Aligning Incentives in the Electric Utility Ecosystem
William Zarakas is the head of The Brattle Group’s Retail Energy Practice. He analyzes the utility business models and regulatory frameworks that are compatible with the Utility of the Future ecosystem. He also works on the economic and financial aspects of investments in grid modernization and resilience, and the impacts of distributed energy resources on utility operational and financial performance.
Performance based regulation, or PBR, is a widely used and well understood term within the regulatory lexicon, so it is not very difficult to agree on its working definition. In general, PBR refers to a regulatory mechanism or approach that induces utilities to improve their performance through the application of financial incentives, rewards, or disincentives, penalties. However, it has been more challenging to find agreement on the scope of PBR.
The most widely applied PBR plans are designed around a utility's overall financial performance with respect to areas of its operations, such as reliability. Over time, these PBR applications have taken on a variety of forms and combinations that have contributed to higher levels of utility operating efficiencies. They have also become nearly synonymous with PBR frameworks.
Going forward, policymakers and regulators are looking for utilities to take on new initiatives and directions that move the industry in a new and disruptive direction. This raises the question as to whether the PBR mechanisms that are prevalent today are up to the task of motivating utilities to move into a Utility of the Future environment.
The incentives to control costs that are the core of most of the PBRs in place today do little to move the Utility of the Future agenda forward, and may actually be antithetical to it. Getting there will require expanding what is included in the performance part of PBR.
It is generally acknowledged that some form of performance based regulation, applying incentives to promote targeted behaviors, has been around since the dawn of utility regulation. As Alfred Kahn is reputed to have said, "All regulation is incentive regulation."
With respect to U.S. electric utilities, PBR became a regulatory mechanism in its own right in the 1980s and 1990s, when regulators concluded that utility costs were probably higher than they should be. They decided that a carrot to utility managers might provide the impetus to drive cost reductions from within.
U.S. regulators had been influenced by regulatory approaches applied to the telecommunications industry in the U.S. and abroad. They were also influenced by the cost savings following utility sector privatization in Europe.
During this period, telecoms were benefiting from major technological breakthroughs, which drove operating costs downward and industry productivity upward. They were also experiencing increasing volumes of sales. Telecom operators saw a financial upside in switching from earnings regulation to price regulation. They also saw it as a mechanism through which they could adjust their prices when challenged by new and growing competitors.
The telecoms also saw that consumers could benefit from price certainty, rather than the ups and downs that come with the rate case cycle. Regulators in the U.S. and in other parts of the world responded by implementing price cap plans, a type of PBR. It was based on setting a base rate and then adjusting it periodically using a pre-established formula that took inflation and productivity into account.
At roughly the same time, many European state-owned electric utilities were being privatized or liberalized, notably in the U.K. While those utilities were not necessarily benefitting from the technological advances that were rocking the telecom industry, the transition from government-run to private enterprise presented significant opportunities for the newly organized utilities to trim their labor and operating costs. This was not surprising, as the promise of cost efficiencies was a primary motivator for privatizing the industry in the first place.
To ensure that this opportunity did not go unrealized, regulators in the U.K. introduced a price cap mechanism called price control, which was similar to the price cap plans that were being applied to telephone companies. With a few modifications over time, this price control approach has remained in effect through today. It is a key element of the current RIIO (Revenues=Incentives + Innovation + Output) approach.
Electric utilities in the U.S., especially vertically integrated ones, did not experience the jump in productivity that was realized by telephone companies. They did not necessarily see the opportunity to trim costs that was available to the recently-privatized utilities in Europe. In fact, productivity gains for U.S. electric utilities were greatest prior to the mid-1970s.
Total factor productivity, which measures the efficiency of converting inputs into outputs, was typically lower for the electric utility industry than for the U.S. economy overall throughout the 1980s and 1990s.
However, even under these circumstances, a case could be — and was — made that incentives could be added to the traditional regulatory frameworks in order to motivate utilities to control costs and improve areas of their operating performance. Since then, PBR has become a standard regulatory mechanism in many jurisdictions. In practice, the multiyear rate plan (MRP) approach and performance plans aimed at specific areas of operations have become the workhorses of PBR in the U.S.
Most analysts who study PBR in the U.S. highlight MRPs as its centerpiece. Indeed, the incentive qualities of MRPs have been discussed at length in many regulatory orders, although some regulators regard them as an enlargement of the rate case process more than a new type of incentive.
