The climate metric, maligned by the Trump administration, helps build the cost of future climate harms into state electricity plans and markets. Also see articles further down on Blockchain use by utilities and cooperatives.
BY PETER FAIRLEY, INSIDECLIMATE NEWS
AUG 14, 2017
The social cost of carbon takes into account the costs of future damage to human health, property and the environment connected to the burning of fossil fuels. Credit: Mark Wilson/Getty Images
The social cost of carbon was an arcane but important tool in the federal climate toolbox until President Donald Trump targeted it in his sweeping March 2017 executive order to weaken climate actions.
Now, states are taking up the metric.
Policymakers and regulators in several states, including New York, Minnesota, Illinois and Colorado, are using the social cost of carbon to measure and reduce CO2 impacts from their power grids. Some are using it to compensate rooftop solar panel owners who feed low-carbon power in the grid. Others use it to incentivize nuclear power and renewable energy. Their efforts, aimed at reducing planet-warming greenhouse gas emissions, come as Congress and the Trump administration try to restrict its use.
“It’s been striking to see the progress on this front even as the Trump administration has tried to undermine the use of a social cost of carbon,” said Rachel Cleetus, chief economist and manager of the climate program at the Union of Concerned Scientists.
Put simply, the social cost of carbon is a dollar estimate of the future damages from droughts, sea level rise, heat waves and other climate impacts wrought by each ton of carbon dioxide released to the atmosphere. Climate change caused by planet-warming CO2 emitted by fossil fuel power plants will diminish ecosystems, damage infrastructure and harm people’s health, but until there is a price on carbon, most of those costs will not be paid by power generators or passed on to their consumers. Instead they will be borne by the environment and the public.
By calculating a cost in today’s dollars for these impacts, and using it when regulating energy investments and implementing climate policies, the states can put cleaner energy sources on a more level playing field with fossil fuels. Wind and solar farms, nuclear power and energy conservation efforts are often less expensive than harmful alternatives when the damage potential of fossil fuels is taken into account.
Many corporations use a similar approach by incorporating a “shadow carbon price,” which bakes the future costs of climate change into their decision-making, Cleetus notes. Putting a price on carbon adds to today’s cost of polluting power plants, helping companies to more accurately evaluate how expensive these long-term investments could be in the future, especially if stronger climate policies down the road lead to plant shutdowns before they reach the end of their lifespan.
“When making investments that are going to be around for decades, you want to make sure they take account of future conditions,” Cleetus said.
Until recently, the use of a social cost of carbon at the state level has been overshadowed by another means of putting a price on carbon—”cap-and-trade” markets, such as California’s, which set a cap on statewide emissions but allow companies to buy or sell emissions allowances within that cap.
But experts say state adoption of a social cost of carbon may have even greater impact, because social cost of carbon estimates are typically higher than carbon market prices. While states are using a variety of values for a social cost of carbon, most are above $40 per ton—about three times higher than recent carbon prices on the California market.
Power Planning with Future Costs in Mind
Minnesota and Colorado have both made moves this year involving a social cost of carbon: their states’ public utility commissions (PUCs) issued rulings requiring their biggest utility—Xcel Energy—to consider a $43-per-ton social cost of carbon when planning new power plants.
“Whether the commissioners choose to act on it remains to be seen, but at least today they’ll have the information,” said Erin Overturf, chief energy counsel for the Boulder-based environmental group Western Resource Advocates, one of the petitioners that prompted the Colorado PUC ruling.
Colorado’s PUC told Xcel Energy to use $43 per ton of CO2 pollution generated starting in 2022 and to set a schedule for ramping that up to $69 per ton by 2050. The starting figure matches the last estimates from President Barack Obama’s Interagency Working Group on Social Cost of Carbon, which Trump has disbanded.
The figure includes all projected climate damages through the year 2300. It then adjusts them to present values using a 3 percent discount rate—a parameter that spurs much debate among economists. The federal working group used three discount rates: 2.5 percent, 3 percent and 5 percent; higher discount rates afford less current value to future costs, while lower values do the opposite.
Minnesota’s PUC followed suit in July. The state has used a social cost of carbon to guide its policies since 1993, but the value was outdated. The July ruling dramatically increased its upper range, from about $4.50 to $43 per ton. Xcel and other utilities will be expected to run cost-benefit studies using both a low-end figure, of just over $9, and the new high-end figure of $43, when assessing new power plant projects in the state.
