U.S. utility companies are engaged in a difficult transition. Environmental constraints, resource concerns and transmission-siting challenges are driving the industry toward a 21st century operating model whose shape is only starting to emerge.
Given this dynamic state of evolution, it’s not surprising that next-generation technologies are undergoing their own difficult transitions. Some new technologies are being embraced by the market, but others are struggling to gain regulatory and financial support. This transition is exemplified by four high-tech projects being executed by four electric utilities, including Duke Energy, American Electric Power, Consolidated Edison and San Diego Gas & Electric. Their projects address different parts of the power-supply chain, and they’re taking different paths to secure financing and regulatory acceptance.
Duke and AEP are striving to update the central-station coal model by introducing utility-scale integrated gasification combined cycle (IGCC) plants and carbon sequestration technology. In New York, Con Edison’s Hydra project provides a window to the future as urban utilities grapple with grid congestion. And SDG&E is looking beyond the horizon, toward an emerging distributed-resources model, and creating a smart micro-grid right in its own backyard.
Duke Energy Indiana (formerly Cinergy) is building a $2.3 billion 629-MW IGCC facility at its Edwardsport plant near Vincennes, Ind. The project is scheduled to go commercial in 2012 and will be the first to employ the standardized IGGC reference plant design developed under a General Electric/Bechtel alliance, employing GE (formerly Texaco) gasification technology.
With a service territory in need of additional generating capacity, Duke Indiana proposed an advanced, environmentally-friendly power generation technology that state regulators already were familiar with, and that could burn locally mined coal, thereby benefiting the state’s economy. Further, Duke opted to site the project at Edwardsport, an aging coal- and oil-fired power plant that’s due to be retired.
The proposal relied on an assortment of state and federal tax breaks that would make the overall cost comparable to a traditional least-cost power generation technology, with the possibility of an adjacent carbon sequestration pilot that, if successful, could further enhance the project’s environmental performance.
The Indiana Utility Regulatory Commission gave Duke its certificates of need and public convenience to proceed in November 2007, and the Indiana Department of Environmental Management issued an air permit in January 2008. Further, regulators granted a series of rate increases that will help pay for the new plant during the construction phase.
The rate impact of the construction costs partially will be reduced by more than $460 million in local, state and federal tax incentives. Duke says the plant will result in an average electric rate increase of approximately 18 percent, phased in from 2008 through 2013.
“While the project will cost 20-percent more (than traditional coal-fired technologies), the tax incentives helped bridge that gap,” says Duke spokeswoman Angeline Protogere. “As of March, procurement, engineering, and construction are 20-percent complete. General Electric will deliver the syngas coolers in mid-June.”
Duke Indiana says the IGCC facility will be able to produce nearly four times as much power as the existing Edwardsport plant, with significantly less environmental impact, including 45-percent less carbon dioxide emissions per net-megawatt hour. Upon the new plant’s completion in 2011, the existing 1944- and 1951-era coal and oil-fired units will be retired.
The state’s experience with IGCC technology at Duke Indiana’s Wabash River Station in West Terre Haute in the 1990s, helped as well. It was there that the DOE demonstrated a 260-MW petroleum coke gasification plant, one of the first coal gasification projects to produce electricity on a utility scale.
“We didn’t own the IGCC, but the gas it produced was burned in one of our turbines. It’s a much smaller unit than the one that will operate at Edwardsport. But that obviously helped us because state regulators were familiar with the technology,” Protogere says.
When IGCC technology was introduced back in 2007, Duke Indiana President Jim Stanley touted its ability to burn Indiana coals. “The Edwardsport facility fits Indiana’s energy plan to turn homegrown natural resources into an economic engine and be self-reliant for power. It’s part of our overall plan to meet growing customer needs with cleaner coal technology, energy efficiency, and renewables,” Stanley said.
Once the new unit is running, Duke Indiana says it will study the potential for removing carbon dioxide from coal during the syngas conversion process to either store or sequester it in underground geologic formations. In May, the utility announced it received $1 million in funds from the DOE’s Regional Carbon Sequestration Partnership Program.
“It’s important to use early projects like this one to get IGCC off the ground,” Protogere says. “This is the first time the technology is being used on this scale. As more are built, the costs should come down because the designs become standardized.”
No utility is pulling for Duke Indiana’s success more than its neighbor, Columbus, Ohio-based AEP.