Irrespective of their designation, MRPs serve to lengthen the period between rate cases, thereby allowing a utility to retain all, or in some cases, a portion of earnings above the authorized level if it can control costs. In addition, most MRPs are designed to ensure that the incentives remain attainable by incorporating periodic adjustments to reflect inflation and productivity. Absent this, in many cases, a utility might find itself working hard to control its costs in order to break even, let alone get ahead.
Performance incentive mechanisms or PIMs, also sometimes referred to as targeted performance incentives or TPIs, tend to be narrower in their application than the broader based MRPs. PIMs cover relatively specific aspects of utility performance, typically with respect to reliability (such as SAIDI), customer service or call center responsiveness and employee safety. Under a PIM structure, regulators usually set a target for acceptable performance for an area and attach a financial incentive to ensure compliance.
Most traditional PIMs are asymmetrical downward in structure; in other words, they impose a penalty when a performance target is missed, but do not provide for a reward when it is exceeded.
This PBR focus has worked well and makes good sense when regulating the cost and service quality of a monopoly provider. MRPs provide utilities with an opportunity to earn more than their authorized returns if they are effective in managing costs and, as a symmetrical mechanism, the risk of earning below that level if their costs exceed projected levels. PIMs, when combined with an MRP or applied separately, made sure that utilities do not sacrifice system maintenance and operations in the pursuit of cost reductions.
But a few things have changed. It is well known, and almost a cliché, that the operating environment for utilities is in the midst of considerable flux, driven by end-user bypass options and regulatory initiatives to open up the grid, among other things. Utilities will be significantly affected by these developments.
Paradoxically, they are also a key agent in effectuating the change. Incentives to control costs, while almost always a good business objective in themselves, will not expedite the transition process. Neither will regulatory fiat.
Incentives in the Evolving Operating Environment
Utilities will almost certainly continue to build and maintain the electric distribution grid, but it will not always be on their terms. They will need to consider non-wires options in resource and systems planning, and they will face greater uncertainty with respect to electricity demand, usage and throughput.
This changing utility operating environment is expected to have an impact, perhaps materially, on utility financial performance. It could also change the way that Wall Street looks at utility equities.
The goals of most of the regulatory initiatives aimed at transforming the electric utility industry have been expressed in win-win terms.
To utility managers, however, the short-term impacts seem more downside than up. This makes it hard to embrace the changes that will need to take place in order to transform the industry, especially in an expedited fashion.
For example, a key goal of New York's well-known Reforming the Energy Vision involves substituting non-utility distributed energy resources for traditional utility wires options. This, by design, will reduce utility rate base compared to a business as usual case, and almost certainly depress utility earnings in dollar terms. Even if the end state is good for utilities — which is far from universally accepted — utility managers are asking themselves if they can survive during the transition.
The possibility of a shortfall in utility revenue is not lost on some regulators. In the long term, some optimistic regulators expect that the combination of new services and fees from transactions conducted over the utility platform, peer-to-peer and otherwise, will more than offset the negative effects of a reduced rate base. However, getting there may be a bumpy ride, so regulators have pointed to PBR as a solution, or even a bridging mechanism, until brand new revenue streams are established.
At first glance, applying PBR during an industry transition conjures a "too big to fail" mindset. This is probably an overly dramatic reaction, although there might be a tinge of truth to it. In very practical terms, PBR-based incentives are being proffered because they are needed; regulators are asking utilities to do a lot to make their Utility of the Future visions work.
Much of what they are asking for goes against the long-standing utility business model and mindset.
Changing behavior on such a scale usually requires application of some form of economic incentive. However, precisely what kind of PBR regulators are talking about remains a bit open-ended and unspecified. It also begs the question of whether the PBR mechanisms in place today, mainly MRPs and PIMs, can do the job; that is, incentivize the right behaviors and also provide a meaningful upside for utility financials.
The short answer is probably not. Most of the PBR mechanisms in place today are geared toward cost reduction and service quality and, furthermore, do not provide very much upside earnings potential.
Effectively designed MRPs are a balancing act, with incentives muted under the two extreme conditions. That is, under an MRP, utilities may realize windfall profits (compared to authorized levels) if cost projections are unreasonably high, and will likewise under-earn if cost projections are too low. Cost projections included in an MRP that fall into the "just right" category generally provide a utility with an even chance that it will outperform its authorized returns. Likewise, most of the PIMs that are in place today, such as those dealing with reliability, customer service and employee safety, are almost always asymmetrical downward and offer no prospect for earnings augmentation.
Regulators must have a different scope in mind for PBR going forward if it is to play a meaningful role in moving the industry into a Utility of the Future business environment.
