The anniversary of Superstorm Sandy is a stark reminder that the nation’s infrastructure remains vulnerable to disruptive weather events. By the time Sandy blew out to sea, it had left 72 dead, damaged 650,000 homes, knocked out power for 8.5 million Americans, and cost between $27 and $52 billion.
Hurricane Sandy highlights a disturbing trend – the increasing frequency of major power outages due to severe weather. Data from the U.S. Energy Information Administration show that weather-related outages have more than doubled over the past two decades. Between 2003 and 2012, there were roughly 679 major weather-related power outages, each affecting at least 50,000 customers. Weather-related power outages cost the U.S. $25 billion to $70 billion annually.
Not surprisingly, policymakers, regulators and consumers are demanding that electric utilities improve their ability to withstand and recover quickly from service disruptions during severe weather. These demands come at a time when much of the equipment on the grid is in need of replacement or modernization. According to the American Society of Civil Engineers, more than 70 percent of power transformers in the U.S. are 25 years or older and 60 percent of circuit breakers are more than 30 years old.
The challenges don’t end there. According to the Los Alamos National Laboratory, 40 percent of cyber attacks target the energy sector, including electric utilities. Now utilities are increasingly expected to serve as front-line defenders of critical national infrastructure, protecting the grid from both cyber and physical threats.
Meanwhile, the rapidly declining cost and corresponding increase in deployment of solar photovoltaic (PV) panels will require utilities to manage higher levels of intermittent generation on their distribution networks. In California, for example, the Independent System Operator estimates that by 2020, the combination of evening peak loads and simultaneous reductions in customer-sited PV generation could almost double net load on the system over a three-hour window.
As the nation’s utilities prepare to meet these challenges, many must contend with a legacy regulatory framework that may impede a utility’s ability to recover its fixed costs and discourage much-needed capital investment. This dilemma is rooted in the fact that most distribution utilities continue to operate under “cost of service” regulation, a model that dates back to the first half of the last century.
Under this model, regulators provide utilities the opportunity to earn a return on those costs determined to be prudent and reasonable in providing service to customers. Utilities experience a lag between when they make an investment and when the regulator has approved including the cost of the investment in rates. During periods of increasing investment requirements and slowly growing sales, this lag can result in negative cash flows for the utility.
As a result, utilities may delay investments that might otherwise benefit consumers. The U.S. electric sector now faces these very dynamics, as sales of electricity decreased by 1.8 percent in 2012 and have fallen in four of the last five years. In 2012, capital expenditures and dividends exceeded the net cash from operations of investor-owned electric companies resulting in cash flow deficit of $26.7 billion. Moreover, “cost of service” regulation offers little incentive for utilities to innovate, improve operational efficiency, or deliver increased service quality beyond the minimum levels set by regulators.
Some regulators have experimented with alternative models – including revenue decoupling, capital trackers or multi-year revenue caps – to provide greater support for new investments or stronger incentives for utilities to reduce costs. However, such alternatives may not effectively integrate incentives for efficiency, innovation and service quality. A new regulatory model is needed to respond to the today’s challenges, create a 21st Century power grid and enable utilities to deliver greater value to their customers.
Emerging Model: Results-Based Regulation
As regulators look for alternative means to meet industry challenges without discarding traditional objectives of regulation, a results-based model offers an attractive approach. Results-based regulation is designed to support investments that deliver long-term value to customers, reward utilities for exceptional performance, and remain affordable by encouraging improved operational efficiencies.
An example of this model can be found in the United Kingdom’s newly-adopted “RIIO” model, or “Revenue set to deliver strong Incentives, Innovation and Output.” The major components include:
- Revenues set based on the regulator’s review of a forward-looking utility business plan;
- A multi-year revenue plan that provides an incentive for cost reductions;
- An earnings-sharing mechanism that enables consumers to benefit from utility cost savings;
- Clearly defined performance metrics and incentives for delivering value to customers; and
- Funding set aside for innovative projects.
The anniversary of Hurricane Sandy is an appropriate time for U.S. regulators, policymakers and utilities to consider the shift to a results-driven regulatory model that better supports the transition to an efficient, reliable and sustainable power system.
To download a report examining today’s regulatory hurdles and the benefits of shifting to results-based regulation, please visit gedigitalenergy.com/regulation.
David Malkin is the Director of Government Affairs and Policy for GE’s Digital Energy business, and Paul Centolella is a former utility commissioner and current vice president at Analysis Group.