Curiously, Xcel Energy appeared to take contradictory positions in the two states. Xcel’s environmental policy manager in Minnesota, Nicholas Martin, told its PUC that “bold action is needed” on climate change and that a higher social cost of carbon would empower Xcel to cut carbon emissions “aggressively and affordably.”
Meanwhile, in Colorado, Xcel officials went on the offensive against the social cost of carbon, arguing that it would be unduly “burdensome” and that large uncertainties in the federal working group’s calculations rendered it unreliable — echoing attacks by conservative think tanks and Republican leaders.
If a social cost of carbon had to be used, Xcel argued, it should include only those climate damages occurring in Colorado or the United States, rather than worldwide. That critique matches changes in federal policy Trump made via his executive order. Federal agencies should set their own social costs of carbon, Trump ordered, but could base them upon harms to the United States only, not the world. Of course, emissions go into the global atmosphere, causing global problems.
During the Colorado proceedings, advocates for climate action and solar power pushed back hard.
“It got pretty heated,” Overturf recalled. Only by valuing the impacts of climate change can the PUC consider how power plants in Colorado contribute to it and the harm it may cause to both Coloradans and the state’s power system.
“By completely excluding … externalities, you’re really just sticking your head in the sand,” she said. “We know that climate change makes our [power] generation fleet less efficient. We know that it causes wildfires and other natural disasters that affect our transmission and distribution system. We know that there are actual costs to utility customers that come from not acting to prevent catastrophic climate change.”
Xcel Energy did not make an official available to comment but provided a statement to InsideClimate News saying it already uses a shadow price to “account for the risk of future carbon regulation.” It added that Xcel opposed using the social cost of carbon in Colorado because that state’s PUC, unlike Minnesota’s, is not obligated by state statute to consider externalities such as climate damage.
Tilting the Scale to Cleaner Investments
The social cost of carbon is already having an impact on power choices in Minnesota, and that can only increase with the higher values approved in July, said Leigh Currie, senior staff attorney for the Minnesota Center for Environmental Advocacy and a leading proponent of Minnesota’s social cost of carbon boost.
She cites two examples where the PUC favored cleaner investments—proposed by power project developers or utilities—that cost a little more today but looked more economical when the social cost of carbon was added:
- In 2014, the PUC approved a solar project that made headlines as the first head-to-head win for utility-scale solar power without any state subsidies over competing natural gas proposals. Minnesota’s PUC picked the 100-megawatt solar project, proposed by Edina, MN-based Geronimo Energy, even though it cost “half a percent” more to build and run than the gas-fired competition. The PUC cited several countervailing factors favoring Geronimo’s project, including the social cost of carbon analysis. The resulting Aurora Solar photovoltaic power project, the state’s largest, was completed last fall.
- Last year, the PUC approved Xcel’s proposal to beginning shutting down the state’s largest coal-fired power plant early and replacing its generation with a combination of wind, solar and gas-fired power. In the standard cost study, shutting the coal generators appeared to be one of the most expensive options on the table, but the scenario including the social cost of carbon showed it to be the cheapest, Currie said.
Energy consultant and former Maine regulator David Littell, with the nonprofit The Regulatory Assistance Project, estimates that 10 to 20 state PUCs are likely using a social cost of carbon in such planning and procurement decisions, although they may be flying under the radar. He said Maine’s PUC used it during his service from 2010 to 2015.
Other states are giving the social cost of carbon at least an indirect role in competitive power markets, in which power plants bid to determine how often they run and what they earn for their electricity. Last year, New York and Illinois used the social cost of carbon to design revenue-boosting incentives to keep low-carbon nuclear power running despite stiff competition from cheap gas.
New York is now considering a broader application that would directly affect daily bids on the competitive power market.
New York’s concept is to add a fee, based on the social cost of carbon, to bids from coal, gas and diesel-fired power plants. “Generating units that emit carbon would incur a penalty based on their level of carbon emissions and the social cost attributed to carbon,” said Brad Jones, CEO of the New York Independent System Operator, in testimony before the House Committee on Energy and Commerce’s Subcommittee on Energy last month. “The penalties collected by the NYISO would then be returned to customers in some equitable manner,” he said.
Jones said the plan would harmonize NYISO’s wholesale markets with the state’s clean energy policies, which include goals to have half of the state’s power come from renewable sources and cut greenhouse gas emissions 40 percent by 2030.
