The U.S. Environmental Protection Agency has finalized a rule to start eliminating a class of climate-warming chemicals that are widely used as coolants in refrigerators, air conditioners and heat pumps.
If that plan feels like déjà vu, it should.
These chemicals, called hydrofluorocarbons, or HFCs, were commercialized in the 1990s as a replacement for earlier refrigerants that were based on chlorofluorocarbons, or CFCs. CFCs were destroying the ozone layer high in the Earth’s atmosphere, which is essential for protecting life from the Sun’s harmful ultraviolet radiation.
HFCs are less harmful than CFCs, but they create another problem – they have a strong heat-trapping effect that is contributing to global warming.
Several states have announced plans over the past few years for phasing out HFCs. Now the EPA, following a vote in Congress in 2020, has established federal regulations to cut HFC production and imports starting in 2022, and aims to reduce their production and use by 85% within 15 years.
If HFCs can be phased down globally – as many countries have agreed to do under the 2016 Kigali Amendment to the Montreal Protocol – that would avoid about half a degree Celsius of temperature rise compared to preindustrial times. China, a major producer of these chemicals, ratified the amendment effective Sept. 15, 2021.
Let’s take a closer look at what HFCs are and what might replace them next.How HFCs keep rooms and food cool
Refrigerators and air conditioning use a technology known as a heat pump. It sounds almost miraculous – heat pumps use energy to take heat out of a cold place and dump it in a warm place.
Here’s how a refrigerator works: A fluid – CFCs back in the old days, and now HFCs – circulates in the walls of the refrigerator, absorbing the ambient heat to keep the fridge cooled down. As that liquid absorbs the heat, it evaporates. The resulting vapor is pumped to the coils on the back of the refrigerator, where it is condensed back to a liquid under pressure. In the process, the heat that was absorbed from inside the fridge is released into the surrounding room. Air conditioners and home heat pumps do precisely the same thing: they use electric-powered compressors and evaporators to move heat into or out of a house. https://www.youtube.com/embed/viM36llqxCU?wmode=transparent&start=0 How a refrigerator works.
Choosing the right fluid for a refrigerator means finding a substance that can be evaporated and condensed at the right temperatures by changing the pressure on the fluid.
CFCs seemed to fit the bill perfectly. They didn’t react with the tubing or compressors to corrode the equipment, and they weren’t toxic or flammable.
Unfortunately, the chemical stability of CFCs turned out to be a problem that threatened the whole world, as scientists discovered in the 1980s. Leaking CFCs, mostly from discarded equipment, remain in the atmosphere for a long time. Eventually they make their way to the stratosphere, where they are finally destroyed by UV radiation from the sun. But when they break down, they create chlorine that reacts with the protective ozone, letting dangerous radiation through to the Earth’s surface.
When production of CFCs was eliminated in the 1990s to protect the ozone layer, new refrigerants were developed and the industry shifted to HFCs.Why HFCs are a climate problem
HFCs are like CFCs but much more reactive in air, so they never reach the stratosphere where they could harm Earth’s protective radiation shield. They largely saved the world from impending ozone disaster, and they are now found in refrigerators and heat pumps everywhere.
But while HFCs’ chemical reactivity prevents them from depleting the ozone layer, their molecular structure allows them to absorb a lot of thermal radiation, making them a greenhouse gas. Like carbon dioxide on steroids, HFCs are extremely good at capturing infrared photons emitted by the Earth. Some of this radiant energy warms the climate.
Unlike CO2, reactive HFCs are consumed by chemistry in the air, so they only warm the climate for a decade or two. But a little bit goes a long way – each HFC molecule absorbs thousands of times as much heat as a CO2 molecule, making them powerful climate pollutants.HFC emissions are increasing. The chart shows their anticipated growth without control measures in place. Netherlands National Institute for Public Health and the Environment
HFCs leaking from discarded cooling equipment are estimated to contribute about 4% of global greenhouse gas emissions – about twice as much as aviation.
This is why it’s time to retire HFCs and swap them out for alternative refrigerants. They’ve done their job saving the ozone layer, but now HFCs are a major contributor to short-term global warming, and their use has been increasing as demand for cooling increases around the world.What can replace HFCs?
Because they are so powerful and short-lived, stopping the production and use of HFCs can have a significant cooling effect on the climate over the next couple of decades, buying time as the world converts its energy supply from fossil fuels to cleaner sources.
The good news is that there are alternative refrigerants.
Ammonia and hydrocarbons like butane evaporate at room temperature and have been used as refrigerants since the early 20th century. These gases are short-lived, but they have a downside. Their greater reactivity means their compressors and plumbing have to be more corrosion-resistant and leak-proof to be safe.The U.S. Environmental Protection Agency has finalized a rule to start eliminating a class of climate-warming chemicals that are widely used as coolants in refrigerators, air conditioners and heat pumps. (Courtesy: Justin Sanchez/Unsplash)
The chemical industry has been developing newer alternatives intended to be safer for both people and climate, but as we saw with CFCs and HFCs, inert chemicals can have unintended consequences. Several industry leaders have supported efforts to phase out HFCs.
So, it’s time for another generation of cooling equipment. Just as our TVs and audio equipment and light bulbs have evolved over past decades, our refrigerators and air conditioners will be replaced by a new wave of improved products. New refrigerators will look and work just like the ones we’re used to, but they will be much gentler on the climate system.
This article was updated Sept. 23, 2021, with EPA formalizing the new rule and China ratifying the Kigali Amendment.
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Eric Garcetti, Mayor of Los Angeles, USA, has launched the C40 Renewable Energy Declaration to help cities around the world accelerate the transition to clean energy resources in an equitable manner.
