Performance-based regulation ("PBR") is most commonly defined as an approach to utility regulation designed to strengthen utility performance incentives. Thus defined, the term PBR is synonymous with incentive regulation ("IR"). The two most common forms of PBR are award-penalty mechanisms ("APMs") and multiyear rate plans ("MRPs"). 

Both involve mathematical formulas that can lower regulatory cost at the same time that they encourage better performance. This constitutes a remarkable potential advance in the "technology" of regulation.

Award/Penalty Mechanisms

An APM is designed to strengthen performance incentives in a targeted area. Basic components of an APM includes a performance metric or indicator (called an "output" in Britain), a performance appraisal that compares the utility's value for the indicator to a benchmark value, and a mechanism for adjusting utility rates to reflect the performance appraisal. Here are some common performance areas targeted by APMs:

• Reliability (e.g. SAIDI, SAIFI)
• Other customer service dimensions (e.g. telephone response time)
• Demand-side management (e.g. estimated net benefits)
• Cost (e.g. cost/dkth of gas procured).

APMs targeting cost are often used to bolster incentives when a regulatory system features a mechanism, such as a fuel cost adjustment clause, that is believed to weaken cost containment incentives.

Multiyear Rate Plans

MRPs are the most common approach to PBR around the world. An MRP features a moratorium on rate cases that typically lasts three to five years. An attrition relief mechanism ("ARM") adjusts rates automatically to reflect inflation and other changes in business conditions. Some costs may be addressed separately using cost trackers. Some MRPs feature earnings sharing mechanisms that share surplus or deficit earnings between the utility and customers when the return on equity deviates from its target. Plans may also feature an efficiency carryover mechanism that incentivizes long term performance gains and discourages the opportunistic timing of expenses by permitting the utility to keep a share of cost savings (or absorb a share of high costs) when rates are trued up to cost at the end of the plan.

Several approaches to the design of ARMs are well established.

• An index-based ARM is developed using industry price and productivity research and is calibrated to produce superior returns for superior productivity performance. This approach was developed in the United States but is more popular today in Canada and countries overseas (e.g. New Zealand).
• A stairstep ARM increases revenue by a certain percentage each year, with the percentages set in advance. Allowed revenue then has a stairstep trajectory. This is currently the most popular approach to ARM design in the United States.
• Two hybrid approaches to ARM design have been widely used. In North America, revenue for O&M expenses is indexed, while that for capital cost has a stairstep trajectory. This approach to ARM design was developed in California and is currently used in the MRP of Southern California Edison. In Britain, a multiyear cost forecast is approved and a revenue cap index with an RPI - X formula (RPI is the retail price index) is chosen that yields equivalent net present value. A similar approach to ARM design is used in Australia.

Since infrequent rate cases lessen concerns about cost allocations and cross-subsidies, MRPs can permit regulators to sanction greater marketing flexibility. Most MRPs also include APMs to balance incentives for cost containment with incentives to pursue other goals (e.g. reliability or energy conservation) that matter to customers and policymakers.

MRPs have been especially popular in North America where utilities need marketing flexibility. Such plans have helped railroads, oil pipelines, and telecommunications utilities provide complex arrays of services to markets with diverse competitive pressures from common sets of assets. MRPs are also favored for energy distributors in most populous provinces of Canada and are increasingly popular for gas and electric utilities in the United States.

Recent developments have increased the potential usefulness of MRPs in the US.

• Slower volume growth due to conservation, slow economic growth, and increased distributed generation has reduced the "gravy" many utilities relied on in the past to help finance cost growth.
• Natural gas-fired technologies have replaced solid-fuel technologies as the low cost choice for incremental generating capacity.
• Vertically integrated electric utilities need fewer plant additions, and those that they do need are smaller than in the past.
• Some utilities are engaged in accelerated modernization of distribution systems that involve elevated levels of capital expenditures for several years.
• Diffusion of "smart grid" technologies creates opportunities for new products and services.
• Some customers will pay a premium for better quality service.

Under cost of service regulation, utilities will respond to these conditions by filing rate cases more frequently and requesting additional marketing flexibility. Frequent rate cases raise regulatory cost and weaken utility cost containment incentives. The recurrent issues of cost allocation and cross-subsidies will incline regulators to discourage desired marketing flexibility. In a prior period of frequent rate cases, in the 1970s and 80s, the productivity growth of US energy utilities slowed markedly.

 Overseas, the privatization of many utilities in the last 20 years has forced governments to choose a regulatory system. The majority have chosen MRPs over cost of service regulation. Regulators in Britain, Australia, Germany, the Netherlands, Norway, and New Zealand are recognized MRP leaders.