The idea is popular with economists because it means the prices consumers pay will more closely reflect electricity’s full cost, including externalities (rather than just the cost to build and fuel power plants).
The Steel Winds wind farm in Lackawanna, N.Y., was built on the grounds of a former Bethlehem Steel Plant. New York has a goal of getting 50 percent of its power from renewable sources by 2030. Credit: John Moore/Getty Images
Littell expects that New York’s plan would give an advantage to cleaner resources. Wind and solar farms, nuclear plants, and energy conservation providers should operate more often, he said, and get paid as much as $15 more per megawatt-hour for their resource compared to a power plant burning natural gas. That is a substantial increase from the average $18- to $40-per-megawatt-hour rate that the state’s power suppliers earned last year (depending on the region).
John Moore, a senior attorney at the Natural Resources Defense Council, and Littell said the plan should also have a long-term effect on what types of plants get built, since investors make decisions based largely on the revenue they expect a plant will earn. Moore predicts that it will give a preference to gas plants that cost more to build but that operate more efficiently, and help cleaner options beat even the best gas plants “so that the region doesn’t just continue to rely heavily on natural gas.”
Using a social cost of carbon could help many more states avoid relying too heavily on gas, Cleetus said. She cited a 2015 report by the Union of Concerned Scientists that found that two-thirds of U.S. states were “putting their electricity consumers at financial risk because of an over-reliance on natural gas.” Florida ranked highest, followed by several other southeastern states, Ohio, and Pennsylvania.
NYISO, the New York state power grid operator released a study of its concept by the Brattle Group, a leading energy consultancy, on Friday. In a joint letter NYISO’s CEO Jones and his counterpart at the New York State Department of Public Service announced that they would collaboratively discuss its feasibility with “all stakeholders and market participants.”
Other markets could follow. PJM Interconnection, which operates a regional power market in the mid-Atlantic states, has already issued a proposal for integrating a carbon price.
New York has an advantage—since it has its own competitive market, it does not need to negotiate with other states to move forward. However, it will confront inevitable legal challenges from owners of fossil-fueled plants that argue using the social cost of carbon unfairly tilts the market against them.
Moore and others say recent federal court rulings on related challenges have been deferential to states’ rights to incentivize attributes of their power supply. But a challenge could also be lodged with the Federal Energy Regulatory Commission (FERC), which oversees wholesale electricity and gas markets and whose composition is in flux. The Senate recently approved two Republican Trump appointees to join the panel’s incumbent Democrat. (Two more Trump nominees, one from each party, await Senate confirmation.)
What may be critical for New York and other states using the social cost of carbon is how they implement it. Both the federal courts and FERC have favored state interventions in electricity markets when state leaders, including the legislature and governors, rather than power system operators, define the policy and then delegate its implementation. As Moore put it: “The more the state drives the policy, the more likely the courts and FERC are to go along with it.”
As for the federal government’s use of social cost of carbon? Although Trump killed the inter-agency working group that set values for all agencies to use, the social cost of carbon lives on in Washington as a diminished version of its former self. Trump empowered each federal agency to set its own value, inviting them to ignore climate damage outside the U.S.
That is likely to draw a legal battle since carbon emissions cause global damage, Cleetus said: “Clearly with this administration they’re going to attempt to lowball it. That will prompt legal challenges if they’re using a low number that doesn’t reflect the latest science or their legal obligations.”
Meanwhile, Cleetus said, we’re losing time. “If we don’t take it into account, it doesn’t go away. Society still bears that cost in terms of wildfires, or floods or sea level rise. You’re just shoving that cost onto Americans at large.”
- Xcel Energy and a diverse group of stakeholders in Colorado have reached an agreement that calls for the early retirement of two coal plants in the southern part of the state, and the potential for $2.5 billion in rural clean energy investments.
- Specifically, the plan calls for shutting down 660 MW of two coal-fired generation units at the Comanche Generating Station. Unit 1 would be mothballed at the end of 2022, and Unit 2 by the end of 2025. A third unit will remain operating.
- Xcel will also issue a competitive request for proposals for up to 1,000 MW of wind, up to 700 MW of solar, and up to 700 MW of natural gas and/or storage.