Some 15 mayors have signed the declaration to increase the pace at which their cities are deploying renewable energy resources to create healthier communities, improve air quality, create green jobs and protect their most vulnerable residents from the impacts of climate change.
The declaration outlines three pathways that can also enable the cities to provide residents with clean and affordable electricity:
Mayors that have signed the declaration include those of London, Copenhagen (which plans to achieve carbon-neutral by 2025), Lisbon, Melbourne (Australia’s first capital city council to be powered by renewables), San Francisco, Tokyo, Tswane, Vancouver and Seoul.
The need to establish the declaration is the result of global cities struggling to reduce emissions from buildings, electricity, and heating use, which account for more than two-thirds of global energy consumption, according to a statement.
Michael R. Bloomberg, UN Secretary-General’s Special Envoy for Climate Ambition and Solutions, said: “Cities drive the global economy, which means they produce much of the world’s greenhouse gas emissions. But cities are also leading the fight against climate change and for cleaner air – and in the process, they are creating good jobs and healthier communities.
“The more mayors around the world who commit to powering their cities with 100% clean energy, and the more concrete actions they take to achieve it, the faster we can create a stronger, healthier, and more sustainable global economy.”
With cities playing a leading role, the transition to powering and heating buildings with green energy is likely to increase, said a statement. The declaration is expected to push cities into seeking partnerships with governments, communities, technology firms and utilities in deploying renewable energy solutions.
By doing so, not only do they accelerate the energy transition and climate mitigation, but also leverage the distributed energy resources to increase electrification and address energy poverty.
Today, some 760 million people around the world lack access to electricity, according to the statement. By deploying distributed solar and district heating systems, the cities are expected to create 5.5 million green jobs annually by 2030.
Projects set to be deployed by cities that have pledged with the C40 Renewable Energy Declaration are expected to help ensure a green recovery from the pandemic.
Mayor of Los Angeles, Eric Garcetti, added: “Nearly half of Los Angeles’ power supply is fueled by renewable energy, and we’ve committed to achieving a 100% clean energy grid by 2035 – 10 years ahead of schedule. Through this declaration, C40 cities are showing the world that relying on renewable energy is not only possible, but more affordable, equitable, and sustainable.”
Chief of Government of Buenos Aires, Horacio Rodriguez Larreta, reiterated: “In Buenos Aires, we know that the transition to renewable energy sources and their efficient use is one of the main ways to achieve our ambitious emissions reductions. This is why we work to promote energy efficiency: in 2019 we became the first city in Latin America to have 100% LED public lighting.”
The Biden administration's Solar Futures Study calls for 45% of the U.S. electricity supply to come from solar by 2050. That means bigger (and more efficient) solar farms -- a massive opportunity for companies that inspect and optimize utility-scale arrays.
Mark Culpepper, general manager of solar solutions for DroneBase, a renewable energy asset ariel imaging firm, foresees significant growth in demand for monitoring at scale to follow federal ambitions.
DroneBase specializes in manned and unmanned ariel analysis of solar photovoltaic arrays using thermal imagining by identifying performance loss in modules that overheat. The company's platform then prioritizes fixes that offer the highest return for the asset owner before dispatching crews.
The company once identified 10,000 defects on a 200 MW portfolio for a client in North Carolina and was able to prioritize just 200 projects for repair that would recover most of the asset owner's losses.
"I think we're still early days in a lot of ways for this sector," Culpepper told Renewable Energy World in an interview, estimating that about 30-40% of utility-scale solar systems in the U.S. have been thermally inspected. "We have this huge challenge in front of us (climate change), but a huge opportunity, too. By the time we're done, the planet will be better off."Raptor Maps serial number scanning software
The Solar Futures Study calls for the U.S. to install an average of 30 GW of solar capacity per year between now and 2025, then 60 GW per year from 2025.
Solar data analytics and monitoring firm Raptor Maps recently used its smartphone software to scan nearly 1 million module serial numbers at a 300 MW solar PV system in California. The technology is being used to track and mitigate degradation. The company also releases guides to solar PV inspections using manned and unmanned aircraft.
"Raptor Maps is excited about the Solar Futures Study as it validates the need for the industry to find solutions to help it scale," Raptor Maps CEO Nikhil Vadhavkar said. "Because our software strengthens asset efficiency, boosts staff effectiveness and ultimately lifts financial return of PV assets, we’re helping to make solar more bankable, playing an integral role in fueling the industry’s rapid growth."
The U.S. added 4.8 gigawatts of utility-scale solar capacity in the first half of 2021, a 15% increase from the first half of 2020 and nearly halfway to the total capacity added in 2020, according to an analysis by S&P Global Market Intelligence.
The U.S. now has 53.7 GW of total solar capacity (including distributed generation). A pipeline of 17.4 GW of utility-scale capacity is under construction.
The Biden administration released a blueprint earlier this month that details a goal of generating 45% of the U.S. electricity supply from solar by 2050. That would require the U.S. to install an average of 30 GW of solar capacity per year between now and 2025, then 60 GW per year from 2025.
The following is a list of the 10 largest utility-scale solar projects completed in the first half of 2021 (through May 31) based on S&P analysis.Robins Air Force Base Solar Project - Bibb, GA Robins Air Force Base Solar Project (Courtesy: E Light Electric)
The 128 MW Robins Air Force Base Solar Project is owned by Georgia Power, a subsidiary of Southern Company, and is located adjacent to the Robins Air Force Base. The project was Georgia power's sixth working with the U.S. Military and Georgia PSC. When it was first announced, the Robins Air Force Base Solar Project was expected to feature 500,000 solar panels.
