuring that the rates paid by utility customers are just and reasonable, based on
prudently incurred costs. Given that regulated electric utilities must be able to raise substantial amounts of both debt and equity capital in order to fund investment in long-lived, specialized assets, utilities must be able to demonstrate that they have the financial standing and resources needed to raise capital at a reasonable cost, in good markets and bad, in both the short and long terms. An important element in this demonstration is being able to point to a supportive regulatory environment. he purpose of this section is to review key regulatory building blocks that can accommodate regulatory approaches that result in more timely recovery of costs. These building blocks include such regulatory practices as: FERC Form 1 accounting statements. Effective regulation of any form requires that regulators define the consistent, durable, and transparent accounting procedures to be used by regulated utilities. The early history of regulation in the U.S. was characterized by notorious accounting abuses, including overstated expenses, unverifiable investments in plant and equipment, a lack of separation between utility and non-utility businesses, and overcapitalization. Such abuses were ended with the adoption, in 1938, of the Uniform System of Accounts by the federal government.8 The goals of good regulation are frustrated when the lack of detailed and reliable
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accounting data obstructs the regulator’s ability to periodically assess the cost of service.9 For example, the Uniform System of Accounts rarely leaves U.S. energy utilities and their regulators in dispute over basic financial issues such as profitability, depreciation expenses, customer contributions, incurred operating costs, or the treatment of unregulated affiliates. Rate cases instead focus on how these costs should be recovered for ratemaking purposes. Adjustment mechanisms. Infrastructure recovery mechanisms, also known as ‘‘asset trackers’’ or ‘‘riders,’’ are roughly analogous to the adjustment mechanisms that are used to pass through the costs of fuel and purchased power. Regulatory Research Associates (RRA) explains that ‘‘from an investor standpoint, this is the preferred treatment, as adjustment clauses can allow for more timely rate recognition of incremental CWIP.’’10 Asset trackers or similar adjustment mechanisms allow for more-timely recovery of rate base additions than would be the case with traditional rate cases. Operating and maintenance expense (O&M) riders or trackers of various sorts, such as bad debt riders or regional cost riders, could also be used. Adjustment mechanisms have been used by regulators since the early days of the industry.11 CWIP in rate base with a cash return. As commissions and utilities grapple with questions of how best to invest in the utility infrastructure needed to
accommodate public policy goals, allowing CWIP in rate base with a cash return has once again become a standard part of the regulatory toolkit. As the industry proceeds with the ongoing construction cycle, legislatures and regulators have begun to allow CWIP in rate base for a cash return, sometimes restricted to only certain designated types of
plant, i.e., transmission or certain types of generation.12 RRA reports that 16 states have permitted a cash return on CWIP in recent years and that eight of the states that allow CWIP in rate base with a cash return also allow asset trackers to be used.13 Given that an allowance for funds used during construction (AFUDC) need not be recovered in rates, using this approach reduces the total cost to customers. Inflation adjustments. Attrition is the persistent inability to recover the real costs of providing utility services. To mitigate the impact of attrition, regulators use inflation adjustments in a variety of ways including attrition allowances, fully forecasted test years,
projections of cost items, true-up of projected and actual costs, and formal price cap plans (inflation minus an x-factor). Generally, inflation adjustments can help maintain rates at levels that provide a utility with a reasonable opportunity to recover its costs, including the cost of capital. Cap ex budgeting. All investorowned public utilities have some type of capital expenditure budgeting process in place to prioritize the many alternative infrastructure investments that could be made. In a few states, ex ante cap ex budgeting information is formally provided to the utility regulator, while, in other cases, less formal procedures are used to keep the regulatory agency informed. Either way, the cap ex budgeting process can build a foundation for recovering utility costs in a timely manner. hese building blocks can aid in the establishment of regulatory practices that support investment in utility infrastructure, which can, in turn, aid in meeting RPS requirements and other state goals.14 The regulatory process has safeguards (e.g., prudence reviews) to assure that tariffed rates remain at a just and reasonable level. Consistent with the regulatory compact, which provides a means of balancing the competing interests of utility customers and the investor–owners of public utilities, these tools can be used to respond and adapt to changes in customer, industry, and market conditions.
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IV. Some Solutions to the Attrition Problem Utility ratemaking is conducted on a case-by-case, fact-specific basis. While the details vary somewhat from state to state, the basics of the ratemaking process are largely the same. For any given jurisdiction, the overarching framework of utility regulation—the ‘‘end result’’15— is likely what is most important to investors.16 Under the Hope standard, ‘‘[i]t is not theory but the impact of the rate order which counts.’’17 tility commissions necessarily have discretion, consistent with their statutory authorization, to revise regulatory policies and procedures. Thus, for example, commissions can typically decide whether to use a fully forecasted test year, a partially forecasted test year, or a fully historic one; a test year can be adjusted for attrition and/or known and measurable changes in costs. The comprehensive state-level regulation of electric utilities is based on a regulatory compact that provides an economic framework that supports major capital investments in assets with very long useful lives. If utility price signals are more efficient when a more cost-reflective test year is used, for example, regulatory policies can be adjusted to accomplish this, consistent with the commission’s statutory authority. The purpose of this section is to review several regulatory approaches that can be
considered ‘‘standard’’ public utility regulatory methods and that may be especially well suited to meeting current challenges. A. FERC formula-rate transmission ratemaking Formula-based approaches— and other regulatory building
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blocks—can be used to set just and reasonable rates, based on prudently incurred costs. The FERC’s formula rate approach is a useful example of how to achieve timely rate recovery, while maintaining traditional regulatory oversight of utility rate levels. The FERC’s approach relies crucially on applying FERC Form 1 data in a formula-based ratemaking approach. Some of these formula-rate plans use prior-year FERC Form 1 data to calculate rates for the upcoming year, while other plans use projected rates, which are then trued up when actual costs are known, with over-collections returned to customers with interest.18
FERC’s approach has a number of advantages including: Keeping rates at levels that are close to the cost of service. This largely avoids the possibility of ‘‘overearning’’ by the utility. Rates are maintained at costbased levels, without the need for frequent full-blown rate cases. This is a sharp contrast to the FERC ratemaking approach for gas pipelines, where gas pipelines can ‘‘over-earn’’ for extended periods of time (paid for by electric utilities and gas local distribution company customers, among others), with the FERC staff only investigating if the earned ROE is over 20 percent.19 Accommodating various types of incentives. Various types of incentives can be accommodated within the FERC’s framework. Orders 679 and 679-A established the procedures by which electric transmission owners can receive incentive-based rate treatment.20 Under FERC Order 679, incentives available to jurisdictional public utilities include ROE incentives, CWIP in rate base with a cash return, hypothetical capital structure, accelerated depreciation, recovery of costs of abandoned facilities, and deferred cost recovery. FERC’s various incentive measures typically garner more attention than does its formula rate approach. Credit quality. Credit quality is a statutorily required criterion in FERC’s determination of a formula-rate plan.21 FERC has, example, considered Westar’s ‘‘BBB-’’ credit rating when
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approving formula rates,22 an example of a regulatory commission using its discretion to support a utility whose credit rating was on the verge of dropping below investment grade.23 The FERC’s formula rate approach can incorporate accelerated depreciation for ratemaking purposes, CWIP in rate base with a cash return, and an asset tracker approach, all of which can support a utility’s credit standing. Inflation adjustments. Standard ratemaking practice makes use, in a variety of ways, of inflation adjustments to actual costs. Whether it is an attrition adjustment, use of a fully forecasted test year, projections of variable costs, a formal price-cap (inflation minus an x-factor) plan, or some other regulatory use of an inflation adjustment, standard practice accommodates ratemaking adjustments based on anticipated inflation. Adjustment mechanisms, such as FERC’s formula-rate approach, can build in true-ups of projected and actual costs. Administrative efficiency. FERC has a large and diligent accounting and auditing staff and thus can be assured that the FERC Form 1 data is accurate and reliable. Thus, FERC’s formularate approach can be implemented in an administratively efficient way. FERC regulates a large number of transmission entities, and, to prevent a logjam, needs to have administratively workable ratemaking procedures in place.