AEP was the first U.S. electric utility to announce plans to scale up IGCC technology. Unfortunately, the two $2.3 billion (each) 629-MW IGCC projects it proposed for Great Bend in Meigs County, Ohio, and its 1,300-MW Mountaineer Plant near New Haven, W.Va., currently are on hold. Ironically, a separate carbon sequestration demonstration project, also at the Mountaineer Plant, is scheduled to begin operation in September.
Both projects won early regulatory approvals. In April 2006, the Public Utilities Commission of Ohio (PUCO) approved AEP’s request to charge its customers $23 million for Great Bend’s pre-construction costs. A year later, the Ohio Power Siting Board approved the project’s site selection. In March, 2008, the West Virginia PSC granted a certificate of public convenience and necessity for the Mountaineer project.
But then things began to unravel. In 2008, the Ohio Supreme Court sent the project back to the PUCO for further review. At issue is whether the project can qualify for rate recovery as a regulated utility asset under the state’s still-changing electric deregulation statutes. That, along with the economic downturn and decreased electrical demand, prompted AEP to place Great Bend on the back burner.
Further, since the Mountaineer IGCC facility would supply part of its output to Virginia, regulators in Virginia also had to approve it. In April 2008, the Virginia State Corporation Commission (SCC) denied the $1 billion rate recovery request, saying the project is too risky.
“In Ohio, it’s not clear yet whether we’ll be able to get regulatory recovery on Great Bend,” says AEP spokeswoman Melissa McHenry. “We’ve always said we won’t build it unless we get the rate recovery. Plus, with the economy down, we don’t really need the additional generation right away. We still want to develop both projects. It might be easier once the federal carbon legislation is ironed out and the emissions requirements are clearer.”
However, AEP is nearly finished building a $120 million carbon sequestration project at the Mountaineer plant site. In May, the West Virginia Department of Environmental Protection awarded AEP the state’s first carbon dioxide sequestration permit for the 20-MW CO2 capture process validation facility (PVF).
The PVF is based on Alstom’s chilled ammonia process technology, and will capture approximately 100,000 tons of CO2 per year. The CO2 will be compressed and stored in saline formations located about 8,000 feet below the earth’s surface.
AEP is picking up more than half of the project’s cost, with Alstom and other participants contributing the rest. “The project was too small to qualify for DOE funding, which requires you to capture at least 300,000 tons of CO2 per year,” McHenry says. “We haven’t decided whether we’ll seek cost recovery on it. We may use R&D funding.”
McHenry added that AEP already is looking to scale up the technology and has applied for DOE funding for a project that would capture carbon dioxide from a 235-MW flue gas stream at the Mountaineer Plant.
In May, the DOE formally announced $2.4 billion from the American Recovery and Reinvestment Act will be used to expand and accelerate the commercial deployment of carbon capture and storage (CCS) technology. Though a final cost has not been determined yet, AEP hopes to use DOE funding to help underwrite the project, which is expected to have a 90-percent capture rate, or approximately 1.5 million tons of CO2 per year.
At Consolidated Edison, a pilot program called “Project Hydra” will test the ability of superconductor power cables to deliver up to 10 times more power (using 10 times less underground space) through the Manhattan grid. ConEd also expects the project to improve reliability by allowing the utility to re-route load from one part of the grid to another in an emergency, and to suppress power surges, or fault currents, that can disrupt services and damage power system equipment.
“This is unique because it will allow us to route much more electricity through a single cable and demonstrate a new type of fault current limiting superconductor, which has never been done before,” says Pat Duggan, a project manager for Con Edison. “That’s key because in a large network like ours, a fault with a normally 2,000 amp path can, and sometimes does, jump to 40 kA at 13 kV, or 63 kA at 138 kV and 345 kV. These are realistic fault currents for bolted faults, validated by oscillograph readings.”
The full-scale, 700 foot-long, high temperature superconductor (HTS) cable will run under city streets and connect two Manhattan substations. If there’s a problem at one substation, the connection will allow Con Edison to shift some of its load over to the other.
Common events, such as storms or accidents, can produce large spikes or “faults” in current that can damage electrical equipment or cause power failures. The cable’s fault-limiting capabilities will protect the grid by allowing normal current to pass through unimpeded. If and when it senses fault current, the technology instantly prevents a large increase in the electrical flow, choking off a potentially damaging electrical spike. Once the fault current subsides, the cable will allow standard levels of current to flow, thus protecting the electrical system automatically without human intervention.
“Once we get beyond this economic downturn, we see our electric load increasing substantially. That means there will be more devices on the grid that could contribute to a fault,” Duggan says. “As a utility, we’re hoping superconductor technologies will get smaller and cheaper. This project will demonstrate the cable in an urban environment, at a site under varying conditions that include rats, road salt and voltage transients.”