Xcel officials say the agreement, which supports the utility’s “Our Energy Future” campaign launched last year, could increase renewable energy’s share in the company’s generation portfolio to 55% by 2026, save customers money, and reduce carbon emissions.
The Colorado Public Utilities Commission still needs to approve the plan, but customer advocates hailed the potential to shutter more coal-fired plants. In addition to retiring two units at the Comanche plant, the plan also calls for construction of a new switching station for a southern Colorado transmission “energy resource zone,” designed to speed development of renewable generating resources in rural parts of the state.
No coal resource will be added as part of the RFP, Xcel said, and carbon emissions could be reduced by up to 60% by 2026, relative to 2005 levels.
Rick Gilliam, program director for Vote Solar, said in a statement the group was happy to see Xcel Energy’s efforts “to close coal plants, reduce carbon emissions, and move Colorado closer to a future where anyone can choose clean energy.”
Parties to the stipulation include Xcel, staff of the CPUC, the Colorado Office of Consumer Counsel, the Colorado Energy Office, the City of Boulder, and several other groups and companies.
The groups are asking regulators to approve the stipulation by the end of 2017.
The utility last year reached an agreement with solar interests in Colorado, launching a time-of-use rate pilot. The state gets about 22% of its energy from renewables, but according to Xcel it will surpass the state’s 30% renewable energy standard by 2020.
Blockchain for energy distribution
Austria and France, Britain and Brooklyn — utilities and startups on different continents are testing ways blockchain technology could usher in an altered future for electricity production and distribution.
“There are a number of utilities all over the world that are looking at blockchain,” said Dan Nossa, an attorney with Steptoe & Johnson’s Houston office who has been studying the technology that underpins the cryptocurrency bitcoin and its potential impacts on industries from finance, to real estate to energy.
Blockchain technology is a cryptographically secure, shared record of transactions, updated by a network of computers instead of a central authority. Every transaction within the system is secure, timestamped and linked with previous and subsequent transactions that can be seen by anyone with access to a given blockchain.
The technology has the potential to be ideal when it comes to simplifying complicated transactions and helping to digitally track physical assets, such as electricity, as they make their way from point A to point B. That potential makes the technology very attractive to large utilities and scrappy energy startups alike, because blockchain can be used to monitor energy consumption and trading alike.
In Brooklyn, startup LO3 Technology has been running a test using blockchain to track sales of solar energy by individuals to other individuals. Nasdaq is involved with Nevada startup Linq in using the blockchain to track sales of electricity back into the grid by individuals with solar panels. Meanwhile, Austria’s largest utility Wien Energie is testing blockchain technology for trading electricity between it and other utilities. Electron, a startup in Britain, is developing a blockchain platform to allow consumers to easily switch from one power provider to another.
There has been some speculation that blockchain technology could ultimately be used to help eliminate or curtail the role of utilities in the energy market. Nossa doesn’t see that as likely.
“I think they’ll probably maintain their roles,” he said. “I think blockchain can make the incumbents that much more efficient.”
The technology can be used in conjunction with Internet of Things technology to better measure electricity usage and collect payments. It could also help consumers see where electricity is coming from and whether, for instance, it is from a renewable source.
“It could be extremely beneficial to all types of energy management systems,” Nossa said.
Blockchain technology could be used by large electricity customers to help trade energy between them. A factory could sell or trade its unused power to another factory that needs it. That, according to a Harvard Business Review article, could yield big efficiency benefits to utilities.
In that article, James Basden and Michael Cottrell argue that, though blockchain technology could have a disruptive effect on utilities, it’s likely that the utilities themselves will be the ones doing the disrupting. They write:
“While there’s always room for startups to move in and disrupt this industry, established utilities are best placed to evaluate and make strategic bets on blockchain technology’s potential applications. If they can seize the moment, centralized incumbents may turn out to be the true disruptors, ushering in a new era of decentralized power.”
To learn how blockchain technology can affect your business, contact Daniel Nossa.
Steptoe & Johnson PLLC is a U.S. law firm with core strengths in energy, labor and employment, litigation and transactional law, serving clients from its 13 strategic locations across the nation. In 2013, Steptoe & Johnson celebrated 100 years of helping clients reach their goals.