Nevertheless, the timing and procedural protocols provide enough time for interested parties to review the data filed by the transmission entity and to submit information requests.24 tate commissions regulate a smaller number of companies, but the rate-caseevery-few-years paradigm may currently not work well in all
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on a divided record. Thus, settlements have a useful role to play.25 Con Ed has, in recent years, borne a cap ex budget of well over $1 billion dollars per year, which is aimed at investing in distribution infrastructure needed to meet its obligation to serve. The Con Ed settlement ‘‘hardwires’’ a three-year cap ex program of roughly $1.4 billion per year into a three-year rate plan, with rate increases of $540.8 million, $306.5 million, and $280.2 million, respectively.26 The New York commission has an ex ante cap ex review process in place, which may accommodate more timely ratemaking treatment of infrastructure investment. ith settlements, one does not necessarily know all of the tradeoffs involved, only the end result. In some contexts, settlements can make the ratemaking process less transparent because the commission may not rule, for example, on what it believes to be a reasonable capital structure and cost of equity and thus a stipulation can become opaque, a black box. That need not be the case however and, indeed, is not the case with Con Ed. Integrating a three-year cap ex program into the setting of rates for those years provides an opportunity to raise rates in a stable and predictable way, rather than rely on one-time adjustments via occasional fullblown rate cases. Con Ed’s threeyear cap ex rate plan provides a good ratemaking model, as does
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instances. Among other things, state commission administrative resources are constrained in an era of tight budgets. Most states commissions have ‘‘annual report’’ filing requirements, akin to the FERC Form 1, which would accommodate the use of a formula-rate approach. B. Con Ed distribution rate settlement Rate settlements or stipulations are a standard part of the procedural repertoire used to conduct public utility rate regulation. Settlements are a way to forge consensus on issues that would otherwise have to be decided by the regulator, based
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the settlement process used to achieve that outcome. C. Peoples Gas pipe replacement tracker A well-designed and implemented asset tracker for qualified infrastructure investments benefits customers. The basic idea would be to recover the costs of ‘‘qualified’’ infrastructure investments incurred between rate cases through an asset tracker. The definition of qualified investments varies. For example, the definition for The Peoples Gas Light and Coke Company (‘‘Peoples Gas’’) infrastructure cost recovery charge (ICR charge) focuses on qualified additions associated with replacing aged facilities that have not previously been included in rate base.27 Under an alternative approach used in New Jersey,28 job creation and economic impact are the main criteria used to target cost recovery on an expedited basis.29 A definition of ‘‘qualified’’ infrastructure investments might include capital expenditures that benefit many customers, are relatively large in size, and that go beyond the ordinary expansion of distribution facilities. he Peoples Gas ICR charge was implemented in the context of a desire to ensure timely replacement of aging and possibly unsafe gas infrastructure. Further, the tariff notes that there is a savings of $6,000 per mile from abandoning aged cast iron pipe.30 Actual
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savings are reconciled to this estimate every three years. Hence, the program was implemented as an incentive for what was considered to be a desirable investment from safety, reliability, and economic perspectives. An infrastructure recovery mechanism, or asset tracker, is attractive from a public policy
perspective for numerous reasons. Accommodate more timely recovery of new plant costs. By ensuring timely recovery, a tracker may make timely investment in facilities more feasible. Rates would ordinarily go up in conjunction with capital expenditure completion and commercial operation but that would be accomplished in a relatively stable and predictable fashion given the cap ex review process. An asset tracker can be implemented in conjunction with CWIP in rate base with a cash return, which would further accelerate and smooth rate impacts. In terms of rate stability, if some AFUDC
accruals can be avoided or minimized, that would help keep rates low. Support financial integrity. An asset tracker can support a public utility’s ability to raise new capital, thereby easing the financing of capital expenditures. Over time, this would tend to improve credit quality and benefit customers via a lower cost of capital. Administrative safeguards. Procedures could be put in place to ensure that the commission has the timely opportunity—and necessary information—to ensure that the asset tracker is working as intended, thereby benefiting customers. For example, Peoples’ internal auditors must certify each year that the ICR has been properly implemented, and there must be an independent external review every five years.31 The Peoples asset tracker mechanism, which places assets into rates in a timely matter, but leaves most of the review process to the reconciliation stage of the case, provides a reasonable ratemaking model. Other approaches can, of course, be used as well. The Peoples Gas Rider ICR mitigates regulatory lag for qualified capital expenditures. Rather than spending and then waiting for commission approval to recover the costs, the utility is afforded the opportunity to spend, recover, and then wait for a retrospective prudence review. From a credit quality standpoint, however, the regulatory implementation of the
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2010 Peoples Gas rate case order represents a missed opportunity to enhance the utility’s ability to raise debt at a low cost.
V. Traditional Rate Cases and the Regulatory Building Blocks While ratemaking procedures will vary on a state by state, case by case basis, regulators’ primary regulatory ‘‘tool’’ for overseeing a utility’s tariffed rates is the traditional rate-of-return/cost-ofservice rate case, which provides the regulator with a forum for investigating and determining the justness and reasonableness of the utility’s rates and the prudence of its capital and operating costs. Figure 5 shows that rate case activity surged during the middle- to late-2000s following a period of relative inactivity during the late 1990s and early 2000s.34 Through June 30, 2011, 39 rate cases have been filed compared to a total of 60 for 2010.35 Using a ‘‘test year’’
revenue requirement, the regulatory agency examines the reasonableness of the utility’s sales growth projections, rate base, operating expenses, cost of capital, and other cost components, and then sets rates that provide the utility a reasonable opportunity to recover its prudently incurred costs—this is the core of the traditional public utility ratemaking regulatory bargain. regulator’s ability to disallow imprudently incurred costs provides crucial regulatory oversight over the utility’s management of its operations. A utility’s costs are held to a ‘‘reasonableness’’ standard, not an ‘‘ideal’’ standard of perfection or optimization. In setting rates that are just and reasonable, the required ratemaking approach is to provide the utility with an opportunity to recover the prudently incurred costs (including a fair rate of return on capital) of providing utility services to customers. In
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Peoples Gas ICR has a major drawback. The mechanics of the Peoples Gas infrastructure tracker are sound, but the ‘‘quasi-debt’’ rate allowed for Rider ICR assets may effectively prevent Peoples Gas from improving its credit quality, at a time when it must raise new capital to fund cap ex programs. Providing only a quasidebt return implies that the ‘‘tracked’’ assets require a lower allowed ROE than non-tracked assets, but the cost of capital is a function of the use to which it is put and is not a function of the specific rate treatment provided those assets.32 roviding only a quasi-debt return makes it more difficult for the company to maintain the coverage ratios needed to maintain or improve its credit rating. Peoples Gas had lost it’s ‘‘A-’’ credit rating from S&P (it has an ‘‘A3’’ rating from Moody’s) following its previous rate case, with those lower ratings affirmed subsequent to the February 2010 rate case decision. In explaining its downgrade, S&P noted that its assessment was based, in part, on its ‘‘assessment of the Illinois regulatory environment which we place in the least credit supportive category.’’33 This rate case did not put Peoples Gas back on the road to meriting an ‘‘A-’’ credit rating. It is a mistake to view an asset tracker in isolation—credit rating agencies generally focus on the regulatory compact in the state not on relatively narrow aspects of ratemaking procedure—and thus this aspect of the February
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examining the prudence of a utility’s costs, the regulator considers the costs in relation to a ‘‘reasonable man’’ standard—the costs must be reasonable in comparison to the costs that would result from reasonable utility practice. Any prudence determination should be based on whether the decisions at the time they were made were reasonable under the then existing circumstances. For a utility, prudence is reflected in the decision a reasonable utility management would make at the time the decision is required, and must remain free of any hindsight. If a prudent decision turns out badly, the bad outcome does not by itself demonstrate a lack of prudence.36 Fairness requires that any imprudence be demonstrated objectively so that there will not be uncertainty about the regulatory decision. Evidence of failure to act prudently must be well grounded in law, economics, and public policy. ome prudently incurred costs (e.g., charitable contributions,37 executive incentive compensation, and advertising expenses) are frequently excluded from a utility’s revenue requirement, even if they are legitimately incurred costs. Prof. Alfred E. Kahn, when he was chairman of the New York State Public Service Commission, expressed the view that ‘‘heated discussions’’ about advertising ratemaking policy were a ‘‘tempest in a teapot,’’ both because the dollars were small
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and because disallowing advertising expenditures under the ‘‘glib assumption that these costs will then be borne by stockholders rather than ratepayers, is something of a sham.’’38 Prof. Kahn went on to explain that the: [E]ssential fraudulence of our purporting to exclude from rates
expenditures for advertising that company managements will continue to feel it necessary to make: since we made every effort to set the allowable return on equity at the minimum cost of capital, and most of the companies we regulate are not earning even that, in principle putting any advertising expenditures ‘below the line’ can only mean, if we are honest, increasing the allowed return on equity, in order to enable these companies to raise the capital they need on reasonable terms.39
This problem could be addressed directly, by revisiting commission policies and precedent on the ratemaking treatment of these costs. Unfortunately, however, this rarely occurs, which makes a direct solution to the problem
difficult to achieve. The regulatory approaches described in this paper do not solve this problem, but would provide an indirect way to deal with the attrition problem, large cap ex programs, and bond ratings that are weak by historical standards.
