By Paul Molitor, NEMA
In February 2009, the California Energy Commission (CEC) issued a Request for Proposals (RFP) to “define the pathway to the California smart grid of 2020.” As stated in the RFP, among the challenges that California electric utilities will face are systems interoperability, communications and common information model standards, implementation schedules, well-defined interfaces and adapters to legacy systems. To a systems integrator, this sounds like the startup checklist to any project. To an electric utility, it’s a whole new ballgame.
How Did We Get Here?
On a Web page created by the National Academy of Engineering, “electrification” is listed as the greatest achievement of the 20th century. The academy goes on to say that “with the merest flick of a finger, each one of us taps into vast sources of energy—deep veins of coal and great reservoirs of oil, sweeping winds and rushing waters, the hidden power of the atom and the radiance of the sun itself—all transformed into electricity, the workhorse of the modern world.” As many have since noted, while the electric grid may be viewed by some as the greatest achievement of the 20th century, the problem is it is now the 21st century—and much of the grid is in need of a makeover.
Since the mid- to late-1990s, a number of people have been contemplating and investigating methods for improving the grid. With no clear leadership on the issue, any interested party was free to come up with its own vision of what constituted a smart grid. Pioneers include the Electric Power Research Institute’s Intelligrid program and the Gridwise Architecture Council, in addition to a handful of state-level programs and commercial “smart energy” products that evolved early on. On the legislative side, a major step toward unifying the U.S. smart grid effort was taken in Title XIII of the Energy Independence and Security Act (EISA) of 2007. However, while the government clarified its smart grid vision in EISA, the bill was left on the table as an unfunded mandate for nearly two years. Beyond the funding issue, a map for the provisions of EISA spread responsibilities across a variety of federal agencies.
Within EISA, federal leadership was finally established under the Department of Energy, Assistant Secretary of the Office of Electricity Delivery and Energy Reliability. The government’s plan came together with the passage of the stimulus bill in February of this year (the American Reinvestment and Recovery Act of 2009, or ARRA). With the funding vehicle for EISA finally in place, programs like the CEC Smart Grid Pathway to 2020 were off to the races.
Goals of the State of California
In terms of smart grid implementation, the state of California is often cited as a leader. In fact, for the GridWeek Conference 2008 in Washington, D.C., an entire day dedicated to state stories included California as a case study. Panelist and speakers for the program were chosen in part, based on their involvement in deploying smart grid concepts and technologies within the state. With a number of initiatives already under way, California’s smart grid goals represent the most common objectives that governors and state legislators wish to achieve. They are:
- Support California utilities’ ongoing advanced metering infrastructure system implementations.
- Operate the future smart grid with a substantially increased percentage of renewable resources.
- Reduce greenhouse gases.
- Implement state directives for aggressive energy efficiency and demand response goals.
- Modernize the aging utility grid infrastructure.
- Meet future energy growth needs with new and innovative technologies.
To some, it’s interesting to note that keeping electricity affordable for the California consumer is absent from the list.
The biggest challenges that the California Energy Commission, Public Utility Commission and utilities face include the EISA provisions that were assigned to the Federal Energy Regulatory Commission (FERC): power grid digital information technologies, federal jurisdiction, transmission corridors and cyber security.
Power Grid Digital Information Technologies
Many Americans would be surprised to learn that in the age of computers, split-second timing, twitter, and up-to-the-minute information, the most critical central management systems for the electric grid in some utilities are updated only on a 15-minute interval. Clearly, power system management would benefit greatly from the application of digital information technologies.
Implementation of this concept, however, represents a significant challenge as many monitored elements of the grid either hang on telephone poles or are located in remote substations where there is often little, if any, access to communications facilities larger than a phone line.
Additionally, computing capability presence also implies that communications, processing power and memory can be added to electricity producing and transmitting elements. In some cases, the physical design of these devices is very tightly controlled by organizations such as Occupational Safety and Health Administration (OSHA) and regulations like the National Electric Code. Adding IT functionality to them could imply months of red tape; research and development alone would add to the manufacturing process, along with expenses associated with implementing and integrating the new technologies with the existing utility systems.
Federal jurisdiction is a longstanding concern for state initiatives like the California Pathway to 2020, based on the simple fact that power lines and many utility company control areas cross state lines. This introduces the notion of interstate commerce to the discussion which could, in some cases, limit the state’s ability to create and enforce its own energy codes. Adding to that the actions of federal agencies like FERC, the Consumer Product Safety Commission and OSHA, creates a real mess. With the realistic possibility that any one of these players may implement a code or rule that impacts a state activity, an environment is created in which the state must tread lightly as it attempts to shape its energy policy and avoid costly financial burdens on utilities. Although the rate cases are handled through state utility commissions, ultimately the costs for retrofitting implementations and stranded assets based on a change in federal regulations would be borne by the state’s rate payers.
During late 2008 and early 2009, Americans were treated to a series of ads by billionaire oilman T. Boone Pickens, extolling the virtues of renewable energy, namely wind. Suddenly “The Pickens Plan” was a topic of conversation across the country with its simple brilliance: build big wind farms to meet future energy needs and use natural gas (as opposed to Middle Eastern oil) to bridge the gap until wind energy could be harvested. News reports mentioned high profile interests in the Pickens Plan including joint appearances with former President Bill Clinton, and a list of investors that included members of Congress including Speaker of the House Nancy Pelosi.
The bad news started in July of 2009, when Mr. Pickens was forced to abandon his original wind farm design because he simply couldn’t get access to the transmission lines necessary to get the energy from where the wind was blowing in the Texas panhandle to where the electricity was needed. Even with a roster of high-profile friends and investors, the regulatory deck apparently stacked in his favor, and a fair amount of public support from his Web site and television ads, the flagship effort in the Pickens Plan had to be abandoned.
On the Project/No Project Web site (pnp.uschamber.com), the U.S. Chamber of Commerce lists numerous transmission projects that have either been killed or are facing opposition from landowners, environmental groups and other interest parties. In the description of a dead transmission project in Northern California that would have been capable of delivering 4,000 MW of renewable energy to Sacramento and the Bay Area, the site notes that “no major power lines have been installed in Northern California in 16 years, despite substantial growth and increasing energy demand.”
Last, but not least, is cyber security. For the last several years, national headlines and the evening news have been filled with stories of hackers penetrating the operating systems of various retailers and financial institutions to capture and exploit their customer’s financial information. On April 8, 2009, the Wall Street Journal broke a story describing how cyber spies in Russia and China “penetrated the U.S. electrical grid and left behind software programs that could be used to disrupt the system.” Given that the financial losses associated with the Northeastern blackout of 2003 were estimated in the tens of billions of dollars, a prolonged, aggressive cyber attack on the electric grid could have long-term financial impact on the U.S. economy. If it’s conducted in conjunction with some additional natural disaster, it could have life or death consequences. (Think of the compound effect with something like Hurricane Katrina.) Given these kinds of impacts, it’s obvious that for any smart grid effort, cyber security must be included in the design.
Years ago, as a young technician in the networking world, I asked a wise, old technical manager how the sales people in our company could continually get away with putting us in a position where we had to stretch the capabilities of our products in order to meet customer’s expectations. “Because,” he said, “selling and installing are two different things.” With smart grid, the American public has clearly been sold on the concept, and now it is up the regulators, manufacturers and utilities to install it.
Paul Molitor is National Electrical Manufacturers Association’s (NEMA’s) smart grid director.