The British approach to PBR is one of the best known. The latest version of this approach, called "RIIO" (Revenue = Incentives + Innovation + Outputs), has been implemented for gas and power transmission utilities in Britain and will begin for power distributors in 2015. The heart of the RIIO system is an MRP, which the British call a "price control". A revenue cap ARM has an RPI - X formula. The typical plan term is 8 years. Since the ARM is based on multiyear cost forecasts, the regulator must carefully review utility business plans. Statistical benchmarking and independent engineering studies loom large in cost appraisals. 30 months is typically required to process a RIIO application. There are APMs for a wide range of outputs. Special cost trackers encourage innovative projects.

RIIO has recently been touted as a promising approach to regulating US electric utilities in an era of smart grid innovations and increased distributed generation. However, many components of RIIO (e.g. MRPs and APMs) are already widely used in America and Americans have developed their own approaches to addressing certain regulatory challenges. For example, integrated resource planning has been used for years in some states, and planning in some states can be extended (as in California) to incorporate DG and smart grid innovations. There is a long tradition of "pilot" projects to encourage innovation. Alternative approaches to ARM design are more familiar and can involve lower implementation costs.

Revenue Decoupling

Revenue decoupling is an approach to Altreg that has been used for more than three decades by North American utilities. The two most common approaches are decoupling true up plans and lost revenue adjustment mechanisms ("LRAMs"). An LRAM compensates the utility periodically for the margin that is lost due to its DSM programs. In a decoupling true up plan, rates are reset periodically to ensure that a company's revenue matches its revenue requirement. Both approaches make utility finances less sensitive to the slowdown in use per customer that can accompany aggressive demand side management (DSM) programs. Utilities are therefore more likely to embrace DSM. A well designed decoupling mechanism can help utilities avoid frequent rate cases that might otherwise be triggered by slow volume growth. The need for decoupling is especially acute when volume growth is slow but utilities are compelled to use historical test years in rate cases.

Decoupling true up plans usually involve a revenue adjustment mechanism (RAM) that escalates the revenue requirement in the absence of a rate case. Five approaches to RAM design have been established. 

• Under a revenue per customer (RPC) freeze, revenue per customer is fixed for the term of the plan. The revenue requirement then grows automatically with the number of customers served. The formula may apply to the total revenue per customer or individual rate classes. This is the single most popular approach to decoupling today. Although used primarily by gas distributors (e.g. Baltimore G&E), who experience declines in average use, it is now used as well by electric utilities in Idaho and Maryland. RPC freezes don't compensate utilities for input price inflation, which has accelerated substantially in recent years. As a consequence, many utilities operating under RPC freezes have been compelled to file frequent rate cases. The other four approaches to RAM design that we describe do not have this failing. 

• Under revenue per customer indexing, the allowed revenue per customer is subject to automatic escalation for price inflation. This can in principle be accomplished by having a company's cost per customer rise at the average rate of a suitably chosen peer group. However, most RPC indexes approved to date have relied on the theoretical result that the growth in cost per customer is the difference between input price and productivity growth. These indexes have inflation - X formulas, where X reflects a productivity target and also corrects for any inaccuracy of the chosen inflation index as a measure of energy utility input price inflation. This approach has a solid scientific foundation and is apt to generate considerably more attrition relief than a revenue per customer freeze. Utilities who have operated under this kind of RAM include Enbridge Gas Distribution, Southern California Gas, and Vermont Gas Systems. 

• Under the "inflation-only" approach to RAM design, the revenue requirement is adjusted only for growth in a familiar macroeconomic inflation measure such as the Gross Domestic Product Price Index. This is tantamount to a revenue per customer index in which X is set equal to customer growth. This approach has been approved for use in decoupling plans for Southern California Gas, and the gas and electric services of Pacific G&E and San Diego G&E. 

• Under the "all-forecast" approach, revenue requirement escalation depends on a multi-year forecast of the growth in total cost. This is tantamount to a rate case with multiple forward test years. The revenue requirement in the "out" years is usually scheduled to rise in a "stair-step" pattern. This approach to RAM design has been used extensively in California and is now being used in New York state. It has the disadvantage of being non-responsive to unforeseen hyperinflation. 

• Under the "hybrid" approach to RAM design O&M expenses are typically escalated using an index, whereas capital cost escalation is based on a multi-year forecast. This general approach has been the third most popular overall and has been used chiefly by California utilities. It is currently used by the three Hawaiian Electric companies.

Forward Test Years

Many utilities are still compelled to use historical or hybrid test years in rate cases. These approaches were designed for an earlier era of rapid volume per customer growth and are often uncompensatory under today's business conditions. A forward (aka fully forecasted) test year allows the utility to set its rates using forecasted costs, investment levels, and revenues. Forward test years are now used in more than twenty states and most Canadian provinces.

Capex Trackers

Many energy distributors are engaged today in accelerated programs of system modernization. Vertically integrated electric utilities face an additional challenge when engaged in a multiyear program to install scrubbers on its generating units. Assets with appreciable value become used and useful each year, and timely recovery of the cost of plant additions can require frequent and even annual rate cases. Capex trackers can help utilities achieve timely recovery of new investments without frequent rate cases. The majority of U.S. regulatory jurisdictions have employed a capex tracker.

