In the aftermath of the Arab oil embargos of the 1970s, state utilities regulators were faced with challenges similar to those faced by their counterparts today: The need to create a regulatory framework that provided incentives to electric utilities to invest in energy sources other than oil, to support new environmental protection requirements, and to vastly improve the efficiencies of energy production, delivery and usage in the United States. Then, the issue was very concrete: a fuel shortage. Today, the cause is more amorphous and controversial: climate change. Despite strikingly different drivers, today’s response echoes the previous ones. That is, encouraging diversification of fuels and greater efficiencies.
In some ways, not much has changed in the past 30 years: State utility regulators then, as now, had as their core mission balancing ratepayers’ need for reasonably priced and reliably delivered electric service with electric utilities’ need for an opportunity to recover costs plus profit for investments made in providing that service. Then, as now, electric utilities faced uncertainties regarding whether their capital costs would be recoverable; public utility commissions (PUC) had statutorily defined processes for reviewing utility applications for rate adjustments and for making regulatory decisions; and key stakeholders in those processes included state regulators and electric utilities. In that era of policy movement away from pure monopoly regulation, consumer counsels emerged as an institutional voice for residential and small business consumers.
In other ways, changes to the overall structure of the electric utility industry since the 1970s have been significant, posing challenges to state utility regulators and the electric utility industry, alike. With the emergence of scientific and political concerns about climate change and the resulting federal policy mandates, the pressure has increased again to base regulatory decisions on considerations other than reliability, cost and reasonable return.
The mix of new state and federal energy policies has introduced levels of complexity for utility investment decisions and political risk for utilities and for state regulators. These energy policies, which apply in a patchwork across the country, include renewable portfolio standards (RPS), retail restructuring, competitive wholesale electricity markets, open access to transmission lines, and state and regional carbon cap-and-trade programs Added to this mix is the development of smart-grid technologies spurred by federal funding, numerous pilot projects, and the establishment of a framework for interoperability standards.
So, have PUCs changed to meet the new challenges? In much the same vein as Fortnightly’s effort to gather insights about the effects of legislative and regulatory mandates on the electric utility industry (November 2009),1 the authors interviewed 14 sitting and former state utility commissioners, consumer counsels, and electric utility representatives to gain insight into the implications of federal and state mandates for PUC operations, processes, and priorities. Similar to Fortnightly’s finding that “the industry’s policy transition has only just begun,” these conversations revealed that the most recent round of federal and state policy changes have only just begun to affect PUCs’ operations, but that the experiences from the 1970s inform the changes today. In many instances, however, these more recent mandates already have affected regulators’ discretion to craft an appropriate balance of consumer and utility interests—their historical core responsibility.
Perhaps the most notable manifestation of a more circumscribed regulatory role is the treatment of cost recovery.
In two areas, state utility commissions historically had, and continue to have, adjudicatory responsibilities with respect to jurisdictional electric utilities: 1) the determination of need for new capacity in states with traditional retail markets; and 2) decisions on rate changes. Both functions involve balancing consumers’ needs for reliable and affordable power with the opportunity for utilities to recover prudently incurred costs.
Electric utilities seek predictability in the regulatory process to safeguard investments in new capacity and improve their credit ratings. Recently, declining creditworthiness and credit ratings among electric utilities has caused concern as utilities embark on a new round of large generation and transmission projects. Eric Ackerman, director of alternative regulation for EEI, observes that regulators and ratepayers alike should be concerned, because utilities will need to pay more to borrow money, and because a lower credit rating reduces utilities’ capacity for absorbing economic adversity before falling below investment grade. He likened strong credit to insurance against an uncertain future, noting that the credit contraction of late 2008 and early 2009 demonstrated that utilities aren’t guaranteed access to investor capital, however much they might need it. The cost of borrowing for prudent investments traditionally has ended up in revenue requirements. Paul Bonney, general counsel and vice president of regulatory affairs at PECO, echoes that sentiment by observing that, in their capacity as policymakers, regulators should develop clear policies and stick to them. Bonney notes that consistency in policy is critical, among other reasons, because “Wall Street looks for certainty in determining where to direct capital.”