VI. Conclusion The standard approaches described in this article can be used to meet the challenges that the electric utility industry currently faces. While the details of utility regulation in the state are no doubt important, there are a variety of regulatory policies and mechanisms that can be used to set utility rates. Regulatory approaches which might not be viewed as quite as favorable to investors, might, in practice, be well-suited to the specific situation in a given state and therefore be considered to be acceptable. It is the end result that matters when regulatory institutions apply the regulatory compact. Utilities must have incentives that lead them to maximize customer benefits—so that customers receive efficient, safe, adequate, and reliable service both now and in the future. A utility’s economic incentives will be better when rates to customers reflect the utility’s true cost of providing service. Allocative efficiency refers to the prices that customers face. Allocatively efficient utility rates would give customers the
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economically correct price signals to use electricity or gas or not, depending on the customer’s choice. Failure to allow appropriate costs to be included in the utility revenue requirement distorts this efficiency, since customers are receiving an inaccurate price signal. Productive (or technical) efficiency refers to the incentives that the utility faces as it decides how to provide its services. The utility should have the incentives to operate in an efficient manner, while also continuing to provide safe, adequate, and reliable service. With appropriate incentives in place, few if any costs should be excluded from the utility’s tariffed rates—the utility will be focused on fulfilling its obligations to its customers. Investment incentives are the dynamic aspect of productive efficiency. The utility must have the incentive to efficiently invest in infrastructure. An inability to recover its costs could distort the utility’s investment incentives. Where credit quality concerns remain a significant deterrent to utility investment in infrastructure on behalf of customers, ratemaking treatments that provide more timely and regular recovery of costs may prove useful.&
Endnotes: 1. Utility regulation may, in part, be a ‘‘method of promoting the expansion of infrastructure services.’’ Richard A. Posner, Taxation by Regulation, BELL J. ECON., Spring 1971, at 39–41.
2. Title XIII of the Energy Independence and Security Act of 2007 (‘‘EISA07’’) declares that ‘‘it is the policy of the United States to support the modernization of the Nation’s electricity transmission and distribution system to maintain a reliable and secure electricity infrastructure that can meet future demand growth’’ and ‘‘achieve [the 10 items], which together characterize a Smart Grid.’’ At 292–293. 3. Robert L. Hahne and Gregory E. Aliff, ACCOUNTING FOR PUBLIC UTILITIES
Competitive Markets, National Regulatory Research Institute, Nov. 1991, at 9. 8. These accounts are firmly embedded within the practices of the accounting profession in the U.S. and are not capable of being amended or changed, as a practical matter, without the scrutiny and approval of the U.S. accounting profession’s standards board. 9. Outside the U.S., many regulatory jurisdictions still lack access to reliable and useful accounting data. 10. RRA, Construction Work in Progress: A State-by-State Policy Overview, April 7, 2009, at 1–2. 11. Adjustment mechanisms may have been unusual in 1918, when the Pennsylvania Public Service Commission characterized them as such, but they are not unusual today. See R.S. Trigg, Escalator Clauses in Public Utility Rate Schedules, UNIV. OF PENN. LAW REV., May 1958, at 964.
(Newark, NJ: Matthew Bender, 2001), at 8–3. 4. U.S. Energy Information Administration, Renewable Portfolio Standards and State Mandates by State, 2008, Aug. 2010, at http:// www.eia.gov/cneaf/ solar.renewables/page/trends/ table28.html. 5. See Leonard Hyman, AMERICA’S ELECTRIC UTILITIES: PAST PRESENT AND FUTURE, 2nd Ed. (Arlington, VA: PUR, 1985), at 263. See also Leonard Hyman, A.S. Hyman, and R.C. Hyman, AMERICA’S ELECTRIC UTILITIES: PAST PRESENT AND FUTURE, 8th Ed. (Vienna, VA: PUR, 2005), at 432. For recent data, see Edison Electric Institute, Quarterly Financial Updates, various dates. 6. Leonard Saul Goodman, THE PROCESS OF RATEMAKING, Vol. I (Vienna, VA: PUR, 1998), at 638. 7. Robert Burns, Mark Eifert and Peter Nagler, Current PGA and FAC Practices: Implications for Ratemaking in
12. RRA goes on to summarize the policy rationale for including CWIP in rate base, explaining that: ‘‘[i]nclusion of CWIP in rate base is generally viewed favorably by investors. Such treatment allows the utility to collect a cash rate of return on the asset while it is under development. The associated cash flow may reduce the amount of utility financing necessary during the construction program and enable a utility to receive more favorable consideration from the credit-rating agencies, thus reducing the utilities cost-of-capital going forward. Additionally, since including CWIP in rate base effectively ‘phases in’ the related investment, such treatment will reduce the ‘rate shock’ that might otherwise be experienced by the ratepayer when the plant or project is completed and placed into service and then reflected in rates in one step.’’ RRA, supra note 10, at 1. 13. Id., at 1–2. 14. For a 50-state survey of RPS standards, see American Bar Association, Report of the Renewable Energy Committee, Section of Public Utility, Communications and Transportation Law, Spring 2011.
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15. Per Hope, under the ‘‘just and reasonable’’ standard, ‘‘it is the result reached not the method employed which is controlling.’’ 320 U.S. 591 (1944). 16. See Wayne P. Olson, At a Crossroads: Modernizing Utility Infrastructure in a Tough Credit Environment, ELEC. J., Aug./Sept. 2009, at 6–26. 17. Hope, supra note 15. 18. Public Service Electric and Gas Company (PSEG), 123 FERC P 61303, 2008 WL 4416764 (FERC), Sept. 30, 2008.
25. Zhongmin Wang, Settling Utility Rate Cases: An Alternative Ratemaking Procedure, J. REGULATORY ECON., 26:2, 2004, at 141–163. 26. Before the New York Public Service Commission, Proceeding on the Motion of the Commission as to the Rates, Charges, Rules and Regulation of Consolidated Edison Company of New York, Inc. for Electric Service, Order Establishing Three-Year Electric Rate Plan, Case 09-E-0428, Mar. 26, 2010, at 3, 10–15.
19. Of the five most recent FERC rate investigations, the lowest earned ROE was 20.83 percent for Great Lakes Transmission. This leads to the conclusion that the effective threshold to warrant investigation by the FERC was about 20 percent.
22. Westar Energy, Inc., 122 FERC ô 61,268 (2008), Para. 47. 23. Olson found that ‘‘there is considerable evidence that the rate orders for ‘‘BBB-’’ utilities pay careful attention to credit quality when setting rates.’’ Olson, supra note 16, at 17. 24. PSEG, supra note 18.