Georgia Power owns an additional 120 MW of utility-scale solar projects at Georgia military bases, located at Fort Benning, Fort Gordon, Fort Stewart, and SUBASE Kings Bay.9. Hardin Solar Energy Center Facility - Hardin, OH
Acquired by Dominion Energy in January, the 150 MW Hardin Solar Energy Center Facility was developed by Invenery, and is located on 1,100 acres in Hardin, Ohio.
Facebook will take the electricity generated at the facility as well as the renewable energy credits, under a long-term agreement signed prior to the project’s construction.
This marks Dominion Energy’s first solar energy investment in Ohio, where the company owns and operates a Cleveland-based natural gas local distribution company serving 1.2 million customer accounts in northeastern Ohio. Dominion owns solar arrays in nine other states, including in North Carolina, South Carolina and Utah, where the company also owns and operates gas utilities.8. Rancho Seco Solar II Project - Sacramento, CA Rancho Seco Nuclear Generating Station
D.E. Shaw Renewable Investments purchased the 160 MW Rancho Seco Solar II Project in Sacramento, California from Lendlease, an international property and infrastructure group. The project has a 30-year Power Purchase Agreement in place with the Sacramento Municipal Utility District and was built on the site of a decommissioned nuclear power plant.7. Impact Solar Project (G.S.E. Twelve) - Lamar, TX Impact Solar Project (Courtesy: Lightsource bp)
The S&P classifies the Impact Solar Project as a 199 MW facility, though the project's owner, Lightsource bp, says the facility has 260 MW of capacity. Most of the energy generated by the project goes to bp through a power purchase agreement.6. Anson Solar Center - Jones, TX Anson Solar Project (Courtesy: Engie)
The 200 MW Anson Solar Center is located on 2,200 acres in Jones, Texas and is owned by Engie. Microsoft announced in 2019 that it would purchase 85 MW from the Anson Solar Center through a power purchase agreement.5. RE Maplewood Solar Project Phase 1 and 2 - Pecos, TX Maplewood Solar Project (Courtesy: Recurrent Energy)
An undisclosed annuity and life insurance company purchased the 250 MW Maplewood 1 and 2 Solar Projects in July from Recurrent Energy. Anheuser-Busch and Energy Transfer Partners have signed 15-year power purchase agreements with the project.4. Copper Mountain Solar V - Clark, NV Copper Mountain Solar V (Courtesy: Sukut Construction)
The 250 MW Copper Mountain Solar V project in Clark, Nevada is owned by Consolidated Edison Inc.3. Taygete Energy Project - Pecos, TX Taygete Energy Project (Courtesy: 7x Energy)
7X Energy developed and owns the 255 MW Taygete Energy Project. The project is sited on approximately 2,000 acres in Pecos, Texas and features 856,000 solar modules. Energy from the project will be sold under a multi-year power purchase agreement to an undisclosed buyer.2. Greasewood Solar Project - Pecos, TX
The 255 MW Greasewood Solar Project, owned by Copenhagen Infrastructure Partners, was the second-largest utility-scale solar project completed in the first half of 2021 in the U.S. The Greasewood Solar Project has long-term power purchase agreements with the City of Garland, New Braunfels Utilities, and the Kerrville Public Utility Board in Texas.1. Eunice Solar Project (Permian Energy Center) - Andrews, Texas Ørsted brought the largest solar power project online in Q2 2021 -- the 420 MW Eunice Solar Project in Andrews, Texas. (Courtesy: Ørsted)
Danish renewable energy giant Ørsted owns the 420 MW Eunice Solar Project in Andrew, Texas, the largest utility-scale solar project completed in the first half of 2021 in the U.S. The Permian Energy Center features 40 MW of battery storage located alongside existing oil and gas infrastructure.
Global supply chain pressures led to a year-over-year decline in new solar power capacity additions in the second quarter of 2021 in the U.S., according to an analysis by S&P Global Market Intelligence. But, researchers wrote, demand is strong with 17.4 gigawatts of capacity under construction.
The U.S. added 1,968 MW of utility-scale solar power capacity in the second quarter of 2021, 31% less than the amount installed in the first quarter.
"Typically, the second and third quarters are the slowest for solar power capacity additions. But the second quarter of 2021 saw fewer capacity additions than the year-ago period when 2,104 MW was connected to U.S. power grids," the researchers wrote.
The U.S. now has 53.8 GW of total solar power capacity, including distributed generation. Ørsted brought the largest solar power project online in Q2 2021 -- the 420 MW Eunice Solar Project in Andrews, Texas.
S&P Global Market Intelligence found that Texas leads the nation in solar projects in advanced development or under construction with 7.4 GW of capacity in late-project phases, significantly ahead of North Carolina (2.6 GW) and California (2.2 GW). Researchers note that demand for utility-scale solar power capacity remains high from corporations and governments.
"Attracted by the cheap costs of solar power, fossil fuel companies are helping drive demand in West Texas. In April, the U.S. Energy Information Administration projected Texas will add a record 10 GW of utility-scale solar power capacity by the end of 2022, with 30% of the additions in the sun-soaked Permian Basin," researchers wrote.
NextEra Energy has the largest solar power project pipeline with 11.3 GW of capacity in all stages of development, followed by Invenergy, EDF Group, SunChase Power, Macquarie Group, and AES Corp.
Oregon-based energy storage firm ESS Tech has been commissioned to deliver 17 of its long-duration Warehouse iron flow battery systems for a hybrid project in Spain.
The order with Enel Green Power Espana contracts ESS to supply the energy storage complement to support a solar farm in Spain. The ESS system will offer a combined capacity of 8 MWh to provide resilience for the local power grid.