Nowhere has the quest for greater predictability been more pronounced than in consideration of allowing accelerated cost recovery, such as construction work in progress (CWIP). To improve predictability and encourage investment in new nuclear plants and transmission facilities, state legislatures and PUCs have adopted measures in recent years to authorize accelerated cost-recovery mechanisms.2 Though North Carolina’s commission allows a utility to include CWIP associated with a baseload facility in rate base and adjusts rates accordingly in a general rate case, utilities argue that this cost-recovery mechanism might not be sufficient to induce investments in new nuclear capacity, according to former North Carolina Commission Chair, JoAnne Sanford.
Other mechanisms to reduce uncertainty for electric utilities have been devised. Predetermination of ratemaking principles, which are authorized in state laws in Kansas, Iowa, and Wisconsin, add predictability to cost recovery for investments in new generation facilities. Several states, including Florida, Georgia, Iowa, Mississippi, North Carolina, and South Carolina, also authorize electric utilities to recover prudently incurred costs even if they ultimately abandon a new nuclear project. Like CWIP, the ability to recover costs for abandoned projects shifts risk from shareholders to ratepayers if the plant ultimately isn’t constructed or is constructed and doesn’t become commercially viable.
In order to achieve greater certainty, PECO’s Bonney sees a growing role for state utility regulators to work collaboratively with utilities. In certain instances, regulators will be implementing state and federal policies. In others, such as determining how new conservation and renewable generation requirements might be met, regulators might be involved in developing policy.
A level of certainty is created for utilities by use of cost-recovery trackers. Because regulatory lag introduces a modicum of cash-flow uncertainty for utilities, one measure of streamlining cost recovery and thus reducing uncertainty is achieved by applying pass-through cost-adjustment mechanisms, also referred to as “trackers.” Costs recovered through trackers may be reconciled or trued up during a full rate case. Historically, trackers took the form of fuel-cost adjustment clauses or tax-adjustment clauses to capture revenues necessary to comply with fluctuating fuel prices or changes in tax policies. In recent years, a growing number of commissions and state legislatures have authorized the use of trackers for other purposes. Trackers now are used to expedite cost recovery for environmental improvements, energy efficiency and energy conservation programs, smart-meter deployment, compliance with renewable portfolio standards, vegetation management, upgrades to transmission and generation facilities, and expenditures associated with storm response.
States vary in the intensity of their use of trackers. And there’s no consensus as to whether overall they provide a net positive or negative regulatory tool. As Pat Wood, former chairman of FERC and the Texas PUC, notes, rate cases are costly and these mechanisms are a means of getting utilities to do what policy makers want them to do.
By contrast, Janine Migden-Ostrander, Ohio consumer counsel, is critical of the expanded use of trackers in her state. She notes that legislation enacted in 2008 authorizes trackers without a requirement that a hearing be held. Sonny Popowsky, Pennsylvania’s consumer advocate, notes that not all trackers are symmetrical. While trackers for fuel and taxes are likely to be symmetrical, capital improvement charges passed through to consumers by trackers likely will rise if they aren’t structured to account for depreciation on existing plants. Popowsky claims that asymmetrical trackers alter the balance of ratemaking, adversely affecting consumers in the process. While trackers have their merits in that they may facilitate the public purpose and expedite infrastructure investments, it’s a good idea for regulators periodically to look at the big picture, according to former North Carolina Chair Sanford.
The use of trackers has had an impact on commission processes, as well as on the magnitude of rate changes. Migden-Ostrander from Ohio says trackers undermine due process because consumer input might not be solicited on a case-by-case basis. As a result, rates increase without the opportunity to review decreased costs that could be netted against the increase to reduce the overall price to consumers. Another threat to due process, in her view, is the use of stipulation agreements and expedited review processes that provide insufficient information and afford consumer counsels little time to review the submitted documentation. Migden-Ostrander contends that cumulatively, these processes result in a shrinking consumer voice.