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31. Peoples Gas, supra note 27, at 9. 32. Richard Brealey and Stewart Myers, PRINCIPLES OF CORPORATE FINANCE, 1st Ed. (New York: McGrawHill, 1981), at 158. 33. S&P, ‘‘Peoples Gas Light & Coke Co.,’’ Mar. 18, 2009, at 2. 34. During the 1990s, rates were frozen in a number of jurisdictions because of settlements and litigated proceedings related to mergers, alternative rate plans, and the introduction of retail competition. See Hethie Parmesano and Jeff D. Makholm, The Thaw: The End of the Ice Age for American Utility Rate Cases—Are You Ready? ELEC. J., July 2004, at 69. 35. Regulatory Research Associates, at http://www.snl.com/InteractiveX/ RateCaseHistory.aspx.
20. Promoting Transmission Investment through Pricing Reform, Order No. 679, FERC Stats. & Regs. ô 31,222 (2006) (‘‘Order No. 679’’); order on reh’g, Order No. 679-A, FERC Stats. & Regs. ô 31,236 (2006) (‘‘Order No. 679-A’’); order denying reh’g, 119 FERC ô 61.062 (2007). 21. 16 U.S.C. 824s (2006). Section 219 of The Energy Policy Act of 2005, 119 Stat. § 594 1241 (2005), amended the FPA. Specifically, § 824s specifies, among other things, that the FERC transmission infrastructure investment rule shall promote reliable transmission and generation by ‘‘promoting capital investment’’ in transmission infrastructure and provide an allowed return on equity that ‘‘attracts new investment in transmission facilities.’’ See http://www.law.cornell.edu/ uscode/16/usc_sec_16_00000824— s000-.html.
30. Peoples Gas, supra note 27, at 8.
27. Peoples Gas, Rider ICR, Infrastructure Cost Recovery, Ill.C.C. No 28, Fifth Revised Sheet No. 130, Feb. 17, 2010. 28. Before the New Jersey Board of Public Utilities, In the Matter of the Proceeding for Infrastructure Investment and a Cost Recovery Mechanism for all Gas and Electric Utilities, Decision and Order Approving Stipulation, Docket No. EO09010049, April 28, 2009, at 3, 10–15. 29. New Jersey’s economic stimulus plan, which sought to moderate the effects on New Jersey of the world economic downturn that followed the 2008 financial crisis, continues in operation, with companies required to file quarterly compliance reports. See, for example, South Jersey Gas, Capital Investment Recovery Tracker Quarterly Report in Compliance with the Board’s Order in Docket No. GO09010051, May 2, 2011.
36. When challenging the prudence of management on the basis of a bad result, care is needed because the regulatory agency already has one piece of information that utility management did not, and could not, have at the time the decision was made. The evaluation of prudence must be based on what a reasonable utility would have known at the time the costs were being incurred, not based on 20/20 hindsight, long after the costs were incurred. 37. The Economist, in a special supplement on precisely this issue, points out that ‘‘for strictly selfish reasons, well-run companies will strive for friendly long-term relations with employees, suppliers and customers. There is no need for selfless sacrifice when it comes to stakeholders. It goes with the territory.’’ The Good Company, ECONOMIST, Jan. 22–28, 2005, at 11. 38. Prof. Alfred Kahn as quoted in Richard Pierce, Jr., Gary Allison and Patrick Martin et al., ECONOMIC REGULATION: ENERGY, TRANSPORTATION AND UTILITIES (New York: BobbsMerrill, 1980), at 142. 39. Id.
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Targeting Attrition: Some Familiar Ratemaking Tools Because of their investment in long-lived assets with little value in alternative uses, special attention to meeting the terms of the regulatory compact is appropriate. This need not always take the form of full-blown rate cases—there are more targeted tools as well. Targeted and formula-based approaches can play a role in setting just and reasonable rates, based on prudently incurred costs. Kenneth Gordon, Wayne P. Olson and Kurt G. Strunk
I. Introduction Public utilities invest in longlived, specialized assets. This ‘‘infrastructure’’ supports economic growth and, as such, helps to explain why public utilities are regulated.1 Public policymakers—at the federal level and in many states—have made modernization of the nation’s electric transmission and distribution infrastructure a priority.2 There are a variety of
policies and practices that can be considered ‘‘standard’’ public utility regulatory methods and that can support investment in infrastructure. tate utility commissions use a variety of regulatory policies and practices—variations on a theme but distinctive enough to suit the needs of the state. For utility investors, it is not the tiny details that matter, but rather whether there is a credible commitment to treat both utility
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customers and utility investors fairly, over the short and long runs. Public utilities are regulated to protect utility customers from the consequences of the unfair exercise of market power. hat purpose would targeted and formulabased regulatory approaches serve? The answer to that question would vary from state to state and from case to case, but, in the current economic climate, we would suggest that there are three major challenges that many electric utilities are now facing: (1) attrition, which is a persistent inability to recover the real costs of providing utility services; (2) the need to invest capital to build utility infrastructure, some of which is mandated by the makers of public policymakers, which can exacerbate the attrition problem; and (3) credit ratings that are above investment grade, but that remain weak by historical standards. A utility’s persistent inability to recover the real costs of providing utility service would harm customers. Direct solutions to the attrition problem may be difficult to achieve, so the focus of this article is on investigating new applications of traditional regulatory tools, aiming to provide commissions and utilities with examples of approaches that could meet current challenges. In this article, we review key regulatory building blocks that could accommodate regulatory approaches that result in more timely recovery of costs. Examples of regulatory approaches that are increasingly
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being used by state commissions when setting utility rates include: Asset ‘‘trackers’’ for defined categories of capital expenditures (‘‘cap ex’’) as they enter rate base. Construction work in progress (CWIP) in rate base with a cash return. Indexing procedures of various sorts. Alternative forms of regulation, such as broad-based, formula-rate plans.
With any application of these regulatory building blocks, there needs to be an assurance that each ratemaking tool can work correctly and not simply end-run the regulator. Some form of ‘‘preapproval’’ of the regulatory policies and practices to be used for a major capital addition, often generation- or transmissionrelated, but that could also apply to major distribution investments. Next, we survey and review specific examples of these approaches. This article identifies regulatory building blocks that are squarely part of standard regulatory methods, but that, given the challenges currently facing the electric utility industry, may have a greater role to play. In conclusion, we review some of the crucial public policy considerations, e.g., economic
efficiency and consumer benefits, which state commissions should consider. With any application of these regulatory building blocks, there needs to be an assurance that each ratemaking tool can work correctly and not simply end-run the regulator. The approaches described in this article have the potential to provide benefits to utility customers.
II. Industry Challenges Each state and region has its own infrastructure needs and would focus its attention on how to best meet those needs. Utility ratepayers would be well served by a regulatory framework and company policies that serve the public interest by minimizing the overall cost of capital, while facilitating investments in needed infrastructure by the regulated utility industry. There are a variety of ways to accomplish this goal. n the current economic climate, we would suggest that there are three major challenges that many electric utilities are now facing: Attrition dilemma. Rates that are adequate for a given ‘‘test year’’ can fall short in succeeding periods given growth in rate base and increasing operating costs, leading to ‘‘attrition,’’ which is the erosion of earnings ‘‘caused by cost of services increasing more rapidly than revenues.’’3 Figure 1 provides evidence that some electric utilities have not earned
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[(Figure_1)TD$IG] 11.00
years. The ability of utilities to fund capital investment is directly dependent on their ability to raise debt and equity in the capital markets. Moreover, most states now have renewable portfolio standards (RPS) or state mandates in place,4 as shown in Figure 3. To meet RPS type mandates, many utilities will need to invest in the infrastructure needed to make use of that renewable energy. Given the nature of these infrastructure investments, some degree of regulatory pre-commitment would likely be appropriate, along with other regulatory building blocks, such as asset trackers and CWIP in rate base with a cash return. Credit quality constraint. Electric utility credit ratings are generally above investment grade, but remain weak by historical standards. Figure 4 shows the S&P bond ratings for electric utilities.5 The sharp
Return on Equity (%)
10.50
10.00
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9.00
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8.00 2006
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2008
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Year Earned ROE
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Figure 1: Allowed ROE vs. Earned ROE (2006–2010)
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goals and major challenges that face the electric utility industry— and extensive cap ex construction programs can exacerbate a utility’s attrition problem. Figure 2 shows that the cap ex plans of utilities are ambitious, requiring the raising of significant new capital over the next few
[(Figure_2)TD$IG] 80
70
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2011E
2012E
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Total Capital ($ Billions)
their allowed ROE in recent years. With few exceptions, all of a utility’s activities are aimed at meeting its obligation to serve customers and, therefore, the legitimate costs incurred by a utility as part of its efforts to meet the needs of its customers would be recoverable in rates. With appropriate incentives in place, there is a strong presumption that all of a utility’s costs will be incurred to meet the utility’s obligation to serve. While there is no guarantee that a utility will actually be able to earn its cost of capital once rates have been set, if rates are set such that the utility does not have a realistic opportunity to recover its costs, harm to customers will likely result in the longer run, if not sooner. Capital expenditure challenge. Infrastructure investment in generation, transmission, and distribution plant would be needed to meet the ambitious
60
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0 2004
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Year Source: Regulatory Research Associates (SNL Energy), Financial Focus Special Report, Capital Expenditures, May 6, 2011
Figure 2: Total Capital Expenditures for 44 Companies (Historical and Forecast-$ Billions)
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[(Figure_3)TD$IG]
AK WA
ID
WI
AZ
KS OK
NM
MI PA
IL
CO
VT NH MA NY CT RI
IA
NE
UT
CA
MN
SD
WY NV
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MT
OR
MO
IN
WV
VA
KY
NJ DE MD DC
NC
TN AR
SC MS
TX
OH
AL
GA
LA FL
HI
Source: Energy Information Administration, Renewable Energy Trends in Consumption and Electricity 2008.
