The power system in North America is at a crossroads. The system has delivered unprecedented growth and prosperity since it started as a single system in New York City more than a century ago. But the next half century presents significant challenges. Since 1990, electricity demand has increased 25 percent and is expected to double by 2050. The issue of carbon management is emerging as a game changer, putting additional stress on the system.
Moreover, capital investment requirements are staggering. The cost to build new transmission is increasing—often exceeding $1 million per mile. According to Jeff Sterba, CEO of PNM Resources, with a business-as-usual approach, approximately $750 billion to $800 billion will have to be invested in the electrical grid and generating infrastructure by 2020 (see Figure 1). This puts extreme pressure on industry and society to find ways to capitalize, site, permit and build the infrastructure necessary to meet the demand challenge.
The technology revolution provides an opportunity to optimize—and perhaps reduce—these capital investments. Smart metering and grid automation technologies create opportunities to tap a new operational resource—the demand side.
Research indicates that broad use of demand-side management could mitigate up to $70 billion of the projected $450 billion investment needed between now and 2020. Unlike critical peak pricing, which is called upon approximately 12 times a year, fully automated demand response can deliver valuable, persistent responses in real time, all the time. This capability can reduce wholesale market volatility; support integration of renewable power sources; improve system reliability and resistance to disturbances and blackouts; and defer expansion costs.
But while technology is a fundamental element of the solution, transforming the grid requires additional, key ingredients—specifically, regulatory innovation and consumer engagement.
Historically, utilities have been given a guaranteed a rate of return on capital investments, with profits tightly coupled with the volume of energy customers’ use. This has created a disincentive for utilities to invest in alternatives to capital asset construction, even when the alternative investments—such as distributed generation, energy efficiency or demand response—might reduce customer rates, improve reliability efficiencies and offer environmental benefits.
Title XIII of The Energy Independence and Security Act of 2007 (EISA) provided a federal policy signal to change this profit model. Specifically, §1307 reads, “Each State shall consider requiring that, prior to undertaking investments in nonadvanced grid technologies, an electric utility of the State demonstrate to the State that the electric utility considered an investment in a qualified smart grid system based on appropriate factors, including (i) total costs; (ii) cost-effectiveness; (iii) improved reliability; (iv) security; (v) system performance; and (vi) societal benefit.
“Each State shall consider authorizing each electric utility of the State to recover from ratepayers any capital, operating expenditure, or other costs of the electric utility relating to the deployment of a qualified smart grid system, including a reasonable rate of return on the capital expenditures of the electric utility for the deployment of the qualified smart grid system.”
In effect, this language encourages each state to authorize electric utilities to decouple rates from consumption. Several states—including Connecticut, Idaho, New York and Vermont—already have taken such action, decoupling rates from energy consumption. More than a dozen other states are considering such a move (see table “Revenue Decoupling in the States”).
In 2007, the Idaho Public Utilities Commission approved a pilot “fixed cost adjustment” that allows Idaho Power to recover its fixed costs regardless of energy sales (see “2008 CEO Forum”). The fixed-cost adjustment will allow for an annual comparison of the fixed costs actually recovered through rates and the fixed costs authorized by the commission in its most recent rate case. The difference, if negative, would result in an annual rate increase to consumers of no more than 3 percent. If the utility recovers more, the difference would be credited back to consumers with as much as a 3-percent decrease. The utility recently adopted programs providing added financial incentives to consumers for efficiency improvements.
In a twist on the decoupling idea, the North Carolina Utilities Commission accepted a plan in 2007 that will compensate Duke Energy Carolinas for verified reductions in energy use. The commission also accepted Duke Energy Carolinas’ commitment to invest 1 percent of its annual retail revenues in North Carolina—about $35 million annually—in energy efficiency programs. As efficiency gains slow the increase in electricity demand, the company will retire up to 800 MW of older coal plants.
(Editor’s Note: Progress Energy recently filed a proposal for a similar conservation incentive, with a goal of reducing 2,000 MW of demand in the Carolinas. See “2008 CEO Forum”)
Providing incentives for utilities to partner with customers and third parties on these alternatives and offering appropriate opportunities for earnings based on these investments will pave the way for a power grid that promotes innovation rather than resists it.
A strong carbon policy will create new incentives and opportunities to extract value from smart grid networks beyond their initial purpose of demand response. If carbon prices rise to projected levels, wholesale power costs could double. The ancillary services made possible by wide-scale, real-time demand response have the potential to mitigate the anticipated financial impact of a carbon policy.