PEG Research Capabilities

PEG possesses North America's most experienced staff of energy Altreg consultants. We are especially well-known for our pathbreaking work in the PBR field. Our research and testimony has helped establish PBR in numerous jurisdictions. Our staff has over sixty man-years of Altreg experience.  We have advised the Edison Electric Institute on Altreg issues for more than a decade. Work for a mix of utilities and commissions has given us a reputation for objectivity and dedication to good regulation. We routinely extend the frontier of Altreg with cutting edge research. Applications we have worked on include most major energy utility services.

• ELECTRIC POWER: Transmission, Distribution, Customer Care, Energy Procurement, and Bundled Power Service
• NATURAL GAS: Transmission, Distribution, and Procurement

Many of the leading PBR jurisdictions in the world are now located outside the US.  PEG is active in many of these venues, including Australia, Canada, and New Zealand.  We also like to share our expertise with less developed countries.  

Plan Design

PEG has helped many energy utilities design Altreg plans.  We have worked on a variety of Altreg mechanisms:

• Multiyear rate plans
• Revenue decoupling
• Cost trackers
• Award-penalty mechanisms for reliability and other indicators.

Revenue decoupling has been a major focus of our recent work. We have filed relevant testimony in proceedings leading to the approval of numerous decoupling mechanisms. A special strength is the design of broad-based revenue adjustment mechanisms.

We are not wedded to any single approach to Altreg and are committed to helping our clients find the approach that makes sense for them.  Our plan design services include the monitoring of Altreg developments across utility industries and around the world. This includes Altreg for major plant additions.   Clients can quickly access our extensive collection of Altreg documents.

Incentive Power Model 

The benefits to utilities from alternative regulatory systems are critical issues in Altreg plan design and advocacy.  Utilities care about earnings levels and risk.  Customers care about price levels and stability.  In research for several clients, PEG has developed a sophisticated model to quantify these impacts of regulation for alternative concrete regulatory systems. For each system considered, the model generates results for:

• Strength of incentives
• Earnings
• Customer benefits

Using a sophisticated optimizing algorithm, we have modeled how rational companies respond to several key features of regulatory systems. These include:

• Plan Term (e.g. 2 - 10 years)
• Rate Reset Provisions (e.g. full rate case, efficiency carryover mechanisms)
• Earnings sharing mechanisms (e.g. symmetric vs. asymmetric, deadbands)

Our results show that if the Altreg plan is not designed appropriately, some initiatives will not be pursued and utilities and their customers will both lose. Results can also help managers plan for success under Altreg. For example, some of the biggest benefits of a PBR plan may not be realized unless there is timely implementation.

Our Incentive Power model can help clients appraise established regulatory options, identify promising new options, and present supportive evidence.

Empirical Research

Altreg plans often require a solid foundation in empirical research.  We have undertaken a wide range of Altreg-related empirical work, including the calculation of industry input price and productivity trends for many utility services.  PEG personnel have provided the research supporting many approved indexing plans for energy utilities.  In work for the Ontario Energy Board ("OEB") and other clients, we have played a leading role in the spread of PBR to the populous provinces of Canada.

Regulatory Support

A sound regulatory strategy is essential to the ultimate success of a Altreg initiative.  PEG provides a full range of regulatory support services, from involvement in technical and settlement conferences to expert witness testimony.  Our experience as expert witnesses in Altreg proceedings has no rival in the consulting industry.  Our record goes beyond appearances on the witness stand to include the achievement of solid results for clients.

Publications and Public Appearances

PEG has organized, chaired, and sponsored a series of highly acclaimed national forums on Altreg. Contact us if you need a speaker on Altreg issues.  PEG personnel have also made a number of contributions to the literature on Altreg, including influential white papers for EEI and the Electric Power Research Institute.  Articles have been published in respected professional journals.

• Models to estimate cost and revenue synergies related to mergers.

• Models to prepare pro forma balance sheets, income statements and cash flow statements for merging companies, both with and without projected synergies and merger related costs.

• Share price and dividend models to track the various merger components and to provide valuable information to boards of directors and senior management as to a potential merger's accretive or dilative effects.

We have developed complex marketing and demand analyses for utilities moving from regulated to competitive markets. In most of these cases, PEG provided expert testimony before either state or federal regulatory commissions, or both.  We have developed presentations for boards of directors and upper management identifying the strategic issues involved in moving from a regulated to a competitive environment, and assisted in developing appropriate strategies for implementing these changes. 

For several utility and non-utility clients, we have identified and screened potential merger candidates and acquisition targets in the United States and abroad. We have analyzed the financial aspects of potential mergers and issued fairness opinions. We have analyzed and provided expert testimony regarding vertical and horizontal market power issues related to mergers.