Diverse Portfolios: The Next Generation in Electricity Generation
Originally published July 1, 2017
As the economics of traditional power operations become more challenging, public power utilities are turning to a range of cutting-edge generation resources — from small modular reactors to renewables.
“As community-owned utilities, our members are at ground zero for a lot of changes, from energy efficiency to decisions about decommissioning plants,” said Carolyn Slaughter, director of environmental policy at the American Public Power Association. “Our planning horizons are long-lived because we’re making the most economical decisions for operating these units. We don’t make decisions for three years; we look at 30-year horizons.”
The Association’s Public Power Forward initiative aims to help public power utilities prepare for the new era in electricity. It includes a business, policy and technology assessment toolbox that utilities can use in their own business models to meet customer demands with next-generation energy sources.
Given their smaller size and community connection, public power utilities are uniquely positioned to broaden their generation portfolios in response to customer preferences. Many utilities are getting at least some of their electricity from newer energy sources like solar, wind, and combined-cycle natural gas.
In fall 2016, Missouri-based Independence Power and Light began constructing the first phase of the Independence Community Solar Farm. The move was driven by a city council resolution directing IPL to increase renewable energy in its generation profile, as well as strong community support — a key factor in community solar.
IPL contracted with a solar construction firm to build the farm and agreed to buy all the power output. IPL then asked the community to subsidize a portion of the cost by offering 1-kilowatt units of output from the solar farm for an additional fixed cost of 1.65 cents per kilowatt-hour of solar energy produced.
“IPL sold 100 percent of the available shares in less than one year,” IPL Director Leon Daggett said. “The response from our community has been overwhelmingly favorable.”
To connect to the grid, the community solar farm’s output passes through a series of inverters and transformers that convert the energy from DC to AC. Then the voltage enters IPL’s distribution system and is tied into the system’s electrical lines.
Community solar offers a solution to one of solar’s biggest challenges: higher costs compared to traditional generation. “Although the overall cost of solar PV is decreasing, solar energy in the Midwest still costs two to three times more than market energy prices,” Daggett said. Community solar mitigates the adverse impacts on retail rates.
Now, IPL is working on the second phase of the community solar project. Though it’s still in the initial planning stages and no decisions have been made, the current location can accommodate another 4 megawatts of solar.
Floating solar panels
Solar panels in fields have become a common sight. Seeing solar panels floating on a body of water is more unusual. That’s the approach Orlando Utilities Commission took when it installed a floating solar array earlier this year on a pond near its operations center in southwest Orlando, Florida.
“The floating solar array uses existing spaces without trees. We did a study and found 9,000 lakes, ponds and other bodies of water in our county, which are all potential options for solar,” said Byron Knibbs, OUC’s vice president of emerging technology.
The company installed 100 panels that produce 31.5 kW. “They are a grid asset, and we treat the facility just like a power plant going into the grid,” Knibbs said. “Electrons go into an inverter where they go from DC to AC, and then right into the grid via a transformer.”
To ensure it was installing solar panels that would withstand storms and damage from being housed on the water, OUC purchased the panels from Ciel & Terre, a company that provides equipment for floating solar arrays in Europe and Asia, where they are more popular.
Compared with many next-generation energy sources, the floating solar array was inexpensive, costing $90,000. “Our customers are excited about this new grid asset and many of our other innovative programs,” said Knibbs. “At OUC, our goal is to make solar both accessible and affordable, and this is just one of the ways we are doing so.”
The East Coast is a hotbed for offshore wind projects. In the past, wind turbines could be installed only five miles off the coast, which is close enough to see from shore. Now, they can be built further offshore, making them much less visible from land. “You really go from opposition to widespread community support,” said Long Island Power Authority CEO Tom Falcone.
Falcone noted that LIPA has been looking at offshore wind “for 10-plus years because we’re on Long Island. We jut out in the ocean and are surrounded by offshore wind resources, like high wind speeds and shallow waters.”
A few years ago, transmission in one of LIPA’s load pockets needed to be upgraded. Following the lead of New York Gov. Andrew Cuomo’s Reforming the Energy Vision, LIPA realized it was a prime opportunity to procure renewable resources and decided to venture into offshore wind.