“We are 100% committed to energy storage as an essential complement to our expanding portfolio of renewable energy projects,” said Pasquale Salza, Head of Long-Duration Storage and Hybrid Systems for Enel Green Power. “With this project, we’re going to assess and validate the ESS flow batteries, which we selected due to their right combination of long-duration capacity, long-life performance, environmental sustainability, and safe operation.”
ESS is collaborating on the project with global systems firm Loccioni and engineering firm Enertis.
The ESS iron flow systems utilize iron, salt and water for the electrolyte. This combination eliminates fire and explosion risks, according to the company.
ESS has previously contracted to deliver its energy storage systems for projects in Pennsylvania, Patagonia, and Germany, among others.
Earlier this month, special purpose acquisition company ACON S2 Acquisition Corp. announced it was merging with ESS to create a publicly-traded company. The deal still requires shareholder and regulatory approvals.
Preliminary findings of a joint investigation into the freeze that left millions in Texas without power for days last February highlighted an increasing frequency of extreme cold weather events, as well as the devastation caused by the failure of natural gas-fired plants.
The joint report issued by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) cited freezing and natural gas fuel supply issues, including the failure to identify natural gas production and processing facilities as critical load, as the two largest causes for the disaster.
"Of the 1,823 unplanned outages, derates, and failures to start caused by freezing issues, 1,244 were in ERCOT, 473 were in SPP, and 106 were in MISO South," the report reads. "The most common sub-causes of generation outages and derates due to freezing issues were frozen instrumentation (sensing lines, transmitters) and icing on wind turbine generator blades."
Across ERCOT, SPP and MISO South regions, 55% of natural gas generating units (by MW of capacity) experienced unplanned outages and derates, compared to 22% of wind and 1% of solar.
Sean Gallagher, vice president of state and regulatory affairs for the Solar Energy Industries Association, commended the reliability of solar following the release of the FERC/NERC report.
“Even during record-breaking low temperatures in Texas, solar assets performed as expected during the February 2021 Texas blackout," Gallagher said in a statement. “Solar and storage will be a big part of the solution in Texas, and we look forward to working with state and federal leaders to continue to make it easier and faster to get solar projects online.”
FERC and NERC issued 28 preliminary recommendations in response to February's extreme weather event, calling for reliability standards that require winterization for new and existing infrastructure and the protection of natural gas infrastructure from manual and automatic load shedding.
The report recommended further study of additional ERCOT connections, noting that SPP and MISO South benefited from connections with other regions.
Jeff Dennis, managing director and general counsel for the Advanced Energy Economy association, provided a live tweet summary of FERC/NERC's presentation of the report, noting FERC Chair Richard Glick's opposition to political rhetoric that renewables were the source of the problems.
"Today’s FERC/NERC Staff report to the Commission made a clear case that these cold weather-driven outages of generating resources are not 'black swan' events, but increasingly regular occurrences and that they have interconnected impacts on both the electricity and natural gas fuel supplies," Dennis said in an email to Renewable Energy World. "FERC and NERC appear poised to implement mandatory reliability standards to ensure that generators are prepared for these events and that planners and operators anticipate them better in the future."
Glick hits back on political rhetoric that renewables were a problem here. Notes all generation types were impacted, focuses on natural gas.— Jeff Dennis (@EnergyLawJeff) September 23, 2021
Renewable energy advocates are closely watching the Texas Public Utility Commission's grid redesign to see if the renewables are unfairly burdened with resiliency costs.
In August, the U.S. Partnership for Renewable Energy Finance – made up of a coalition of corporations that includes Google, Amazon Web Services, and Goldman Sachs – sent a letter urging Texas leaders to scrap anti-renewable energy proposals crafted in response to the storm.
The letter addressed to Gov. Greg Abbott, Public Utility Commission of Texas Chairman Peter Lake, and leaders in the state legislature, said current policy proposals are built on the false premise that renewable energy sources – like wind and solar – were to blame for the outages.
In July, Abbott directed the PUC to “allocate reliability costs to generation resources that cannot guarantee their own availability, such as wind or solar power” and to “streamline incentives within the ERCOT market to foster the development and maintenance of adequate and reliable sources of power, like natural gas, coal, and nuclear power.”September 23, 2021
GE Renewable Energy has been selected by Kaylon to deliver solar power stations for 1.3 GW of projects in Turkey, the company announced Thursday.
GE will supply its FLEXINVERTER* solar power stations to the 270 MW Karapinar phase II-A and 810 MW Karapinar phase II-B solar plants, in addition to the power stations already commissioned at the 267 MW Karapinar phase I solar plant.
The agreement represents the first time GE has supplied its FLEXINVERTER* technology outside the US.
“There is tremendous potential for solar energy in Turkey which can be addressed through smart solutions that will help integrate this natural energy source into the grid in a reliable way and at utility scale," said Prakash Chandra, CEO Renewable Hybrids at GE Renewable Energy. "We are thrilled to be partnering with Kalyon on these projects and look forward to more opportunities to increase the penetration of renewable energy in Turkey.”
GE's FLEXINVERTER* solar power station combines a solar inverter, medium voltage power transformer, and an optional MV Ring Main Unit, integrated in a 20-feet ISO high cube container.
The project in Turkey's Konya Karapinar province is expected to reach commercial operations by December 2022.
In its latest Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration forecasts that electricity generation from U.S. hydropower plants will be 14% lower in 2021 than it was in 2020.