David Springe, Kansas’ consumer counsel and former NASUCA president, observes that commission staff reviews of expenditures subject to trackers rarely involve assessment of prudency—in part because the volume of trackers has grown rapidly. Chairman Thomas Getz of New Hampshire has much the same observation with respect to RPS trackers: The commission doesn’t determine whether pass-through costs associated with RPS are just and reasonable, only whether utilities have complied with RPS provisions. However, from his perspective, much the same treatment of pass-through mechanisms occurred with PURPA mandates almost 30 years ago.
In recent years, state utility regulators not only have seen their discretion limited by various types of state legislation, but also by federal measures, for example the FERC designation of regional transmission organizations (RTO) and independent system operators (ISO). Those entities now are responsible for determining much of the transmission cost allocation and reliability policies affecting interstate transmission in a significant portion of the nation. Historically, PUCs were responsible for determining transmission cost-recovery mechanisms. With appropriate transmission costs determined by entities other than state commissions, commissioners’ only roles in transmission cost recovery might be at the regional negotiating table—and those regional forums don’t exist in all areas of the country. In addition, there’s no mechanism to support dedicated consumer representation in transmission rate-setting deliberation at the regional level. As Kansas Consumer Counsel Springe observes: “The consumer counsel is often left completely outside the [regional cost allocation] process.” Transmission rates established by RTOs to recover costs associated with transmission facility build-outs typically are passed directly through to consumers.
Proponents of regional recovery of transmission costs view that mechanism as a powerful tool available to accelerate transmission-grid improvements and counteract many other factors that slow such projects: interconnection queuing issues, cost allocation uncertainty, state and local siting obstacles, NIMBY opposition, material and labor shortages and cost increases, stalled federal carbon-reduction legislation, cancelled generation projects, and credit crunches facing transmission owners.3 For PUCs, the treatment of cost recovery for transmission assets reflects a significant shift of authority for the determination of prudency of transmission investments.
Smart-grid deployment, a relatively recent federal initiative, is viewed as either an opportunity to reinvigorate the electric industry or a reason for concern, depending on one’s perspective. Regardless of perspective, implementation of smart-grid technology might be an area in which commissions’ discretion is circumscribed by federal policy direction. The deployment of smart meters and other smart-grid technologies has been accelerated by $3.4 billion in federal stimulus funds, to be matched by industry funding. EEI’s Ackerman observes that smart grids will change the business of electricity in many ways. The fundamental question will be, “is the new technology worth it?” Some of the benefits will be private to the extent they’re meaningful to individual customers (i.e., avoiding peak prices and deferring the need for new capacity investment) and utilities (i.e., reducing meter-reading costs and improving asset utilization). Others will be public in terms of reduced carbon-dioxide emissions, integration of distributed resources, electric vehicles, and better energy security. Either way, a business case needs to be made to justify the benefits. Given the federal impetus, state commissions might not be in a position to assess potential benefits on a case-by-case basis.
Finally, lurking in the background is inchoate climate-change policy. The prospect of federal policy in this area makes for some strange bedfellows, allying coal-using states that oppose mandatory carbon-dioxide emissions controls with states that already have embarked on their own carbon-reduction strategy, for example, the Regional Greenhouse Gas Initiative (RGGI). As Vermont Commissioner and President of NARUC David Coen put it: “RGGI is working well and there is a concern that federal legislation will dumb it down.” Federal policy also is working at cross purposes with itself and certain ongoing state initiatives to provide incentives for the construction of new nuclear plants. In Commissioner Coen’s view, politics at the federal level have put storage of nuclear waste at a standstill. New nuclear plants can’t be licensed without a federal resolution to the storage issue.
The most notable cumulative impact of recent and proposed policy changes is an increase in the cost of electricity. Because federal climate-change policy has yet to unfold, nobody knows exactly the degree to which electricity rates will be affected, but regulators are concerned that consumers in coal-using states can expect to pay much more than their counterparts in states less reliant on coal, if financial penalties are imposed for emissions from fossil fuels. Meanwhile, states with RPS also are driving utilities to add more costly capacity from renewable sources to their supply mix.
In addition, the emphasis on energy efficiency in many states is much more intense than it was years ago. Greater efficiency has a counter-intuitive impact on rates. In the short term, according to Greg Bollom, assistant vice president for energy planning at Madison Gas & Electric, rates for consumers will go up because utilities’ fixed costs must be spread over a smaller customer base. In the short term, there’s also a mismatch between supply and demand. In the long term, greater energy efficiency might result in less capacity being built or purchased.
