The term "Smart Grid" refers to new power-distribution system technology that permits the flow of information from a customer's meter in two directions: both inside the facility to thermostats, smart appliances, and other devices, and back to the utility. Expected benefits include increased grid reliability as additional information from the distribution system is available to utility operators. This technology will allow for better planning and operations during periods of peak demand, according to its supporters.
In last month's article, I introduced the latest news about Smart Grid developments and briefly mentioned the latest federal legislation that is now prodding it from research and development into institutional implementation (Energy Independence and Security Act of 2007, PL110-140) Following is some more about the law and what it presumes to accomplish - all of which will affect your bottom line. The main source for this information is a report, Code RL34288, prepared for Congress and issued in December 2007 by the Congressional Research Service, authored by Amy Abel, specialist in energy policy. But, a brief Google search of the Internet discloses that Smart Grid news and analysis is an increasing topic of popular interest among the trade press.
Maybe you already know this, but perhaps a review of the electrical system from the government report could provide a baseline. Most electricity in the United States is generated at power plants that use fossil fuels (oil, gas, and coal), nuclear fission, or renewable energy (hydropower, geothermal, solar, wind, and biomass). (There is some localized distributed power generated on-site, but that is not part of this analysis.) At the power plant, energy is converted into a set of three alternating electric currents (called "three-phase power"). In a three-phase system, the phases are offset 120 degrees from each other as the generator rotor spins through a full circle, with each phase producing a sinusoidal wave form of voltage and current. After power is generated, the first step in delivering electricity to the consumer is to transform the power from medium-voltage (15-50 kilovolt [kV]) to high-voltage (138-765 kV) alternating current. This initial step-up of voltage occurs in a transformer located at transmission substations at the generating plants. High voltages allow power to flow long distances with the greatest efficiency because transmission-line losses are minimized. The three phases of power are carried over three wires that are connected to large transmission towers. Close to the ultimate consumer, the power is stepped-down by a transformer at another substation to lower voltages, typically less than 15 kV. At this point, the power is considered to have left the transmission system and entered the local-distribution system for service to individually metered users. Service-protection breakers are located throughout the system, which are designed to shut it down under dangerous overloaded conditions. It's in the distribution system that Smart Grid technology is being introduced.
Due to previous federal energy policies, states have the authority to regulate the system from end-to-end in vertically integrated companies, or to adopt a variety of deregulation schemes. Interstate-power transmission is regulated by the Federal Energy Regulatory Commission (FERC). About 18 states have required utility companies to spin off their generation assets into independent power producers and to operate primarily as regulated delivery companies. This has created a competitive generation business that sells power at wholesale prices into the grid system, giving consumers more choices in selection of power sources, wherever available (and encouraging more renewable-generation methods). But, the transition from controlled monopolies to competitive providers has been a rocky road with many disappointments for consumers, investors, and providers. The transmission system continues to become more congested; siting and upgrading transmission lines continues to be difficult. Efforts are being made in both industry and government to modernize electric-distribution equipment to improve communications between utilities and the ultimate consumer. Some utilities have been using smart meters that can be read remotely, primarily for billing purposes. These meters, however, do not provide communication back to the utility with information on voltage, current levels, and specific usage. Similarly, these meters have very limited ability to allow consumers to either automatically or selectively change their usage patterns based on information provided by the utility.
If FERC and the states cannot determine which Smart Grid costs should be considered transmission-related (federally regulated) and which should be considered distribution-related (state regulated), utilities may be reluctant to make large investments in Smart Grid technologies. Another issue limiting the deployment of this technology is the lack of consistent standards and protocols. To overcome these barriers, Title XIII of the act stipulates the following specific responsibilities of the various federal agencies involved:
"Within 90 days of enactment (from Dec. 19, 2007), the Secretary of Energy shall establish a Smart Grid Advisory Committee, whose mission is to advise the Secretary of Energy and other relevant federal officials on the development of Smart Grid technologies, the deployment of such technologies, and the development of widely accepted technical and practical standards and protocols to allow interoperability and integration among Smart Grid capable devices, and the optimal means for using federal incentive authority to encourage such programs. In addition, a Smart Grid Task Force shall be established within 90 days of enactment. This task force will be composed of employees of the Department of Energy, Federal Energy Regulatory Commission, and the National Institute of Standards and Technology. The mission of the Smart Grid Task Force is to ensure coordination and integration of activities among the federal agencies."
The Congressional report disclosed that several utility companies have proposed the installation of new Smart Grid meters. Southern California Edison (SCE) proposes, throughout its service territory (approximately 5.3 million meters), to install advanced meters in all households and businesses under 200 kW through its SmartConnectTM program. The new system is expected to reduce demand response at peak times, which could save as much as 1,000 megawatts of capacity additions. That is about equivalent to a standard coal-fired power plant. SCE is planning to use three telecommunications elements in addition to a smart meter. The telecommunications system will include a Home Area Network (HAN) plus a Local Area Network (LAN) consisting of a proprietary, two-way narrowband radio frequency network that will connect the meters to the electricity aggregator. (An electric aggregator purchases power at wholesale from various providers for resale to retail customers.) A Wide Area Network (WAN) will be installed using a non-proprietary open standard two-way broadband network that will be used to communicate between the aggregator and the utility back-office systems. For the consumer, benefits include load reduction and energy conservation, which could result in lower electric bills. Outage information will automatically be sent to the utilities so customers won't need to report these disturbances. SCE is expecting to achieve greater reliability over time as additional information from the system is available to manage operations. Manual meter reading will be eliminated, as will field-service trips to turn power on to new customers.
TXU Electric Delivery plans to have 3 million automated meters installed primarily in the Dallas-Ft. Worth area by 2011. As of Dec. 31, 2006, TXU had installed 285,000 advanced meters, 10,000 of which had broadband over power line (BPL) capabilities. This system combines advanced meters manufactured by Landis+Gyr with BPL-enabled communications technology provided by CURRENT Technologies. TXU Electric Delivery said that, in the near term, it will primarily use the advanced meters for increased network reliability and power quality, and to prevent, detect, and restore customer outages more effectively. TXU expects that electric delivery will eventually include time-of-use options and new billing methods to its consumers.
On Jan. 16, 2008, the Smart Grid Consortium announced the vision of a "Smart Grid City" led by Xcel Energy. The advanced Smart Grid system is expected to allow Xcel Energy to work in tandem with customers to determine when, where, and how they use their energy. "We are on the verge of significant transformation in an industry that has seen relatively little change during its long history," says Dick Kelly, chairman, president, and CEO of Xcel Energy. "Using the Smart Grid, we can provide innovative solutions to the environmental challenges facing all of us today."
Among the consortium's initial tasks will be selection (this spring) of a midsize community with a population of approximately 100,000 residents somewhere within the company's trade area in the upper Midwest. The city will represent the consumer end of the Smart Grid, with a fully interconnected system managing the various parts of the grid involved in producing power and delivering it to customers. The chosen city will become a test bed for emerging technologies and deployment strategies. The goal is to create an international showcase of Smart Grid possibilities and evaluate their environmental, financial, and operational benefits.
The bottom line is that utility infrastructure is poised for a major upgrade that could bring technology into a new era of power-usage management. Keeping up with the developments could be both fun and profitable.