This is a result of “extreme and exceptional” drought conditions that have been affecting much of the western U.S., especially California and states in the Pacific Northwest, which are home to the majority of U.S. hydropower capacity. The Pacific Northwest’s Columbia River is the fourth-largest river in the U.S. by volume. Its watershed, the Columbia River Basin, covers large parts of Washington, Oregon, Idaho and Montana. In 2020, hydropower plants in these states generated 136 billion kWh of electricity, representing 54% of U.S. hydropower generation that year.
After dry conditions and a record-breaking heat wave affected large parts of the Columbia River Basin this summer, drought emergencies were declared in counties across Washington, Oregon and Idaho. The dry conditions have reduced reservoir storage levels in some Columbia River Basin states. According to the U.S. Department of Agriculture’s National Water and Climate Center (NWCC), reservoir storage in Montana and Washington is at or above average. However, as of the end of August 2021, reservoir storage in Oregon measured 17% of capacity, less than half its historical average capacity of 47%. Idaho reported reservoir storage at 34% of capacity, lower than its historical average capacity of 51%.
In March and April of 2021, hydropower generation in Washington and Oregon was 10% below the 10-year (2011 to 2020) range. Over the summer, hydropower generation in these states moved back within the 10-year range.
California contains 13% of the U.S.’ hydropower capacity. In 2020, hydropower plants in California produced 7% of the country’s hydro generation. However, the state is experiencing intense and widespread drought this year, which has reduced water supply and hydropower generation. The reservoir at Lake Oroville, the second-largest reservoir in California, hit a historic low of 35% in August 2021, prompting the Edward Hyatt Power Plant to go offline for the first time since 1967. So far this year, hydropower generation in California has been on the lower end of its 10-year range.
In the STEO, EIA forecast electricity generation for electricity market regions instead of state geographical boundaries. The latest STEO expects hydropower generation in the Northwest electricity region, which includes the Columbia River Basin and parts of other Rocky Mountain states, to total 120 billion kWh in 2021, a 12% decline from 2020. EIA expects hydropower generation in the California electricity region to be 49% lower in 2021 than in 2020, at 8.5 billion kWh.
By Kathiann M. Kowalski, Energy News Network
A bill for cutting carbon emissions calls for equity in job training and transition programs, an office of energy justice, increased oversight, and curbs on utility influence over regulators.
Ohio Democratic lawmakers plan to emphasize potential economic benefits as they try to persuade Republican colleagues to support an ambitious new bill aimed at pushing the state to 100% clean energy by 2050.
Reps. Stephanie Howse, D-Cleveland, and Casey Weinstein, D-Hudson, previewed the Energy Jobs and Justice Act (HB 429) at Cleveland’s Great Lakes Science Center on Tuesday. Ten other Democrats have signed on as co-sponsors.
“We’re at an inflection point — not just in Ohio but globally — as we seek to reduce greenhouse gas emissions that are wreaking havoc on our global environment and our Ohio environment,” Weinstein said.
Among other things, the 265-page bill calls for a 50% reduction in greenhouse gas emissions from electricity by 2030, compared to a 2005 baseline. That target would increase to 100% by 2050. The bill would also set an energy waste reduction goal of 22% by the end of 2030.
The bill aims to level the playing field for renewables to compete against fossil fuels. Among other things, it would fix the property line setbacks for wind farm turbines that were tripled in 2014. There would be more flexible options for community solar and virtual net metering. And steps for grid modernization would improve reliability and efficiency.Sponsors and supporters of House Bill 429 spoke at the Great Lakes Science Center in Cleveland on September 21. Left to right: Crystal Davis, Alliance for the Great Lakes; SeMia Bray, Black Environmental Leaders; Stephanie Howse, D-Cleveland; Casey Weinstein, D-Hudson; Ela Mody and Jenny Williams, constituents of House District 37; Kwame Botchway, Global Shapers; Miranda Leppla, Ohio Environmental Council Action Fund. Credit: Kathiann M. Kowalski
Equity concerns drive the need for clean energy and must play a key role in the transition, Howse and others stressed.
“We must focus our efforts on environmental justice,” Howse said. In particular, “poor air quality disproportionately impacts Black and Brown communities, as well as communities with low income.” Those groups also feel the most stress from high electricity prices, she added.
HB 429 calls for an Office of Energy Justice, whose director would report to the governor. Among other things, the office would make sure decisions by the Public Utilities Commission of Ohio are guided by energy justice when it sets rates and deals with other issues relating to existing, retiring or closed energy facilities. The Ohio Power Siting Board also would have to consider energy justice impacts in its rulings.
HB 429 calls for job training and economic development as well, with an emphasis on jobs in clean energy and grid modernization. “These are huge job creators,” Weinstein said. “We just need to create the underlying conditions that can allow those jobs to grow.”
Training programs would give priority to people who are Black, Indigenous or people of color, who have historically faced barriers to good jobs. Other groups with priority for job training under the bill include young people aging out of foster care and people reentering the workforce from incarceration. Additional provisions aim to help minority clean energy businesses get on their feet, with low-interest loans, coaching and some grants.
Similar to recent legislation passed in Illinois, the bill aims to help communities that have been dependent on fossil fuels as well. Areas where coal plants have shut down “have borne the brunt of both producing our electricity and suffering the impacts of pollution,” Howse said.
“The Energy Jobs and Justice Act may very well be one of the best expressions of energy justice in the region,” said SeMia Bray, a co-facilitator for Black Environmental Leaders in Cleveland. “This legislation serves as a logical step in making clean energy work for all Ohioans and creating systems that deliver support, call[ing] attention to areas where large gaps in access and equity persist, and creating new policies and practices that are needed to improve these outcomes.”Accountability and reform
HB 429 is especially timely in the wake of the ongoing scandal involving former House Speaker Larry Householder and others in an alleged $60 million corruption scheme, primarily funded by FirstEnergy and affiliates, to elect Householder-friendly legislators, pass House Bill 6 and block a voter referendum on it. The 2019 law provided subsidies for two nuclear plants and two old coal plants, propped up utility revenues, and gutted Ohio’s clean energy standards.