The project is being funded mainly by the Federal Department of Homeland Security (DHS), which is picking up $25 million of the $39 million tab. DHS is interested in the technology’s capacity and fault-limiting capabilities to prevent an isolated problem from turning into a cascading failure. The rest of the cost is being shared by American Superconductor Corp., which is providing the cable, along with Con Edison and the New York State Energy Research and Development Authority. If the project delivers on its promise for Con Edison, it could pave the way for future utility commercialization of superconductor technology.
“To get a regulator’s approval, you need to explain the project so they can understand all the benefits and why it deserves to be supported,” Duggan says. “If this project proves to be viable, it could help to achieve a breakthrough over the installed cost of copper, if we could use this more compact fault current limiting superconducting cable design to fit these cables within existing ducts, rather than excavating under city streets. We have roughly 94,000 miles of underground cable in our system. Obviously we won’t replace all of it, but superconductor technology could be extremely beneficial at specific points within the system.”
In August, SDG&E begins a three-year, $12.5 million proof-of-concept pilot, subsidized in part by the DOE, that will determine whether existing information technologies can be used to leverage distributed energy resources and create a true smart grid.
Doing so, the utility says, could allow more power to be delivered through existing infrastructure, thereby reducing the need to build more T&D facilities. Additionally, it might increase reliability by adding elements that make the grid more stable and reconfigurable.
The test will be carried out over the next three years on a portion of SDG&E’s existing distribution network in Borrego Springs, a rural community of about 3,000 mainly residential customers at the eastern edge of the utility’s service territory.
The area is served by a single substation and historically has had reliability problems, making it a good candidate for the pilot. The project will consist of three circuits and include existing or planned distributed generation assets operated by the utility, as well as businesses and residential customers. SDG&E’s AMI program, which will install 200,000 smart meters by the end of the year and a total of 1.4 million by the end of 2011, also will play a key role.
“We tell regulators that the smart grid is not a revolution, it’s an evolution,” says Tom Bialek, chief engineer on the project. “We need R&D funding to explore and demonstrate the benefits of technology now so we can come back to them with a larger-scale application later on. It was received favorably by the California Public Utilities Commission and the California Energy Commission. They view this as a step towards meeting the state’s energy goals of incorporating more renewable energy, providing energy choice and lowering electricity bills.”
SDG&E will install sensors and controls to continuously monitor and control the microgrid’s operating conditions. It will monitor, for example, power produced (or capable of being produced) by utility- and customer-owned generation inside the microgrid zone, including solar generators, storage capacity and commercial and industrial on-site generation. It also will be able to monitor the impact of demand-response measures, if and when they’re activated. All of this will allow SDG&E to manage the amount of electricity used by customers on the three circuits.
“We’ll know real-time electrical demand and the distributed energy resources that are available,” explains Lee Krevat, director of SDG&E’s Smart Green Grid initiative. “If a customer is generating power with solar panels, for example, we need to know that because of the intermittent nature of renewable resources. Right now we have an optional demand-response program for central air conditioning, but we don’t know whether a unit is actually running when we call the event. With sensors and AMI, we’ll know the exact impact of the demand-response program and whether we need to leverage other assets, such as energy storage. If necessary, we’ll be able to isolate that area from the rest of the grid without an outage to customers.”
The overall goal is to achieve greater than 15-percent reduction in feeder peak load, integrate its AMI smart meters with microgrid operations, demonstrate VAR management and integrate feeder automation technologies. That, in turn, will let SDG&E better integrate an outage management and distribution management system into the microgrid operations.
“This is an alternative service delivery model where customers are viewed as potential energy resources rather than simply consumers,” Bialek says. “We’ll be able to access distributed generation, renewables on both the customer and utility side, energy storage, reciprocating engines, and demand response. All this will be available to help balance load and generation in real time, and to maintain the voltage frequency levels.”
Additionally, regulators and other state officials will get to see the value and importance of smart-grid technologies now, rather than later.
“There are two big changes coming in California,” Krevat says. “First, renewables are becoming a larger percentage of the energy mix and, in the future, there will be more intermittency issues. We need to be sure we can manage that now, before the problem gets here. Second, electric vehicles are coming. If they recharge at night, that’s great. But if they charge during peak times, that could cause system problems. We don’t know how fast these changes are coming, but we know we’ll need new ways to oversee what’s going on out there.”