Figure 3: States with Renewable Portfolio Standards, 2008
recovery methods would be a necessary part of that balanced approach. The ability of utilities to fund capital investment is directly dependent on their ability to raise debt and equity in the capital markets. Under current market conditions, it would be relatively more difficult for utilities to raise funds in the debt market, and
decline in electric utility credit quality (relative to 2001 levels) begs the question of whether the industry and its regulators will together be able to find ways to implement the nation’s grid modernization, energy independence, and environmental goals in a timely and efficient manner. Timely rate
[(Figure_4)TD$IG] Electric Utility Bond Ratings 1965-2009 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 1965
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1975
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A- or higher
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Sources: Leonard Hyman and EEI.
Figure 4: Electric Utility Bond Ratings (1965–2011)
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when they do so, it would be at a higher cost than it would have been with a bond rating of ‘‘A-/ A300 or higher. tility ratemaking should not prevent a utility from earning an adequate return on its investment in serving the public. Attrition, which is typically discussed in the context of the combined effects of inflation and large-scale construction programs on a utility’s opportunity to actually earn its allowed ROE, should not lead to a public utility being prevented from having a reasonable opportunity to recover its prudently incurred costs, including the forward-looking cost of capital. Leonard Saul Goodman points out that‘‘[i]f attrition is an economic factor truly beyond the company’s control, and if it is a proper cost in a transitional inflationary period, there is
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unfairness in placing the entire burden of the cost on shareholders.’’6 A close reading of this comment suggests that: Economic factor truly beyond the company’s control. Infrastructure costs aimed at achieving ‘‘energy independence’’ can be considered to be a type of mandated cost, with the initial decision to construct beyond the control of the utility. To meet RPS mandates, utilities will need to invest in infrastructure and some degree of ‘‘preapproval’’ of the initial decision to construct can be justified. A proper cost. Note that the utility would continue to have control of its execution of the project and therefore would face prudence scrutiny with respect to the mandated investment. Unfairness in placing the burden entirely on shareholders. With respect to the traditional regulatory ‘‘balancing act,’’ efforts to ameliorate the economic effects of attrition by providing more timely cost recovery can be beneficial to both utility customers and investors. This is because utility customers’ rates will reflect the weighted cost of the utility’s debt, preferred stock, and common equity—and use of the regulatory building blocks can potentially reduce these capital costs. he traditional standard to justify the suitability of a fuel adjustment mechanism is whether the cost of the purchased item is beyond the control of the utility, large, and volatile.7
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Applying an analogous ratemaking approach to mandated infrastructure investments can potentially make sense from a public policy perspective. After all, the cumulative effect of numerous ratemaking adjustments should not prevent a utility from having the opportunity to earn a compensatory return on capital. Absent imprudence, a public utility should not face a persistent
An important element in this demonstration is being able to point to a supportive regulatory environment. inability to recoup its costs of providing utility service. Put more positively, a utility should be given a reasonable opportunity to realize an adequate rate of return and thereby be assured of access to the capital markets at a reasonable cost—because customers would benefit.
III. Regulatory Building Blocks The focus of utility regulation should always be on consumers, with regulation ensuring that the rates paid by utility customers are just and reasonable, based on
prudently incurred costs. Given that regulated electric utilities must be able to raise substantial amounts of both debt and equity capital in order to fund investment in long-lived, specialized assets, utilities must be able to demonstrate that they have the financial standing and resources needed to raise capital at a reasonable cost, in good markets and bad, in both the short and long terms. An important element in this demonstration is being able to point to a supportive regulatory environment. he purpose of this section is to review key regulatory building blocks that can accommodate regulatory approaches that result in more timely recovery of costs. These building blocks include such regulatory practices as: FERC Form 1 accounting statements. Effective regulation of any form requires that regulators define the consistent, durable, and transparent accounting procedures to be used by regulated utilities. The early history of regulation in the U.S. was characterized by notorious accounting abuses, including overstated expenses, unverifiable investments in plant and equipment, a lack of separation between utility and non-utility businesses, and overcapitalization. Such abuses were ended with the adoption, in 1938, of the Uniform System of Accounts by the federal government.8 The goals of good regulation are frustrated when the lack of detailed and reliable
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accounting data obstructs the regulator’s ability to periodically assess the cost of service.9 For example, the Uniform System of Accounts rarely leaves U.S. energy utilities and their regulators in dispute over basic financial issues such as profitability, depreciation expenses, customer contributions, incurred operating costs, or the treatment of unregulated affiliates. Rate cases instead focus on how these costs should be recovered for ratemaking purposes. Adjustment mechanisms. Infrastructure recovery mechanisms, also known as ‘‘asset trackers’’ or ‘‘riders,’’ are roughly analogous to the adjustment mechanisms that are used to pass through the costs of fuel and purchased power. Regulatory Research Associates (RRA) explains that ‘‘from an investor standpoint, this is the preferred treatment, as adjustment clauses can allow for more timely rate recognition of incremental CWIP.’’10 Asset trackers or similar adjustment mechanisms allow for more-timely recovery of rate base additions than would be the case with traditional rate cases. Operating and maintenance expense (O&M) riders or trackers of various sorts, such as bad debt riders or regional cost riders, could also be used. Adjustment mechanisms have been used by regulators since the early days of the industry.11 CWIP in rate base with a cash return. As commissions and utilities grapple with questions of how best to invest in the utility infrastructure needed to
accommodate public policy goals, allowing CWIP in rate base with a cash return has once again become a standard part of the regulatory toolkit. As the industry proceeds with the ongoing construction cycle, legislatures and regulators have begun to allow CWIP in rate base for a cash return, sometimes restricted to only certain designated types of
plant, i.e., transmission or certain types of generation.12 RRA reports that 16 states have permitted a cash return on CWIP in recent years and that eight of the states that allow CWIP in rate base with a cash return also allow asset trackers to be used.13 Given that an allowance for funds used during construction (AFUDC) need not be recovered in rates, using this approach reduces the total cost to customers. Inflation adjustments. Attrition is the persistent inability to recover the real costs of providing utility services. To mitigate the impact of attrition, regulators use inflation adjustments in a variety of ways including attrition allowances, fully forecasted test years,
projections of cost items, true-up of projected and actual costs, and formal price cap plans (inflation minus an x-factor). Generally, inflation adjustments can help maintain rates at levels that provide a utility with a reasonable opportunity to recover its costs, including the cost of capital. Cap ex budgeting. All investorowned public utilities have some type of capital expenditure budgeting process in place to prioritize the many alternative infrastructure investments that could be made. In a few states, ex ante cap ex budgeting information is formally provided to the utility regulator, while, in other cases, less formal procedures are used to keep the regulatory agency informed. Either way, the cap ex budgeting process can build a foundation for recovering utility costs in a timely manner. hese building blocks can aid in the establishment of regulatory practices that support investment in utility infrastructure, which can, in turn, aid in meeting RPS requirements and other state goals.14 The regulatory process has safeguards (e.g., prudence reviews) to assure that tariffed rates remain at a just and reasonable level. Consistent with the regulatory compact, which provides a means of balancing the competing interests of utility customers and the investor–owners of public utilities, these tools can be used to respond and adapt to changes in customer, industry, and market conditions.