Initiatives currently are being developed, such as new rate structures and creation of third-party energy efficiency service providers, to better align consumer and utility incentives toward energy efficiency investments. To date, these initiatives haven’t been adopted ubiquitously and outcomes will vary. A successful example of a third-party energy efficiency utility is Efficiency Vermont. Thanks to Efficiency Vermont’s efforts, Vermont has seen negative load growth in recent years, even before the recession, according to Vermont’s Commissioner Coen.
Yet, what works in one state might not work in another. State utility regulators tend to be wary of the one-size-fits-all approach that characterizes FERC and Congressional mandates, and they’re concerned about the implications of such mandates for their ratepayers. Madison Gas & Electric’s Bollom notes that his company provided its consumers with the opportunity to pay more for renewable generation. This approach might not work everywhere: Wisconsin has RPS, the Madison community has a high environmental awareness, and the company is small with a relatively affluent customer base. The use of renewables in the company’s total supply mix is projected to be somewhat greater than 10 percent in 2010, in large part due to the voluntary renewable program. And, Madison customers who can’t afford, or who choose not, to go green may remain with electric rates based on average costs.
Even mandates from surrounding states can present challenges for PUCs. For example, how much of the cost of energy should North Dakota’s ratepayers be asked to pay if an electric utility serves both North Dakota (i.e., with no RPS and relatively cheaper electric rates) and Minnesota (i.e., with RPS and higher rates)? How should costs be allocated among ratepayers in each state?
With changes in the energy industry landscape coming from all directions—state legislatures, FERC, regional entities, Congress, the EPA, interest groups—the balancing act of PUCs has become much more challenging. Given evolving FERC mandates and state requirements governing smart-grid technology, demand response, and renewable and energy efficiency standards, two predictions can be made with some certainty: 1) retail consumers won’t be affected uniformly across the country; and 2) electricity prices will go up.
Perhaps one of the greatest challenges is the management of customer expectations in light of changes necessary to implement new policies. Bollom observes that customers who adopt energy efficiency practices might not understand why their rates continue rising while usage declines. North Dakota’s Commissioner Tony Clark suggests that an emerging appropriate role for state commissions is to be proactive and communicate with consumers and utilities about upcoming energy policy changes. This isn’t an easy task because consumers often are conflicted about their desires. Georgia’s Commissioner Stan Wise describes it this way: On the one hand, consumers want utilities to generate power using renewables, and on the other hand, they often oppose siting of transmission facilities to dispatch those sources.
For those proceedings that still involve quasi-judicial decision making, are consumers active participants? In light of the increased possibility that decisions in rate cases might result in rapidly increasing energy costs, and because in many jurisdictions there appears to be more activity in rate-case applications, one might expect consumers would be more inclined to become involved in commission proceedings. This is especially true of large industrial customers who stand to lose millions of dollars if a regulatory decision results in significant rate increases. However, according to former New York PSC Chairman Bill Flynn, both large and small businesses tend to become aware of the importance of commission proceedings only after a decision is rendered. In some cases, the commission’s decision might have been different if commissioners had received input during, rather than after, the proceeding. Because commissioners must rely on the hearing record to arrive at, and justify, their decisions, they can’t consider, and respond, to consumer concerns and recommendations after an order is issued.
Paul Bonney of PECO notes changes in commission procedures that might address at least some participation issues. For example, workshop-type rulemaking approaches are less likely to result in litigation because a diverse array of stakeholders work collaboratively to craft and implement new policies and rules. Former Pennsylvania Chairman Wendell F. Holland describes commission hosted, probing, en banc meetings involving a diverse array of stakeholders, including legislators and their staffs, to discuss significant energy policy issues. He cites as examples the Pennsylvania commission’s forums on topics such as RPS, price caps, initiation of competition and, most recently, the Marcellus shale gas resource. These forums, in his estimation, facilitate comprehensive exchanges in a non-adversarial environment.