HB 6 was “the world’s worst policy, with ulterior motives,” Weinstein said, noting that Ohioans still pay about $10,000 per hour for the coal subsidies. “After an act of such unprecedented corruption, we need equally unprecedented legislation in Ohio to get us back on track and to meet our clean energy goals.”
Among other things, HB 429 would expand regulators’ authority to audit and investigate utilities that may have engaged in malfeasance. In theory, that authority could allow for more thorough investigations than the state’s public utilities commission has undertaken so far relating to FirstEnergy and HB 6. The commission has been criticized for taking a restrictive, piecemeal approach. And a recent corporate separation audit deemed multiple violations to be only “minor.” Yet those practices arguably made it easier for company personnel to funnel money to entities for the alleged corruption scheme.
Additional reforms would raise the bar before the utilities commission can bless settlements with only some parties to a proceeding. Critics such as Sen. Mark Romanchuk, R-Ontario, have said current practice allows settlements that favor utilities and sweetheart deals with certain industrial customers, at the expense of consumers and the public interest. In two 2016 rulings involving FirstEnergy and American Electric Power, the commission initially OKed partial settlements for coal and nuclear plant bailouts, which were then challenged by federal regulators.
HB 429 also calls for refunds if utility charges are later held unlawful. The reform would avoid situations such as those faced by customers of AEP and FirstEnergy, where the utilities collected millions in unlawful charges from consumers, but never had to pay the money back. Other bill provisions would tighten the standards for electric security plans and decoupling. And utilities wouldn’t be able to swap out rate plans if they don’t like regulators’ modifications.An uphill climb?
The bill will face an uphill battle in the Republican-controlled General Assembly, which has passed multiple laws making it harder to site renewable energy and gutting the state’s clean energy standards. Yet Weinstein and Howse are optimistic.
“We are in a relationship business,” Howse said, stressing the economic upsides of jobs in renewable energy and grid modernization. Indeed, most of the rhetoric around fossil fuels has focused on job protection, she noted.
“How are you going to protect a job that’s not there?” Howse asked. “That’s just reality. And it would be irresponsible for us as a government not to partner” to move ahead.
“I think there’s an opportunity in the wake of HB 6 to take a new fresh look at how to essentially do energy policy here,” Weinstein said. Bipartisan bills remain pending in the legislature to completely repeal that 2019 law, he noted. “I strongly believe there is bipartisan support to move forward and take that next step.”
“The probability that it won’t pass is just as possible as the probability that it can,” Bray said. “So let’s try and see where we end up.”
New York-based National Grid US envisions a “hydrogen hub” on Long Island that it says will help the state and city meet net-zero carbon goals in the coming decades.
The utility shared those goals and ideas as part of Climate Week NYC. National Grid US had developed a vision highlighting Long Island as an ideal location to cluster hydrogen production, storage, and demand.
Hydrogen has no carbon atom. It can be produced by electrolysis, separating the H2 from oxygen in water, and by the more carbon-intensive method of steam reforming of natural gas.
To be truly green or zero-carbon hydrogen, the electrolysis would need to be powered by carbon-free resources such as renewables or nuclear. The National Grid vision proposes that Long Island hydrogen production could be powered by nearby offshore wind electricity generation.
“When hydrogen is converted to usable energy in a fuel cell or burned to release its energy, the only byproduct is water vapor,” reads the National Grid web page on its H2 vision. “Hydrogen has the potential to help decarbonize multiple sectors, including power generation, transportation, and heating. Because hydrogen can be stored for long periods of time, it can play a critical role in help to balance renewable supply with demand while maintaining reliability and resiliency.”
New York has ambitious carbon reduction goals, but two-thirds of its energy currently comes from fuels like oil and natural gas, the utility noted. Renewables and energy storage can work with hydrogen capacity to reduce the percentage of fossil fuels in the electricity mix also.
National Grid has built 80 MWh of battery storage capacity on Long Island, helping to offset peak demand and emissions challenges while also balancing renewable intermittencies. The power generator also is considering transitioning conventional power plants to run on green hydrogen.
Numerous power equipment manufacturers, from Mitsubishi Power to MAN Energy Solutions and Cummins, are piloting projects to burn a mixture of hydrogen and methane gas in turbines and engines. Eventually, the goal of these projects to advance to a 100-percent hydrogen-fired power generation gen-set.
Some skeptics doubt that hydrogen production can be truly green. Those tackling a scale-up of hydrogen capacity in the future also are dealing with challenges around combustion in turbines as well as storage and transmission limitations.
Arizona-based municipal utility Salt River Project connected its largest battery storage facility into the grid this month.
SRP has placed the 25-MW energy storage facility into service at its Bolster Substation, which is adjacent to the gas-fired Agua Fria Generating Station. The fully charged battery site can power about 5,600 homes for close to four hours, according to reports.
The Bolster energy storage plant consists of Tesla Megapack large-scale batteries connected directly into SRP’s grid. SRP called it the largest stand-alone battery storage system in Arizona.
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“Battery storage is an extremely important and growing component of SRP’s 2035 sustainability goals to reduce our carbon footprint,” said Kelly Barr, SRP’s chief strategy, corporate services and sustainability executive, in a statement earlier this month. “The Bolster Substation Battery System adds to our already considerable investment in battery storage and further allows us to offset carbon-emitting resources by storing energy and providing it to our customers when they need it most.”