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IV. Some Solutions to the Attrition Problem Utility ratemaking is conducted on a case-by-case, fact-specific basis. While the details vary somewhat from state to state, the basics of the ratemaking process are largely the same. For any given jurisdiction, the overarching framework of utility regulation—the ‘‘end result’’15— is likely what is most important to investors.16 Under the Hope standard, ‘‘[i]t is not theory but the impact of the rate order which counts.’’17 tility commissions necessarily have discretion, consistent with their statutory authorization, to revise regulatory policies and procedures. Thus, for example, commissions can typically decide whether to use a fully forecasted test year, a partially forecasted test year, or a fully historic one; a test year can be adjusted for attrition and/or known and measurable changes in costs. The comprehensive state-level regulation of electric utilities is based on a regulatory compact that provides an economic framework that supports major capital investments in assets with very long useful lives. If utility price signals are more efficient when a more cost-reflective test year is used, for example, regulatory policies can be adjusted to accomplish this, consistent with the commission’s statutory authority. The purpose of this section is to review several regulatory approaches that can be
considered ‘‘standard’’ public utility regulatory methods and that may be especially well suited to meeting current challenges. A. FERC formula-rate transmission ratemaking Formula-based approaches— and other regulatory building
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blocks—can be used to set just and reasonable rates, based on prudently incurred costs. The FERC’s formula rate approach is a useful example of how to achieve timely rate recovery, while maintaining traditional regulatory oversight of utility rate levels. The FERC’s approach relies crucially on applying FERC Form 1 data in a formula-based ratemaking approach. Some of these formula-rate plans use prior-year FERC Form 1 data to calculate rates for the upcoming year, while other plans use projected rates, which are then trued up when actual costs are known, with over-collections returned to customers with interest.18
FERC’s approach has a number of advantages including: Keeping rates at levels that are close to the cost of service. This largely avoids the possibility of ‘‘overearning’’ by the utility. Rates are maintained at costbased levels, without the need for frequent full-blown rate cases. This is a sharp contrast to the FERC ratemaking approach for gas pipelines, where gas pipelines can ‘‘over-earn’’ for extended periods of time (paid for by electric utilities and gas local distribution company customers, among others), with the FERC staff only investigating if the earned ROE is over 20 percent.19 Accommodating various types of incentives. Various types of incentives can be accommodated within the FERC’s framework. Orders 679 and 679-A established the procedures by which electric transmission owners can receive incentive-based rate treatment.20 Under FERC Order 679, incentives available to jurisdictional public utilities include ROE incentives, CWIP in rate base with a cash return, hypothetical capital structure, accelerated depreciation, recovery of costs of abandoned facilities, and deferred cost recovery. FERC’s various incentive measures typically garner more attention than does its formula rate approach. Credit quality. Credit quality is a statutorily required criterion in FERC’s determination of a formula-rate plan.21 FERC has, example, considered Westar’s ‘‘BBB-’’ credit rating when
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approving formula rates,22 an example of a regulatory commission using its discretion to support a utility whose credit rating was on the verge of dropping below investment grade.23 The FERC’s formula rate approach can incorporate accelerated depreciation for ratemaking purposes, CWIP in rate base with a cash return, and an asset tracker approach, all of which can support a utility’s credit standing. Inflation adjustments. Standard ratemaking practice makes use, in a variety of ways, of inflation adjustments to actual costs. Whether it is an attrition adjustment, use of a fully forecasted test year, projections of variable costs, a formal price-cap (inflation minus an x-factor) plan, or some other regulatory use of an inflation adjustment, standard practice accommodates ratemaking adjustments based on anticipated inflation. Adjustment mechanisms, such as FERC’s formula-rate approach, can build in true-ups of projected and actual costs. Administrative efficiency. FERC has a large and diligent accounting and auditing staff and thus can be assured that the FERC Form 1 data is accurate and reliable. Thus, FERC’s formularate approach can be implemented in an administratively efficient way. FERC regulates a large number of transmission entities, and, to prevent a logjam, needs to have administratively workable ratemaking procedures in place.
Nevertheless, the timing and procedural protocols provide enough time for interested parties to review the data filed by the transmission entity and to submit information requests.24 tate commissions regulate a smaller number of companies, but the rate-caseevery-few-years paradigm may currently not work well in all
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on a divided record. Thus, settlements have a useful role to play.25 Con Ed has, in recent years, borne a cap ex budget of well over $1 billion dollars per year, which is aimed at investing in distribution infrastructure needed to meet its obligation to serve. The Con Ed settlement ‘‘hardwires’’ a three-year cap ex program of roughly $1.4 billion per year into a three-year rate plan, with rate increases of $540.8 million, $306.5 million, and $280.2 million, respectively.26 The New York commission has an ex ante cap ex review process in place, which may accommodate more timely ratemaking treatment of infrastructure investment. ith settlements, one does not necessarily know all of the tradeoffs involved, only the end result. In some contexts, settlements can make the ratemaking process less transparent because the commission may not rule, for example, on what it believes to be a reasonable capital structure and cost of equity and thus a stipulation can become opaque, a black box. That need not be the case however and, indeed, is not the case with Con Ed. Integrating a three-year cap ex program into the setting of rates for those years provides an opportunity to raise rates in a stable and predictable way, rather than rely on one-time adjustments via occasional fullblown rate cases. Con Ed’s threeyear cap ex rate plan provides a good ratemaking model, as does
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instances. Among other things, state commission administrative resources are constrained in an era of tight budgets. Most states commissions have ‘‘annual report’’ filing requirements, akin to the FERC Form 1, which would accommodate the use of a formula-rate approach. B. Con Ed distribution rate settlement Rate settlements or stipulations are a standard part of the procedural repertoire used to conduct public utility rate regulation. Settlements are a way to forge consensus on issues that would otherwise have to be decided by the regulator, based
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the settlement process used to achieve that outcome. C. Peoples Gas pipe replacement tracker A well-designed and implemented asset tracker for qualified infrastructure investments benefits customers. The basic idea would be to recover the costs of ‘‘qualified’’ infrastructure investments incurred between rate cases through an asset tracker. The definition of qualified investments varies. For example, the definition for The Peoples Gas Light and Coke Company (‘‘Peoples Gas’’) infrastructure cost recovery charge (ICR charge) focuses on qualified additions associated with replacing aged facilities that have not previously been included in rate base.27 Under an alternative approach used in New Jersey,28 job creation and economic impact are the main criteria used to target cost recovery on an expedited basis.29 A definition of ‘‘qualified’’ infrastructure investments might include capital expenditures that benefit many customers, are relatively large in size, and that go beyond the ordinary expansion of distribution facilities. he Peoples Gas ICR charge was implemented in the context of a desire to ensure timely replacement of aging and possibly unsafe gas infrastructure. Further, the tariff notes that there is a savings of $6,000 per mile from abandoning aged cast iron pipe.30 Actual
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savings are reconciled to this estimate every three years. Hence, the program was implemented as an incentive for what was considered to be a desirable investment from safety, reliability, and economic perspectives. An infrastructure recovery mechanism, or asset tracker, is attractive from a public policy
perspective for numerous reasons. Accommodate more timely recovery of new plant costs. By ensuring timely recovery, a tracker may make timely investment in facilities more feasible. Rates would ordinarily go up in conjunction with capital expenditure completion and commercial operation but that would be accomplished in a relatively stable and predictable fashion given the cap ex review process. An asset tracker can be implemented in conjunction with CWIP in rate base with a cash return, which would further accelerate and smooth rate impacts. In terms of rate stability, if some AFUDC
accruals can be avoided or minimized, that would help keep rates low. Support financial integrity. An asset tracker can support a public utility’s ability to raise new capital, thereby easing the financing of capital expenditures. Over time, this would tend to improve credit quality and benefit customers via a lower cost of capital. Administrative safeguards. Procedures could be put in place to ensure that the commission has the timely opportunity—and necessary information—to ensure that the asset tracker is working as intended, thereby benefiting customers. For example, Peoples’ internal auditors must certify each year that the ICR has been properly implemented, and there must be an independent external review every five years.31 The Peoples asset tracker mechanism, which places assets into rates in a timely matter, but leaves most of the review process to the reconciliation stage of the case, provides a reasonable ratemaking model. Other approaches can, of course, be used as well. The Peoples Gas Rider ICR mitigates regulatory lag for qualified capital expenditures. Rather than spending and then waiting for commission approval to recover the costs, the utility is afforded the opportunity to spend, recover, and then wait for a retrospective prudence review. From a credit quality standpoint, however, the regulatory implementation of the
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2010 Peoples Gas rate case order represents a missed opportunity to enhance the utility’s ability to raise debt at a low cost.