The worst case scenario for PUCs, consumer advocates, and electric utilities alike might be consumer backlash, as rates increase to recover the costs from various mandates or the addition of new capacity. In the authors’ conversations, the example was cited several times of consumers’ heated responses to PG&E’s smart-grid deployments in Bakersfield, Calif., and the company’s decision to halt the project. The ability of state utility regulators to mitigate rate increases will depend on the statutory framework and the discretion given to them. As Kansas Consumer Counsel Springe observes, as more cost trackers and costs mandated by policy or legislative decisions show up on consumer bills, commissioners will find their regulatory discretion restricted to a few more narrow issues like return-on-equity determinations in rate cases. For their part, utilities need to worry that consumer backlash doesn’t translate into a lower level of allowable cost recovery in rate cases, because state utility regulators feel pressured to prove they aren’t caving in to utility company demands. Because utilities historically have been risk averse, they might not be inclined to invest in new technologies like smart meters without certain assurances of risk mitigation. According to Bonney, one of the commission’s challenges is to spur innovation in the electric utility sector. “How do you reward companies for being innovative, and not risk averse?”
EEI’s Ackerman cites one way to induce smart-grid investments through rate design. He notes that retail rate reform, both in terms of the introduction of time-differentiated (e.g., smart) rates, and reduced reliance on volumetric kilowatt-hour charges to recover fixed costs, will be critical to the success of the smart grid. While utilities will be concerned about recovering the costs for smart-grid investments, consumers need to have a better understanding of what to expect. Utility and consumer expectations definitely are inter-related and must be managed effectively if the intent is to avoid future Bakersfield-style debacles. Certainly one approach is to make sure that consumers understand the benefits and costs of smart grids and smart meters.4
Of course, smart-grid initiatives are only one of several mandates that can result in higher retail electric rates. From former Commissioner Wood’s perspective, “the biggest challenge is getting the balance between implementing mandates and protecting customers. It will be tough but it can be done.”
David Springe, consumer counsel in Kansas, observes that consumer education might go some way toward preventing a backlash against the inevitable rate increases. His effort has shifted toward helping people understand why rates are going up. The consumer counsel of the future needs to help consumers be more responsible for their energy usage and fight against the spread of bad information. That will involve work outside the trial environment. He also notes that PUCs will need to become involved in these outreach efforts.
The core responsibilities of state utility regulators haven’t changed, and probably won’t change in the near future. Arguably, consumers still need protections from burdensome price increases and utilities still will need an opportunity to recover their costs and earn a reasonable profit—even in restructured states. Some states have been more active than others in adopting policies to promote retail competition, smart-grid technologies, energy efficiency standards, dynamic pricing, RPS, and policies for encouraging investments in nuclear and renewable generation and siting. The movement toward energy efficiency and renewables born during the oil embargoes of the 1970s has reemerged and has permeated public opinion in ways that couldn’t have been foreseen 30 years ago.
Have all these simultaneous push-pull forces transformed the regulatory process and procedures? Based on interviews with industry leaders, there’s no evidence that a fundamental shift has occurred to date. Nonetheless, interviewees suggested that new tools and new skills might be needed. For example, there’s a growing need for credible cost-benefit analyses that are broader in scope than those applied to an individual company or even to an individual state. There’s a need for solid economic forecasting to underpin and justify regulatory decisions. In addition, regulators, legislators and the energy industry will need a better understanding of the convergence of power delivery and telecommunications tools to inform future policy decisions on smart-grid deployment and cost allocations.
Looking toward the future, state regulators will need to continue to monitor and understand regional and federal policymaking to inform their decisions. They’ll need to share their understanding of new and emerging policy implications broadly with all stakeholders. The educational role of state utility regulators remains at least as important today as it was 30 years ago. As Brian Moline, late chairman of the Kansas Corporation Commission prophetically wrote in 1984:5 “Commissioners and staff must recognize that their jobs will become increasingly complex and frustrating. Public disenchantment with the regulatory process can only increase, and there’s little that regulators can do about it except to clarify their roles and educate the participants. Regulators and utility executives alike must avoid a siege mentality even in the face of public and legislative hostility to their efforts.”