by C. Douglas Bowman
and Margaret S. McKay
Performance-based regulation (PBR) was introduced as an alternative to cost-of-service regulation in the U.S. electricity sector in the late 1980s and early 1990s. The primary objective of PBR is to inject competitive market incentives into monopoly markets and weaken the link between costs and rates. By the mid- to late-90s, emphasis on PBR diminished as a result of the increasing focus on restructuring issues such as stranded costs.
PBR is now experiencing a resurgence for two reasons. First, PBR has produced significant value to both utilities and consumers. Under PBR since 1992, the National Grid Company in England and Wales has reduced its unit cost of transmission by 37 percent, while increasing transmission system availability by a full percentage point to over 99 percent and increasing the capacity of the transmission system in excess of 20 percent.
Second, the increasing number of regulated entities in the market following unbundling of the generation, transmission and distribution functions has significantly increased the workload on regulators, dictating a more light-handed form of regulation with more automated pricing mechanisms. For example, the Ontario Energy Board in Canada previously regulated only one vertically-integrated utility, Ontario Hydro, but following restructuring, took on regulation of a transmission company and 250 distribution entities (this number may drop as low as 90 this year as a result of mergers and acquisitions).
Components of PBR
Under traditional cost-of-service regulation, utilities are allowed to recover prudently incurred costs plus a return. This requires frequent regulatory reviews and provides little incentive to increase service offerings or cut costs. Under PBR, price or revenue is capped, providing utilities with the incentive to improve efficiency and reduce costs to improve profit margins. PBR is a more light-handed form of regulation, resulting in reduced costs of regulation, reduced cost of power owing to sharing of utility cost reductions between utilities and consumers, and improved risk allocation between utilities and consumers.
Most PBR schemes institute a revenue or price cap that is adjusted annually to account for input price increases offset by productivity improvements to ensure that customers share in any benefits derived by the utility. Often, a “Z-factor” is included in the revenue/price cap formula to allow direct pass-through to consumers of costs over which the utility has no control (i.e., costs of restructuring). A typical PBR formula:
- l Pricet = Pricet-1(1+CPI-X) +/- Z, where:
t = current period,
t-1 = last period,
CPI = consumer price index,
The PBR plan is reviewed at regular intervals, for example three to five years, when revenues/prices are reset. The length of the review period is selected to ensure that consumers share in the utility’s efficiency gains while providing the utility with enough time to gain a return on its investment.
The incentive to cut costs under PBR leads to reliability and service quality concerns on the part of consumers. In this regard, PBR generally includes performance indicators related to reliability, market efficiency, customer service, and perhaps, employee and public safety.
Problems and concepts
Development of price control mechanisms accommodating the needs of both utilities and customers has proven to be elusive. England, Wales and Australia have identified the reduction of in-period reviews as a primary goal of subsequent PBR mechanisms. Earnings-sharing mechanisms, such as those used in California, make annual reviews a requirement in order to determine the customer’s share of excess revenue earnings. In-period reviews increase regulatory risk, reduce price stability and increase the level and cost of regulation. In some cases, constant in-period reviews have effectively reduced PBR to cost-of-service regulation.
In order to take the guess-work and negotiation out of the price control mechanism, allowed revenues should be based on a utility’s peer group. DTe in the Netherlands intends to institute yardstick competition in 2004 in order to break the link between individual prices and costs, and instead focus utilities on their performance vis-a-vis that of their peers. Ontario intends to review the role of yardstick regulation in its second generation PBR plan to take effect in 2003.
Yardstick competition would work well for transmission companies and distribution companies in the United States because there are large numbers of each type of entity, enhancing the ability to select statistically significant peer groups with similar characteristics.
The performance indicators utilized in PBR schemes to date are too numerous and often do not focus on what customers value. At the retail level, customers care about level of service, reflected by quality of supply, and utility response to queries and requests, such as billing questions and new service connection requests. A large number of indicators can produce perverse incentives to utilities, and impede a utility’s ability to direct capital and operations and maintenance (O&M) dollars to those areas that return the greatest customer satisfaction on a per dollar basis.
In addition, there is a need to move to more market-based performance measures. Australia’s Draft Statement of Principles for the Regulation of Transmission Revenues determined that “ellipsethe most important shortcoming of the current arrangements is the lack of direct relevance to market impacts. Market impacts can be measured as the cost to market participants or end-users of network unavailability.” Performance measures related to reliability generally include number and duration of outages to customers. However, loss of a transmission line may or may not have a measurable effect on the efficiency of the market and the resulting costs to customers. Performance indicators that are not tied to market impacts are not providing the proper incentives to utilities to direct capital and O&M expenditures to the components of the network that have the greatest financial impact on consumers.
England and Wales has proposed reducing its number of performance measures for distribution companies from 12 to three measures, including customer satisfaction and number and duration of interruptions to supply. These performance measures are more consistent with what customers value and provide utilities with greater latitude in the efficient employment of capital. However, the reliability measures could be substantially improved by incorporating market impacts. In Australia, information is being gathered on a number of market-based measures to incorporate into future PBR schemes (i.e., the cost of extra energy required to overcome constraints).
The loss of some network elements will have a much greater impact on market participants than the loss of others. Under a nodal pricing system such as that implemented at PJM, the cost to the market of the loss of a transmission element is reflected in the nodal prices. Performance indicators capturing this impact will provide incentives to utilities to direct capital and O&M costs to the elements that most affect the market. In Norway, network companies are required to report energy not supplied broken down by end-user group. Once end-user groups are identified, an appropriate outage cost can be applied to each group, and the resulting costs tracked accordingly. It is not necessary to develop exact costs of outages to the consumer groups as only the relativity of the figures to the utility’s peer group and/or to its historical performance is evaluated.
The application of PBR
PBR is consistent with the more competitive electricity industry now in place in the United States. It has produced significant customer benefits and offers the opportunity for increased profits for utilities that take greater risks and perform well. In addition, PBR is necessitated by the increased number of regulated entities resulting from industry unbundling.
Although PBR has had great success, its benefits can be enhanced through the application of advanced regulatory concepts. A utility’s revenues should be based on those of its peer group through yardstick competition. In addition, the number of performance measures should be minimized, and the measures themselves should reflect what customers value and should incorporate market impacts. This will result in the more efficient use of capital and O&M resources by granting utilities the latitude to direct resources to those areas that provide the greatest overall benefit to consumers.
C. Douglas Bowman, manager of performance assessment and strategy services, and Margaret S. McKay, senior consultant of performance assessment and strategy services, can be contacted via e-mail (dbowman@ kemaconsulting.com; mmckay@kemaconsulting. com) or telephone (703-631-6912).