Earlier this year, a first-of-its-kind microgrid was commissioned at the Marcus Garvey Apartment complex in Brooklyn’s Brownsville neighborhood in New York City. Like many microgrid projects, it combined renewable energy (in this case, solar PV) with battery storage, as well as a fuel cell. It’s connected to the grid and provides multiple local benefits, including clean energy generation and resiliency. The system also generates revenue and savings through demand charge reduction, capacity relief, and other grid services.
The owners of the apartment complex, L+M Development Partners, have a guiding principle to develop quality affordable, mixed-income, and market rate housing while improving the neighborhoods in which they work. As with other properties in their portfolio, L+M also sought to make the development energy efficient and reduce its carbon footprint — and an innovative microgrid was the answer.
What makes this Brooklyn microgrid unique are these attributes:
- First to use lithium-ion batteries in a behind-the-meter multi-family (625 units) complex in NYC
- First renewable-energy-plus-storage microgrid in a low- to middle-income housing development
- First solar + storage + fuel cell microgrid, optimized to manage multiple services and revenue streams
- First microgrid deployed under Consolidated Edison’s Brooklyn-Queens Demand Management Program
The industry has taken notice. Earlier this month, the Marcus Garvey microgrid project won the prestigious ESNA Innovation Award for Distributed Storage, given at the annual Energy Storage North America conference.
The award was proudly accepted by a team from Demand Energy*, the company that designed and integrated the system and developed the control software that operates it. Its successful deployment and operation are a notable proof point of the value of intelligently designed and managed multi-resource microgrids, especially in grid-constrained areas.
Optimizing Benefits & Driving Revenue with Intelligent Software
This innovative microgrid consists of a 400 kW solar PV system and 400 kW fuel cell, supported by 300 kW / 1.2 MWh lithium-ion batteries and controlled by Demand Energy’s Distributed Energy Network Operating System (DEN.OSTM), which optimizes how these resources interact and perform. The system is reducing the property’s power consumption by managing the generation and storage of renewable energy to save money through demand charge reduction. It also provides resiliency during an outage, lowers operational cost, delivers essential load relief for Con Edison, and helps reduce greenhouse gas emissions.
The battery system stores solar energy during the midday period and supplies it to reduce peak loads between 8:00 pm and midnight. On days when loading is not critical, the microgrid can be used to reduce demand charges that are incurred based on Con Edison’s delivery rate. If there is a grid outage, the apartment complex’s management office and community center can be powered by the microgrid to provide local resiliency.
A key technical aspect of the project is the ability of DEN.OS to ensure that the housing development self-consumes any energy it generates, without exporting to the grid. That capability directly aligns with the utility’s Brooklyn-Queens Demand Management (BQDM) requirements, which facilitated the interconnection and permitting process.
After the Hurricane: Reimagining New York’s Electrical System
New York City is one of the most energy-intensive urban environments in the world. The peak summer loading of Con Edison’s service territory (NYC and Westchester County) approaches 14 GW of demand — almost a quarter of the peak demand in all of California. In addition, while nearly 60 percent of the state’s electricity is consumed in the New York City area, only 40 percent of it is generated there. This urban grid delivers energy primarily through an underground network, which makes managing and maintaining the system an expensive and challenging endeavor to continue to meet growing peak load.
For the first 100 years or so, utilities had their revenues tied to how much electricity a customer used. Based on a longstanding regulatory model, the greater the usage, the greater the revenue (and utility earnings). Utilities today face a long list of challenges — from aging infrastructure and stagnant demand growth to federal emissions standards and increased renewables penetration. But rather than tackle these issues separately, New York’s leadership decided to take a holistic view.
The result? Reforming the Energy Vision (REV) initiative. REV seeks to solve one overarching problem at the heart of all: The traditional utility business model is not aligned with societal goals nor with the rapidly evolving, increasingly distributed, two-way electric grid.
REV came about in direct response to the reality of climate change and the devastating impact of Hurricane Sandy. The state needed to develop a more resilient grid while finding ways to encourage third-party renewable energy developers to engage in a new grid operating model. Building out renewable and other distributed energy resources at the edge of the grid could help resolve the loss of power during extended outages — and address another major need: meeting peak power demands on critical days.
Aligning Customers, Businesses, & Society
Revenue decoupling was a key to the solution. Utilities now have incentives to help customers use less energy. But with REV, instead of having utilities passively resist solar and other distributed energy resources, REV aims to align utility business objectives with societal goals and let them harness the full potential of technologies coming onto the grid.