A New Face?
PBR does not necessarily need a complete makeover, but we probably need to amend its incentive structure going forward. MRPs and PIMs have become mainstream ratemaking and regulatory tools, even though they have not been implemented everywhere. This is an understandable outcome, considering that a primary focus of regulation has been on costs, rates and the dilemmas associated with traditional rate of return regulation.
The incentives embedded in MRPs and PIMs have thus contributed to getting an important job done. However, these incentives were not intended to promote actions related to some of the new and evolving policy goals — namely, goals and directives for utilities to modernize their grids, integrate DERs and develop platforms that enable more far-reaching grid accessibility.
A variety of regulatory options are being tried out to fill this void, ranging from the incorporation of new incentives into existing regulatory mechanisms, to the creation of new stand-alone measures. In several cases, rate basing new regulatory assets such as those associated with energy efficiency, decoupling, formula rate approaches and even targeted riders and trackers have been repurposed to this end, taking on an air of PBR.
Incentives to achieve new policy outcomes can also be incorporated into existing PBR frameworks. The U.K.'s RIIO provides a good example. Ofgem largely kept its longstanding price control plans in place, and improved upon them by adding measures and incentives for performance outcomes. So far, most of these are focused on areas of traditional utility operations, but the outcome-oriented approach can readily be re-specified to incorporate new policy goals.
PBR that is focused on specific policy outcomes can also be addressed separately on a stand-alone basis. Incentives for utilities to promote and reach energy efficiency targets have been around for years, but have typically been categorized as specialized programs and not necessarily considered to be part and parcel of a PBR framework.
Regulators in New York may have taken policy outcome based incentives to another level when they introduced their earnings adjustment mechanisms (EAMs). Under this incentive mechanism, utilities receive compensation for reaching targets associated with system efficiency, energy efficiency, customer engagement and information access, and interconnection of non-utility DERs to the grid.
Converting broadly stated policy goals into specific incentive mechanisms will inevitably require some work. This was certainly the case with respect to MRPs and PIMs. First, and perhaps most obviously, the incentive measures themselves need to be defined and specified.
Translating "opening the grid" or "integrating DERs" into actual measures involves breaking down broad policy goals into actionable steps. The process for setting the specific targets should, of course, follow the guidelines for incentive regulation overall: targets should be outcome oriented, compatible and consistent, objectively measured and verified, and readily interpretable. They should also be achievable; setting unachievable targets, in effect, extracts any meaning from the incentive mechanism.
An associated goal in designing the new incentive framework will be to minimize the need for new measurement systems and reporting requirements. However, in practice, some new measures and data will inevitably be needed. After all, the goal for the new framework does involve assessing a utility's performance in new areas.
Second, the incentive mechanism itself will need to be determined. The incentives applied to energy efficiency and New York's EAMs provide a good starting point. The incentives applied there tend to be asymmetrical upward, that is, rewards only, in direct contrast to the incentive structure that is applied to the traditional PIMs.
This change in incentive direction makes a lot of sense when you understand the context. Regulators are asking utilities to work to advance an important societal goal which may not necessarily be aligned with their short term financial interests. An asymmetrical upward mechanism can readily be applied to measures that advance new policy initiatives, such as targets for interconnecting distributed energy resources and electric vehicle deployments.
Third is the question of how much, in dollar or basis point terms, to put forward as an incentive. This is tricky because the incentive needs to be meaningful, motivating utilities to action, but not distortive. It is not an entirely new issue: setting incentive levels has also been a perennial question when setting asymmetrical downward incentives for traditional PIMs.
Analyses and studies on this matter will inevitably be needed, but, for comparison purposes, New York has set a one hundred basis point reward (asymmetrical upward only) for hitting their EAM targets. The U.K.'s Ofgem has taken it a few steps further. Under RIIO, the potential rewards and penalties for reaching policy driven outputs, such as environmental and interconnections goals, equate to about three percent of utility annual base revenues.
Incorporating new policy outcomes into regulatory incentive frameworks represents an enhancement to the industry's approach to PBR, more than a departure from it. It is also a logical progression: the initial rounds of PBR, focused on cost controls and service quality, were designed with the day's critical industry issues in mind.
Rate and cost controls, of course, continue to be important goals of regulation. However, industry transformation to a Utility of the Future environment is occupying more and more space on regulatory agendas. Layering policy outcomes into the PBR framework will be essential to enabling realization of these policy goals, and to ensuring that PBR remains relevant.