LIPA is working with offshore wind energy development group Deepwater Wind, which will build the 90-megawatt Deepwater ONE South Fork wind farm — the first built off New York. It will be 30 miles off the coast and connected to shore via a transmission cable buried six feet under the ocean floor. Once on shore, the cable will run 10 miles to a LIPA substation.
LIPA signed a pay-for-performance contract, which commits the utility to purchasing power generated from the wind farm at an agreed-on cost for 20 years.
The U.S. offshore wind market is still in its nascent phase, at least compared with other parts of the world, such as Europe. But the East Coast is seeing increased offshore wind activity.
In late 2016, Deepwater Wind said the Block Island Wind Farm had completed its commissioning and testing phases and begun commercial operations, delivering electricity into the New England region’s grid on a regular basis. The energy produced from the Block Island Wind Farm is linked to the New England grid by a new National Grid submarine transmission cable system.
Legislation signed into law by Massachusetts Gov. Charlie Baker last year calls for the procurement of approximately 1,600 megawatts of offshore wind by utilities in the state. And in May 2017, Maryland regulators cleared the way for the development of a combined 368 megawatts of offshore wind capacity.
A few years ago, the Michigan-based Lansing Board of Water and Light faced a dilemma. It needed to upgrade three steam production units and three coal-fired electric generating units, which would require substantial investment to meet environmental regulations. Instead, BWL replaced the outdated units with a new natural gas combined-cycle cogeneration plant.
“Natural gas combined-cycle cogeneration plants are very efficient, dramatically reduce emissions compared to the coal-fired units, comply with foreseeable air regulations, have broad community support, and help diversify the BWL’s fuel mix,” said Stephen Serkaian, executive director of public affairs for BWL.
BWL supplies electricity to the Lansing area as well as steam to downtown Lansing for manufacturing processes, building heating, and domestic hot water. Making the switch to natural gas helped the utility ensure it could continue to maintain its central steam business.
The plant generates up to 300,000 pounds of steam for 225 customers in downtown Lansing, and 100 percent of BWL’s steam generation. In addition, the plant generates 100 MW of clean, highly reliable electricity, which provides 20 percent of BWL’s total electric generation.
Making the switch from coal to natural gas was relatively easy. It took two years to build the cogeneration plant, and many existing operators, with the right training, were able to continue to run the natural gas plant. Like the coal units, the natural gas plant is interconnected to the grid by BWL’s transmission system.
The move from coal to natural gas was an important step in BWL’s commitment to provide 30 percent clean energy by 2020 and 40 percent clean energy by 2030. The plant decreased greenhouse gas emissions by 50 percent compared to the coal-fired units it replaced, by eliminating the need to burn 351,000 tons of coal. The new plant also lowered mercury and sulfur dioxide emissions by more than 99 percent, compared to the coal-fired units, as well as nitrogen oxide emissions by more than 85 percent.
With three hydroelectric facilities brought online in 2016, another nearing commercial operation, and a number of other existing hydro facilities, American Municipal Power’s work in the hydro sector represents the country’s largest deployment of clean, renewable run-of-the-river hydroelectric generation in recent years.
Hydro is a no-brainer for AMP, which is headquartered in Columbus, Ohio. For hydro to be a viable option, two things are needed, according to Phil Meier, AMP’s vice president of hydroelectric development and operations. The first is headwater, which is the difference between the upstream and downstream level. The second is flow, which needs to be powerful enough to generate energy. To determine whether a water source will work for hydro, those two aspects need to be reviewed and averaged out over a number of years.
“The Ohio River is a prime location for hydro facilities, because there’s enough head differential and a significant amount of river flow,” Meier said.
If enough headwater and flow are available, hydro is a powerful energy source. In Ohio, hydro achieves an approximately 60 percent capacity factor, compared to up to 40 percent achieved from wind, according to Meier.