The REV vision is to integrate distributed resources into the grid to the point where they help manage the increasingly complex needs of New York’s power systems. Thanks to REV, Con Edison has been empowered to solve a growing demand problem in a less traditional but far more cost-effective way: by making the grid more efficient, creating a new model for earning returns.
The Marcus Garvey microgrid benefits the property owners and residents through enhanced resiliency, clean operation and energy savings. It provides benefits to the local utility — and indirectly to its ratepayers — and is compensated for them. It also aligns perfectly with the state’s vision of moving to a two-way distributed grid that serves longer-term energy goals.
New York City has long been a strong proponent of affordable housing. The city has also advocated for increased use of renewable energy and improved energy consumption and efficiency. This award-winning project combines both initiatives.
Thanks to Demand Energy’s intelligent storage management software, the Marcus Garvey microgrid provides the added benefits of energy security and resiliency, as well as revenue streams from grid services that enhance the return on investment. You can read more about the project by downloading the case study here.
Duke Energy to Invest $6B for Solar, Batteries and EVs, Scrap Nuclear Plant Plans
Florida is set to get a lot more solar power and grid batteries — in exchange for losing a future nuclear power plant.
On Tuesday, Duke Energy Florida filed a revised settlement that lays out a four-year, nearly $6 billion investment into 700 megawatts of solar PV, 50 megawatts of energy storage, 500 electric-vehicle chargers, and smart meters and grid modernization across the state.
In exchange, Duke will shut down work on its Levy Nuclear Project — one of many planned nuclear power plant projects being canceled in the wake of the Westinghouse bankruptcy and broader industry disruption. And, in a turnaround from last week’s request for an 8.3 percent rate hike, the new plan would keep rates in line with inflation over the next four years.
Duke Energy Florida, which owns about 8,800 megawatts of generation capacity and serves approximately 1.8 million customers, will instead absorb more than $150 million in existing investments. It will also remove the project’s closing costs from customers bills, saving them about $2.50 per megawatt-hour. It will also reduce customer costs by $2.53 per megawatt-hour by spreading the costs for under-recovered fuel over two years rather than one.
The settlement before the Florida Public Service Commission was reached with industry, commercial, agricultural and environmental groups, represents a major new commitment to clean and flexible energy resources for the Duke Energy subsidiary. The 700 megawatts of solar is an order of magnitude greater than its current PV portfolio, and will be compressed from 10 years to four under the new proposal. And its 50-megawatt energy storage deployment and 500-charger EV infrastructure investment are its first large-scale forays into those technologies.
Florida’s energy storage landscape has until recently been dominated by pilot projects, according to the GTM Research Energy Storage Data Hub. But in the past year, we’ve seen two of the state’s biggest utilities commit to multi-megawatt projects: Duke and Florida Power & Light.
In November, Florida Power & Light won PSC approval for a four-year rate case that includes a 50-megawatt pilot program to “enhance operations of existing and/or planned solar facilities, among other potential benefits.” The NextEra Energy subsidiary has been working on pilots, including a battery backup system at the southern tip of Everglades National Park and second-life EV batteries in Miami; it also has eight 74.5-megawatt solar farms opening across the state.
Duke Energy Florida, for its part, didn’t provide many details on how it plans to develop and deploy its new 50-megawatt target. Its previous experience includes a 100-kilowatt solar-battery system it deployed with the University of South Florida St. Petersburg in 2015.
The utility, acquired by Duke as part of its merger with Progress Energy, also didn’t provide specifics on its plans to roll out smart meters to customers, although it did note they will “enable more bill-lowering tools, access to more information about energy use, and the ability to receive usage alerts, outage notifications and customized billing options once fully implemented.”
The grid modernization investments will “enhance reliability, reduce outages, shorten restoration times and support the growth of renewable energy and emerging technologies,” it noted.
Duke is also struggling to absorb the costs of closing down nuclear power plant projects in North Carolina. Last week, Duke told state regulators it was abandoning its Lee Nuclear Station project, and asked for permission to raise rates by 13.9 percent to cover the costs.
Across its six-state territory, Duke Energy still gets most of its electricity from natural gas, coal and nuclear power plants, with wind making up about 1 percent and solar power about 0.5 percent. The screenshot below from Duke’s power plants website shows only two solar projects on-line in Florida, compared to two coal-fired power plants and 11 gas-fired power plants — a ratio that’s set to radically change over the next four years.