V. Traditional Rate Cases and the Regulatory Building Blocks While ratemaking procedures will vary on a state by state, case by case basis, regulators’ primary regulatory ‘‘tool’’ for overseeing a utility’s tariffed rates is the traditional rate-of-return/cost-ofservice rate case, which provides the regulator with a forum for investigating and determining the justness and reasonableness of the utility’s rates and the prudence of its capital and operating costs. Figure 5 shows that rate case activity surged during the middle- to late-2000s following a period of relative inactivity during the late 1990s and early 2000s.34 Through June 30, 2011, 39 rate cases have been filed compared to a total of 60 for 2010.35 Using a ‘‘test year’’
revenue requirement, the regulatory agency examines the reasonableness of the utility’s sales growth projections, rate base, operating expenses, cost of capital, and other cost components, and then sets rates that provide the utility a reasonable opportunity to recover its prudently incurred costs—this is the core of the traditional public utility ratemaking regulatory bargain. regulator’s ability to disallow imprudently incurred costs provides crucial regulatory oversight over the utility’s management of its operations. A utility’s costs are held to a ‘‘reasonableness’’ standard, not an ‘‘ideal’’ standard of perfection or optimization. In setting rates that are just and reasonable, the required ratemaking approach is to provide the utility with an opportunity to recover the prudently incurred costs (including a fair rate of return on capital) of providing utility services to customers. In
A
[(Figure_5)TD$IG] 80 70
Number of Rate Cases Filed
Peoples Gas ICR has a major drawback. The mechanics of the Peoples Gas infrastructure tracker are sound, but the ‘‘quasi-debt’’ rate allowed for Rider ICR assets may effectively prevent Peoples Gas from improving its credit quality, at a time when it must raise new capital to fund cap ex programs. Providing only a quasidebt return implies that the ‘‘tracked’’ assets require a lower allowed ROE than non-tracked assets, but the cost of capital is a function of the use to which it is put and is not a function of the specific rate treatment provided those assets.32 roviding only a quasi-debt return makes it more difficult for the company to maintain the coverage ratios needed to maintain or improve its credit rating. Peoples Gas had lost it’s ‘‘A-’’ credit rating from S&P (it has an ‘‘A3’’ rating from Moody’s) following its previous rate case, with those lower ratings affirmed subsequent to the February 2010 rate case decision. In explaining its downgrade, S&P noted that its assessment was based, in part, on its ‘‘assessment of the Illinois regulatory environment which we place in the least credit supportive category.’’33 This rate case did not put Peoples Gas back on the road to meriting an ‘‘A-’’ credit rating. It is a mistake to view an asset tracker in isolation—credit rating agencies generally focus on the regulatory compact in the state not on relatively narrow aspects of ratemaking procedure—and thus this aspect of the February
60 50 40 30 20 10 0 2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
Year Source: Regulatory Research Associates
Figure 5: Number of Rate Cases Filed, 2000–2010
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examining the prudence of a utility’s costs, the regulator considers the costs in relation to a ‘‘reasonable man’’ standard—the costs must be reasonable in comparison to the costs that would result from reasonable utility practice. Any prudence determination should be based on whether the decisions at the time they were made were reasonable under the then existing circumstances. For a utility, prudence is reflected in the decision a reasonable utility management would make at the time the decision is required, and must remain free of any hindsight. If a prudent decision turns out badly, the bad outcome does not by itself demonstrate a lack of prudence.36 Fairness requires that any imprudence be demonstrated objectively so that there will not be uncertainty about the regulatory decision. Evidence of failure to act prudently must be well grounded in law, economics, and public policy. ome prudently incurred costs (e.g., charitable contributions,37 executive incentive compensation, and advertising expenses) are frequently excluded from a utility’s revenue requirement, even if they are legitimately incurred costs. Prof. Alfred E. Kahn, when he was chairman of the New York State Public Service Commission, expressed the view that ‘‘heated discussions’’ about advertising ratemaking policy were a ‘‘tempest in a teapot,’’ both because the dollars were small
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and because disallowing advertising expenditures under the ‘‘glib assumption that these costs will then be borne by stockholders rather than ratepayers, is something of a sham.’’38 Prof. Kahn went on to explain that the: [E]ssential fraudulence of our purporting to exclude from rates
expenditures for advertising that company managements will continue to feel it necessary to make: since we made every effort to set the allowable return on equity at the minimum cost of capital, and most of the companies we regulate are not earning even that, in principle putting any advertising expenditures ‘below the line’ can only mean, if we are honest, increasing the allowed return on equity, in order to enable these companies to raise the capital they need on reasonable terms.39
This problem could be addressed directly, by revisiting commission policies and precedent on the ratemaking treatment of these costs. Unfortunately, however, this rarely occurs, which makes a direct solution to the problem
difficult to achieve. The regulatory approaches described in this paper do not solve this problem, but would provide an indirect way to deal with the attrition problem, large cap ex programs, and bond ratings that are weak by historical standards.
VI. Conclusion The standard approaches described in this article can be used to meet the challenges that the electric utility industry currently faces. While the details of utility regulation in the state are no doubt important, there are a variety of regulatory policies and mechanisms that can be used to set utility rates. Regulatory approaches which might not be viewed as quite as favorable to investors, might, in practice, be well-suited to the specific situation in a given state and therefore be considered to be acceptable. It is the end result that matters when regulatory institutions apply the regulatory compact. Utilities must have incentives that lead them to maximize customer benefits—so that customers receive efficient, safe, adequate, and reliable service both now and in the future. A utility’s economic incentives will be better when rates to customers reflect the utility’s true cost of providing service. Allocative efficiency refers to the prices that customers face. Allocatively efficient utility rates would give customers the
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economically correct price signals to use electricity or gas or not, depending on the customer’s choice. Failure to allow appropriate costs to be included in the utility revenue requirement distorts this efficiency, since customers are receiving an inaccurate price signal. Productive (or technical) efficiency refers to the incentives that the utility faces as it decides how to provide its services. The utility should have the incentives to operate in an efficient manner, while also continuing to provide safe, adequate, and reliable service. With appropriate incentives in place, few if any costs should be excluded from the utility’s tariffed rates—the utility will be focused on fulfilling its obligations to its customers. Investment incentives are the dynamic aspect of productive efficiency. The utility must have the incentive to efficiently invest in infrastructure. An inability to recover its costs could distort the utility’s investment incentives. Where credit quality concerns remain a significant deterrent to utility investment in infrastructure on behalf of customers, ratemaking treatments that provide more timely and regular recovery of costs may prove useful.&
Endnotes: 1. Utility regulation may, in part, be a ‘‘method of promoting the expansion of infrastructure services.’’ Richard A. Posner, Taxation by Regulation, BELL J. ECON., Spring 1971, at 39–41.