The utility began working with hydro in 1999, when it opened the Belleville Hydroelectric Facility, which is a 42-MW run-of-the-river hydroelectric generation facility. Since then, AMP has developed a number of additional hydro facilities, including the Combined Hydroelectric Project, which consists of three run-of-the-river hydro generation facilities at existing dams on the Ohio River.
With a powerful generation source like the Ohio River, Meier said hydro is a clean and renewable option that can last more than 100 years with routine maintenance.
Pumped storage can be described as the original energy storage battery. It’s a good way to meet peak demand and allow use of intermittent sources of power, such as wind and solar. It can provide more reliable service by releasing water at any time, preventing fluctuations in frequency and voltage. And for utilities in drought-prone areas, pumped storage saves water by reusing water supply.
Public power utilities are already using pumped storage. For example, the New York Power Authority operates the Blenheim-Gilboa Pumped Storage Power Plant, while the Tennessee Valley Authority’s Raccoon Mountain Pumped Storage Plant is TVA’s largest hydroelectric facility.
Other public power entities are actively pursuing pumped storage. In late 2016, South Dakota-based Missouri River Energy Services said that it had applied for a new permit to study the potential for a 1,200-megawatt pumped storage hydroelectric facility, known as the Gregory County Pumped Storage Project, on the Missouri River in south-central South Dakota.
The vision for the Gregory County Pumped Storage Project is that it will be a regional project with several utilities and/or joint action agencies partnering to develop this resource. MRES noted that the project would be too big to develop on its own.
Other public power utilities have kicked the tires on pumped storage and decided not to pursue it. The Sacramento Municipal Utility District planned on constructing the 400-MW Iowa Hill pumped storage project along the Upper American River Project at Slab Creek Reservoir in El Dorado County, California. However, as planning progressed, SMUD decided to cancel the project. Cost estimates exceeded $1.45 billion, which was much higher than expected.
“An investment that size would significantly limit the choices SMUD has with regard to future distributed generation technologies and could have significantly constrained future capital investments,” said Frankie McDermott, chief energy delivery officer at SMUD.
SMUD also determined the amount of storage provided would be more than double the amount necessary prior to 2030. “With recent advances in other energy storage technologies, it’s likely there will be more economical alternatives for satisfying SMUD’s long-term energy storage needs,” McDermott said.
McDermott said the industry is moving away from large, central plants and toward a wider distribution of energy resources, including battery storage. The utility also expects the technology for storing electricity in lithium-ion batteries to become more economical.
While the Iowa Hill project is officially off the table, SMUD continues to keep an eye on advancements in the electric utility industry to meet its future energy needs.
Small Modular Reactors
Meanwhile, public power is also on the cutting edge when it comes to the future of nuclear power through small modular reactors.
Utah Associated Municipal Power Systems took a step forward in the development of its Carbon Free Power Project by exploring the feasibility of nuclear through small modular reactors. UAMPS provides wholesale electricity to more than 40 public power utilities in the Intermountain West. CEO and General Manager Doug Hunter says nuclear energy represents a market-based solution to greenhouse gas emissions and other Clean Air Act pollutants. UAMPS is partnering with NuScale Power on this SMR project.
NuScale Power submitted its design application in early 2017 to the Nuclear Regulatory Commission to approve the company’s 12-module SMR commercial power plant design. NuScale noted that this was the first-ever SMR design certification application to be submitted to the NRC.
“We are delighted that our friends at NuScale have completed this step, which is key to our project licensing and our target commercial operation date of 2026 for the UAMPS Carbon Free Power Project,” said Hunter in a Jan. 12 news release issued by NuScale. Another public power entity, Energy Northwest, will operate the SMR plant.
UAMPS has identified a preferred site within the boundary of the Energy Department’s Idaho National Laboratory, near Idaho Falls. The site selection process was conducted in collaboration with the Energy Department.
Small modular reactors are just one of the three elements of the Carbon Free Power Project. Distributed generation and energy efficiency are the other key components.
The NuScale SMR consists of integrated pressurized water reactor modules, designed on the light water reactor technology that has safely operated worldwide for 70 years. Each module’s generating capacity will be 50 megawatts, and up to 12 modules can be grouped in a single power plant installation of 600 MW.
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