The two-way communication and metering capabilities of an intelligent demand-response system will provide utilities with the required measurement and validation for carbon offsets programs. Today, measurement and validation of end-use energy efficiency typically accounts for approximately 10 percent of total utility program costs. Modern demand-response networks with automated metering provide data at short intervals (hourly or less), providing enhanced resolution to conduct accurate measurement and validation.
This capability can make efficiency programs significantly more attractive to utilities and regulators by saving substantial measurement and validation costs and making energy savings and carbon offsets more transparent and tradable.
Smart-grid technologies also can help utilities reduce carbon output. Shifting loads from peak demand periods to shoulder or off-peak periods can save primary energy and reduce carbon emissions. Peaking plants are very inefficient—frequently less than 30 percent. Demand response can shift loads to shoulder periods that are served by more efficient facilities—such as natural gas-fired, combined-cycle plants that deliver about 40 percent efficiency and have lower carbon emissions per unit of energy supplied.
Additionally, carbon regulation is expected to lead to increased reliance on windpower and other variable power sources. The Olympic Peninsula Gridwise project determined the fast regulation capability of demand response, which ultimately could help ease the operational stress and expense of integrating variable energy resources.
The operational challenges associated with managing variable windpower already are apparent. In Texas, a nearly 1,000-MW shortfall in wind generation, compared to the day-ahead schedule, contributed to emergency measures ordered by ERCOT (see “What Happened in ERCOT,” Fortnightly, May 2008). A study by General Electric for the state of Texas predicts that wind-induced power drops of as much as 2,400 MW in less than 30 minutes could happen at least once a year when Texas’s wind capacity hits 15,000 MW.
Technology and regulatory incentives alone are not enough to ensure deployment of a smarter grid. For smart metering systems to deliver the desired benefits, consumers must be engaged and incentivized to participate. Their active participation in electricity markets brings tangible benefits to both the grid and customers, while reducing the cost of infrastructure investment and electricity delivery.
Recent demonstration projects validate the impact end users can have in helping utilities address some of the complexities that exist in today’s operating environment. Demand-response case studies show that, when given the right incentive and controls, participants will respond to peak-period prices, reducing demand and saving money in the process.
One recent demonstration, led by the Department of Energy’s Pacific Northwest National Laboratory, found that over the course of a year, end-users in Washington’s Olympic Peninsula reduced peak energy demand by at least 15 percent and achieved 50-percent decreases for short periods of time (see “Demonstrating the Smart Grid”).
Not only did consumers consistently help flatten the load, they exercised complete control of their level of participation throughout the entire project. At the conclusion of the study, 95 percent of participants stated they would be likely, to very likely, to participate in a similar project if offered by their utilities.
The significance of the consumers in premise-based participation became apparent when the California Energy Commission faced backlash for a proposal to require installation of smart thermostats in new buildings. The proposed thermostats were designed to allow utilities to adjust customers’ preset temperatures when the price of electricity began to rise. Customers had the ability to override the utilities’ suggested temperatures—most of the time. In emergencies, the utilities could override customers’ wishes. A large California building association and other groups fueled a public outcry that spread via the Internet and talk radio shows. As a result, the CEC dropped the proposal entirely from its 2008 building-efficiency standards.
Utilities seeking to deploy smart-grid technology and smart-tariff policies will need to present a strong case to regulators and customers that such actions would be cost-effective and mutually beneficial.
America’s demand growth and strategic interests call for the nation to implement the smart grid at a faster pace than is happening today. Policy changes, environmental concerns, growing demand and changing markets have presented the U.S. utility industry with a substantial challenge—but also a unique opportunity to significantly transform the electric system. Deployment depends on the alignment of technology, regulatory signals and customers.
Regulatory policies must provide utilities with the proper incentives to encourage investment in the best technologies. Toward that end, NARUC and other regulatory bodies are coordinating dialogue about regulatory changes. Policy innovations in support of smart grid concepts can be central to protecting consumers, utilities, the economy and the environment when they are developed in partnership with regulators, utilities and consumers.
Recent research and demonstrations show that customers will be partners in this transformation if engaged early and offered the right incentives. Industry leaders already are exploring innovative concepts and stepping out to test the waters.
The convergence of information and communications technologies with digital device capabilities stand to fuel a substantial transformation of North America’s electric system. It promises to release a wave of innovation and opportunities to see the power system as never before; tap the substantial resource of the demand side of the electricity system; improve efficiency and reduce greenhouse gas emissions; reduce dependence on energy imports; and simultaneously enhance asset utilization and overall reliability. The challenge lies in matching technology potential with regulatory reforms to allow the right incentive signal through to utilities and consumers.