SRP plans to add 2,025 MW of utility-scale solar energy by 2025. Large batteries can take in excess solar-generated power when the sun is brightest and demand relatively low during the day.
In addition to the new Bolster Substation Battery System in Peoria, SRP receives power and collects data from two pilot battery storage projects. These include the Pinal Central Solar Energy Center, a 20-MW, integrated solar energy, and battery storage plant in Casa Grande and the Dorman battery storage system a 10-MW, 40-MWh stand-alone battery storage system in Chandler.
When California-based Jesse Morris saw a tweet from the California Independent System Operator (CalISO) asking Californians to conserve energy between 4 PM and 9 PM in order to help keep the grid stable on a hot summer day, he knew that CalISO could be tackling the problem in a much better way. That’s because Morris is the CEO of the Energy Web Foundation (Energy Web), a non-profit spun out of the Rocky Mountain Institute (RMI) that has created open-source (read, free) software that connects DERs to aggregators, utilities, and system operators so they can transact in the safest and most secure manner.
Fast forward to today and Energy Web has just completed a project with CalISO to help better manage its Flex Alerts. A Flex Alert is a call for consumers to voluntarily conserve electricity when there is a predicted shortage of energy supplies. When the ISO issues a Flex Alert, consumers are asked to cut back on electricity use, typically in the late afternoon and early evening hours (as energy produced by solar PV starts to drop off and people get off work and start to ramp up their electricity use).
As an educational and emergency alert program, Flex Alerts inform consumers when grid conditions are strained and conservation is needed to stretch supplies.
With the new system, California residents will be able to sign up to be notified when Flex Alerts take place and indicate if they plan to participate. Then, CalISO will be able to validate those responses by zip code, giving the grid operator better visibility into which areas of the grid might see some relief.
Plus, said Morris in an interview, if CalISO ever decided to award people for participating, “here we go. We’ve just set up a digital relationship between the Cal ISO and all these Californians and it would be very easy to then hook into the local utilities [like] PG&E, SCE the others.”
Morris estimates that California could have as much as 13 GW of flexible demand from distributed energy resources (DER) such as EVs, solar batteries and efficiency that it could be tapping if there was a market in place for DER services.Australia’s Project EDGE is ‘tip of the spear’ for global DER marketplace development
Creating a market for DER is exactly what is on trial in Australia. Earlier this month, the Australian Energy Market Operator (AEMO), Australia’s power system and market operator, announced the architecture and technology partners for Project EDGE, a new initiative that will enable DER to provide both wholesale and local network services at enterprise scale within an off-market trial environment.
The trial participants include local market players AusNet Services and Mondo, and technology providers Energy Web, PXiSE, and Microsoft.
According to Morris, Australia is a perfect place to set up a trial like this because the country has quite a high penetration of DER. “There’s just more solar. There are more batteries. There is soon to be more electric vehicles,” he said in an interview.
The biggest questions that project participants hope to answer are on the market design side, said Morris. “Australia is really cracking the regulatory questions.”How it works
Project participants break down this way: AEMO is the system operator, Mondo is the aggregator and AusNet is the distribution utility. Pixse, Microsoft and Energy Web are the technology providers.
Questions about how aggregated DER can provide services to the wholesale market are being tested around the world. Sunrun was the first in the US to announce that it would be bidding aggregated DER batteries into the wholesale market in New England. The project that Energy Web just implemented with CalISO makes use of DER in a similar way. Morris said they also have a project with PJM in the US.
“But then they [DER] are also going to be providing services to the distribution utilities, so that’s what’s being tested here in Australia,” said Morris.
Next-gen Utility Business Models and Grid Modernization are both educational tracks at DISTRIBUTECH International, set for Dallas, Texas, January 26-28, 2021. Registration is open now! Learn more and register to attend today.
On the distribution side, DER can provide services like voltage support from smart inverters, said Morris. But since utilities can’t profit from using DER this way – today utilities rely on building new infrastructure in order to get a guaranteed return on money they invest to build out the grid – that’s what will be examined in Australia.
“So part of EDGE is about experimenting with that so that they can go to the Australian energy regulator and say, ‘hey, we’re doing all this stuff we’d like to earn a transaction fee on the software. We’d like to rate base some of the expenses and digital technologies we are implementing,’” explained Morris, adding, “That’s the other part of the experiment with Edge that I think is pretty interesting…defining those business models for these utilities.”
POWERGRID International will continue to explore the evolution of the DER market. Subsequent articles will examine cybersecurity, technology players, costs and more.
The newly formed Green Hydrogen Organisation (GH2) and the International Hydropower Association (IHA) have set out a mutually strengthening vision of how their two sectors can collaborate and contribute to tackling climate change.
Green hydrogen is produced through electrolysis of water, using electricity generated by low-carbon power sources such as hydropower, wind, and solar.
The Green Hydrogen Organisation will promote the production and use of green hydrogen. It has begun work on establishing a GH2 Green Hydrogen Standard to ensure that green hydrogen is certified as coming only from low-carbon sources. In addition, the GH2 Green Hydrogen Standard will be developed to align with the hydropower sector’s Hydropower Sustainability Standard.
Former Australian Prime Minister Malcolm Turnbull will be the inaugural chair of the new organization, with Dr. Andrew Forrest, Chairman of Fortescue Metals Group, and Fortescue Future Industries, a founding board member.