2. Title XIII of the Energy Independence and Security Act of 2007 (‘‘EISA07’’) declares that ‘‘it is the policy of the United States to support the modernization of the Nation’s electricity transmission and distribution system to maintain a reliable and secure electricity infrastructure that can meet future demand growth’’ and ‘‘achieve [the 10 items], which together characterize a Smart Grid.’’ At 292–293. 3. Robert L. Hahne and Gregory E. Aliff, ACCOUNTING FOR PUBLIC UTILITIES
Competitive Markets, National Regulatory Research Institute, Nov. 1991, at 9. 8. These accounts are firmly embedded within the practices of the accounting profession in the U.S. and are not capable of being amended or changed, as a practical matter, without the scrutiny and approval of the U.S. accounting profession’s standards board. 9. Outside the U.S., many regulatory jurisdictions still lack access to reliable and useful accounting data. 10. RRA, Construction Work in Progress: A State-by-State Policy Overview, April 7, 2009, at 1–2. 11. Adjustment mechanisms may have been unusual in 1918, when the Pennsylvania Public Service Commission characterized them as such, but they are not unusual today. See R.S. Trigg, Escalator Clauses in Public Utility Rate Schedules, UNIV. OF PENN. LAW REV., May 1958, at 964.
(Newark, NJ: Matthew Bender, 2001), at 8–3. 4. U.S. Energy Information Administration, Renewable Portfolio Standards and State Mandates by State, 2008, Aug. 2010, at http:// www.eia.gov/cneaf/ solar.renewables/page/trends/ table28.html. 5. See Leonard Hyman, AMERICA’S ELECTRIC UTILITIES: PAST PRESENT AND FUTURE, 2nd Ed. (Arlington, VA: PUR, 1985), at 263. See also Leonard Hyman, A.S. Hyman, and R.C. Hyman, AMERICA’S ELECTRIC UTILITIES: PAST PRESENT AND FUTURE, 8th Ed. (Vienna, VA: PUR, 2005), at 432. For recent data, see Edison Electric Institute, Quarterly Financial Updates, various dates. 6. Leonard Saul Goodman, THE PROCESS OF RATEMAKING, Vol. I (Vienna, VA: PUR, 1998), at 638. 7. Robert Burns, Mark Eifert and Peter Nagler, Current PGA and FAC Practices: Implications for Ratemaking in
12. RRA goes on to summarize the policy rationale for including CWIP in rate base, explaining that: ‘‘[i]nclusion of CWIP in rate base is generally viewed favorably by investors. Such treatment allows the utility to collect a cash rate of return on the asset while it is under development. The associated cash flow may reduce the amount of utility financing necessary during the construction program and enable a utility to receive more favorable consideration from the credit-rating agencies, thus reducing the utilities cost-of-capital going forward. Additionally, since including CWIP in rate base effectively ‘phases in’ the related investment, such treatment will reduce the ‘rate shock’ that might otherwise be experienced by the ratepayer when the plant or project is completed and placed into service and then reflected in rates in one step.’’ RRA, supra note 10, at 1. 13. Id., at 1–2. 14. For a 50-state survey of RPS standards, see American Bar Association, Report of the Renewable Energy Committee, Section of Public Utility, Communications and Transportation Law, Spring 2011.
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15. Per Hope, under the ‘‘just and reasonable’’ standard, ‘‘it is the result reached not the method employed which is controlling.’’ 320 U.S. 591 (1944). 16. See Wayne P. Olson, At a Crossroads: Modernizing Utility Infrastructure in a Tough Credit Environment, ELEC. J., Aug./Sept. 2009, at 6–26. 17. Hope, supra note 15. 18. Public Service Electric and Gas Company (PSEG), 123 FERC P 61303, 2008 WL 4416764 (FERC), Sept. 30, 2008.
25. Zhongmin Wang, Settling Utility Rate Cases: An Alternative Ratemaking Procedure, J. REGULATORY ECON., 26:2, 2004, at 141–163. 26. Before the New York Public Service Commission, Proceeding on the Motion of the Commission as to the Rates, Charges, Rules and Regulation of Consolidated Edison Company of New York, Inc. for Electric Service, Order Establishing Three-Year Electric Rate Plan, Case 09-E-0428, Mar. 26, 2010, at 3, 10–15.
19. Of the five most recent FERC rate investigations, the lowest earned ROE was 20.83 percent for Great Lakes Transmission. This leads to the conclusion that the effective threshold to warrant investigation by the FERC was about 20 percent.
22. Westar Energy, Inc., 122 FERC ô 61,268 (2008), Para. 47. 23. Olson found that ‘‘there is considerable evidence that the rate orders for ‘‘BBB-’’ utilities pay careful attention to credit quality when setting rates.’’ Olson, supra note 16, at 17. 24. PSEG, supra note 18.
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31. Peoples Gas, supra note 27, at 9. 32. Richard Brealey and Stewart Myers, PRINCIPLES OF CORPORATE FINANCE, 1st Ed. (New York: McGrawHill, 1981), at 158. 33. S&P, ‘‘Peoples Gas Light & Coke Co.,’’ Mar. 18, 2009, at 2. 34. During the 1990s, rates were frozen in a number of jurisdictions because of settlements and litigated proceedings related to mergers, alternative rate plans, and the introduction of retail competition. See Hethie Parmesano and Jeff D. Makholm, The Thaw: The End of the Ice Age for American Utility Rate Cases—Are You Ready? ELEC. J., July 2004, at 69. 35. Regulatory Research Associates, at http://www.snl.com/InteractiveX/ RateCaseHistory.aspx.
20. Promoting Transmission Investment through Pricing Reform, Order No. 679, FERC Stats. & Regs. ô 31,222 (2006) (‘‘Order No. 679’’); order on reh’g, Order No. 679-A, FERC Stats. & Regs. ô 31,236 (2006) (‘‘Order No. 679-A’’); order denying reh’g, 119 FERC ô 61.062 (2007). 21. 16 U.S.C. 824s (2006). Section 219 of The Energy Policy Act of 2005, 119 Stat. § 594 1241 (2005), amended the FPA. Specifically, § 824s specifies, among other things, that the FERC transmission infrastructure investment rule shall promote reliable transmission and generation by ‘‘promoting capital investment’’ in transmission infrastructure and provide an allowed return on equity that ‘‘attracts new investment in transmission facilities.’’ See http://www.law.cornell.edu/ uscode/16/usc_sec_16_00000824— s000-.html.
30. Peoples Gas, supra note 27, at 8.
27. Peoples Gas, Rider ICR, Infrastructure Cost Recovery, Ill.C.C. No 28, Fifth Revised Sheet No. 130, Feb. 17, 2010. 28. Before the New Jersey Board of Public Utilities, In the Matter of the Proceeding for Infrastructure Investment and a Cost Recovery Mechanism for all Gas and Electric Utilities, Decision and Order Approving Stipulation, Docket No. EO09010049, April 28, 2009, at 3, 10–15. 29. New Jersey’s economic stimulus plan, which sought to moderate the effects on New Jersey of the world economic downturn that followed the 2008 financial crisis, continues in operation, with companies required to file quarterly compliance reports. See, for example, South Jersey Gas, Capital Investment Recovery Tracker Quarterly Report in Compliance with the Board’s Order in Docket No. GO09010051, May 2, 2011.
36. When challenging the prudence of management on the basis of a bad result, care is needed because the regulatory agency already has one piece of information that utility management did not, and could not, have at the time the decision was made. The evaluation of prudence must be based on what a reasonable utility would have known at the time the costs were being incurred, not based on 20/20 hindsight, long after the costs were incurred. 37. The Economist, in a special supplement on precisely this issue, points out that ‘‘for strictly selfish reasons, well-run companies will strive for friendly long-term relations with employees, suppliers and customers. There is no need for selfless sacrifice when it comes to stakeholders. It goes with the territory.’’ The Good Company, ECONOMIST, Jan. 22–28, 2005, at 11. 38. Prof. Alfred Kahn as quoted in Richard Pierce, Jr., Gary Allison and Patrick Martin et al., ECONOMIC REGULATION: ENERGY, TRANSPORTATION AND UTILITIES (New York: BobbsMerrill, 1980), at 142. 39. Id.
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