New regulatory frameworks encourage electric infrastructure investment.
David K. Owens is executive vice president at the Edison Electric Institute business operations group.
The electric power industry is building for the future. We’re building a cleaner, more advanced, efficient, and diversified generation fleet. We’re exploring methods for capturing and storing carbon. We’re creating a smarter electrical grid and modernizing our transmission and distribution system, which also will help us to expand our efforts to help our customers become more energy efficient.
Today, our industry is spending approximately $80 billion per year building new infrastructure—about twice the amount we spent in 2004. Looking ahead to 2030, one major economic firm has estimated that the industry will invest another $1.8 trillion in developing a more advanced and diversified generation fleet, meeting increasingly stringent environmental standards, and modernizing its transmission and distribution systems.
These new investments will help to ensure high levels of reliability. And they will help to improve customer service, as well as promote public policy goals, such as lowering power plant emissions, increasing customer energy efficiency, and supporting the introduction of electric cars and trucks. But just as the industry is seeking to raise and invest large amounts of capital, sales growth has slowed, making it difficult to fund new investments without rate increases.
In the past, when energy use per customer was growing, utilities could use increasing sales revenues to help fund new infrastructure. Today, however, with electricity demand projected to grow at 1.0 percent per year (or less) through 2035, utilities no longer have this cushion. Under business-as-usual regulation, electric utilities must file more and more rate cases to keep up with rising costs.
Under traditional regulation, utilities also face a lag between the time when they incur financing costs for a construction project, and the time when the project is put into service and they can begin to collect their allowed cost of capital and annual depreciation in rates. This lag time can lead to rate shocks for customers when the total cost of a project is finally allowed to enter the rate base. The lag can also erode utilities’ credit metrics and put downward pressure on their ratings.
To address these risks, the electric utility industry has begun working with state regulators to develop new regulatory frameworks.1 These new approaches provide for modest but stable recovery of costs outside rate cases, while providing ongoing regulatory oversight and creating strong incentives for utilities to efficiently manage their construction projects—both during construction and once they become operational.
New Policy Tools
The particular regulatory framework that a public service commission and a utility develop will depend upon the industry’s unique issues, including its existing system, investment needs, and legal and regulatory situations. Among the policy tools that can be combined in various ways to create such frameworks are the following:
• CWIP: “Construction work in progress” is an accounting and ratemaking procedure that allows for the recovery of financing expenses on construction while work is in progress. Construction costs are entered into the rate base as they are incurred (or as adjustments to historic test years) so that investments begin to earn their allowed return without delay.
CWIP enhances a utility’s cash flow during multi-year construction projects, which helps the utility to maintain favorable credit metrics. The cost of capital incurred in financing new assets (e.g., cleaner power plants) is reduced, along with the rate shock that could otherwise occur when assets are placed in rate base only after becoming used and useful.
To the extent financing costs are recovered through CWIP, they aren’t captured via “allowance for funds used during construction” (AFUDC).
• Cost Trackers: These are mechanisms that expedite the recovery, outside of general rate cases, of volatile or rapidly rising costs, such as those for energy, energy efficiency, pensions, and major plant additions. Cost trackers, which may include annual budget limits, can reduce the frequency of rate cases by surgically addressing major reasons why costs are growing more rapidly than sales. They also can incorporate performance-based incentives that allocate some risk (e.g., of cost overruns) to a utility’s shareholders. Cost trackers sometimes are used in tandem with formula rates to recover costs of major plant additions.
• Rate and Revenue Caps: These are multi-year rate plans that cap growth in a utility’s rates or revenue requirement. Caps might involve index-based, so-called “stairstep” (negotiated), or hybrid escalation formulas that allow utilities to keep up with inflation, investment programs, and other cost challenges without rate cases. Plan terms typically range from three to seven years.
By not being tied directly to the utility’s own costs, these mechanisms give utilities increased operating flexibility and strong incentives to manage long-term productivity growth. Surplus and deficit earnings can be shared with customers via performance-based mechanisms. Supplemental benchmark incentive mechanisms can be added to define specific performance standards and provide penalties or rewards when actual utility performance varies from the standard.
• Revenue Decoupling: This involves ratemaking approaches that make a utility’s base rate revenue significantly less sensitive to its electricity delivery or sales volumes. Revenue decoupling is especially useful when sales per customer are declining due to large energy efficiency programs, particularly state-mandated energy efficiency programs, or structural changes in the economy that lower sales growth. Decoupling ensures that utilities recover approved fixed costs and so eliminates a potential utility disincentive to promote energy efficiency goals. Three revenue decoupling approaches are popular: 1) Revenue true-up plans track variances between actual and allowed revenue and make true-ups to future rates to keep the utility whole for allowed fixed costs. These plans also may escalate base revenue requirements between rate cases to reflect changes in business conditions that drive utility costs (e.g., inflation). 2) Lost revenue adjustment mechanisms compensate utilities periodically for base rate revenues that are estimated to be lost due to aggressive increases in energy efficiency. 3) Fixed variable pricing collects a high percentage of fixed costs through fixed (e.g., customer and reservation) charges.
• Formula Rate Plans: These mechanisms make regularly scheduled rate adjustments outside of rate cases to help a utility’s revenues track its pro-forma cost of service. Utilities earn their target return on equity, and avoid over- and under-earning. Formula rates can incorporate CWIP in rate base and reduce rate shock. Performance-based provisions are sometimes added to strengthen incentives in targeted areas such as cost control, customer satisfaction, and service quality.
• Forward Test Years: A rate case methodology that uses forecasts of utility costs and billing determinants in a test year that occurs after the filing. When unit costs are rising, forward test years mitigate regulatory lag and give utilities a better chance to earn their allowed return on equity.
The new regulatory frameworks can provide benefits to consumers in at least four major ways. The first is the avoidance of rate shocks.
Many of the foregoing policy tools have the effect of smoothing rate trajectories to avoid large step increases in rates. CWIP does this by reducing total financing charges. Rate and revenue caps do it by providing multi-year plans that can transition to higher unit costs over a period of years with limits on annual increases. And revenue decoupling and formula rate plans do it by adjusting rates regularly and providing refunds when the weather, fuel prices, or economic activity cause revenues to be too high.
All of these will help to avoid situations like those that occurred recently in Maryland, where fuel costs were deferred from July 2000—when customer choice was introduced—until July 2006 when an associated rate freeze was lifted and utilities in the state had standing to ask for the recovery of new costs. At that point, the request translated into a 72 percent increase in retail rates.
A second benefit involves removing barriers to needed new investment, and allowing new infrastructure of all kinds to be built. This is the most significant long-term benefit because it means reliability, service quality, and environmental quality will continue to be improved.
A third, related benefit involves access to private capital on more reasonable terms and conditions than would be the case under traditional regulation. This translates into lower borrowing costs for utilities, and as a result, lower rates for customers.
A fourth major benefit involves increases in construction and operating efficiency when utilities respond to performance-based incentives. These expose the utility to a portion of the risk of cost overruns, and provide a clear demonstration of how performance-based policies can be used to rebalance risk between customers and shareholders. This type of policy can create a strong incentive for the utility to manage construction effectively and even to pass construction risk on to contractors via performance-based contract terms.
The electric power industry is investing to build a modern, cleaner, and more efficient electrical system. In working with state regulators to develop innovative regulatory frameworks, the industry will facilitate and encourage this investment, benefiting customers and society alike.