“GH2 has been established to ensure green hydrogen is central to the energy systems of the future,” said Turnbull, who is also a board member of IHA. “Green hydrogen is a vastly superior technology to fossil fuels and will inevitably replace them – the only question is when. We are running out of time. Globally, almost 800 million people lack access to electricity. Addressing this should be a priority, using renewable energy and green hydrogen, not perpetuating dependence on fossil fuels.”
The collaboration commitment by the two organizations was made at a session on green hydrogen at the World Hydropower Congress on Sept. 17, 2021. The main message of the session was that energy should be sourced only from renewable sources like sustainable hydropower.
“We hope that our organization will harness entrepreneurship and sustainability in the renewables to enable a faster shift to producing and using green hydrogen,” said Jonas Moberg, chief executive officer of the Green Hydrogen Organisation.
Eddie Rich, CEO of IHA, said: “Sustainable hydropower and green hydrogen is a perfect marriage. I look forward to working arm in arm with the green hydrogen sector to help its exponential growth built on good sustainability principles. The green hydrogen revolution is dependent on renewable energy, including sustainable and responsibly developed hydropower. With the need for renewable energy and storage growing rapidly, it will be critically important for the green hydrogen industry to subscribe to high sustainability standards.”
The founders of the new organization strongly endorsed the forthcoming San José Declaration on Sustainable Hydropower and the recently launched Hydropower Sustainability Standard.
In May 2021, IHA published a paper, The green hydrogen revolution: hydropower’s transformative role, outlining how hydropower can be pivotal in supporting growth in green hydrogen.
During this Climate Week, and the upcoming COP26 climate summit of world leaders, corporations will make pledges to decarbonize and policymakers will up the ante on the urgency to transition away from fossil fuels to clean, renewable energy to address threats posed by climate change.
But the U.S. needs a grid of the future, now, to meet the goals of the Paris Climate Agreement and continue the rapid deployment of renewable energy assets, according to developers and industry experts.
The bipartisan infrastructure bill working its way through the U.S. Congress is a start but doesn't go far enough, according to the World Resources Institute. While the bill includes $27 billion in grid spending between 2022 and 2026, $360 billion in transmission investments are required to deploy 600 GW of new wind and solar by 2030. President Biden's goal of generating 45% of American electricity from solar by 2050 calls for 30 GW of new solar capacity to be added each year until 2025, increasing to 60 GW each year from 2025-2050.
According to Black and Veatch, 60% of U.S. distribution lines have surpassed their 50-year life expectancy. The Brattle Group, meanwhile, estimates $1.5-2 trillion will have to be spent by 2030 to maintain reliability.
"These more than $27 billion in investments are significant and would advance the grid and transmission improvements that a clean energy transition requires, but there is more needed to modernize this critical part of power infrastructure," WRI analysts wrote. "The Infrastructure Investment and Jobs Act falls tens of billions of dollars short of the scale of investment proposed in the American Jobs Plan, and the hundreds of billions of federal and private funds needed to prepare transmission systems to meet the nation’s low-carbon goals."
Transmission and distribution deficiencies are chief concerns for renewable energy developers, especially as recent studies indicate that they are unfairly burdened with upgrade costs.
Ryan Prescott, head of growth strategy and energy storage business development at Enel Green Power, an international renewable energy developer with a global portfolio of 49.9 GW, said the grid's limitations impact resiliency and complicate siting for new renewable projects, which can slow deployment.
"It's not a dearth of good sites; it's really a dearth of good sites that have the right supportive infrastructure that is built around them," Prescott said in an interview. "So, you're seeing this suboptimal siting effort from our industry, largely because we're sort of forced to based on the infrastructure that exists right now.
"We certainly haven't maxed out the ability of the grid, but we've really started to put some pressure on it."
Prescott said that federal investment must be coupled with a philosophical change of mindset in how the grid is designed. That means planning new transmission and distribution infrastructure around the best wind and solar resources, with the knowledge that there's going to be a larger share of distributed resources and flexible load.
"In many ways, the transmission planning and interconnection of utility-scale renewables is still stuck philosophically in the past," he said. "It's a large hub and spoke system that foresees a very small number of large generators connecting to the grid every single year; those large generators paying for a substantial amount of new transmission infrastructure. That's just not really how the grid is being built right now."3D rendering of Enel Green Power North America's Azure Sky wind + storage project in Texas (Courtesy: Enel Green Power North America)
The Federal Energy Regulatory Commission, in addition to Congress, could take sizeable steps to create the grid of the 21st century, experts say.
Joshua Rhodes, a research associate at the University of Texas Energy Institute, believes federal leaders could empower FERC to site interstate transmission lines, as they do with oil and gas pipelines, to streamline upgrades.
"The grid will need trillions of dollars of investment just to maintain the status quo, and even more to evolve to where we need it to go," Rhodes told Renewable Energy World. "Grid investment has always been a more local affair, but the federal government can help by providing seed funding and grants to nudge the development of the grid to a better place."
The world's largest floating wind farm is now operating offshore Scotland.
Statkraft, a renewable energy generator owned by the Norwegian state, will buy the entire electrical output of the 48 MW Kincardine Offshore Wind Farm through a power purchase agreement that extends until 2029.
The Kincardine Offshore Wind Farm is expected to generate up to 218 GWh of clean electricity each year, enough to power 55,000 households. The project is comprised of a 2MW Vestas turbine in addition to five 9.5 MW Vestas turbines.
"We are proud to be one of the partners that helped bring this highly innovative project to completion," said John Puddephatt, manager of long term PPA origination at Statkraft. "This is the first floating project that Statkraft has been involved in and we expect more to follow; a key technology that could help countries around the world achieve their renewable energy targets."
The project was developed by Kincardine Offshore Wind, a wholly-owned subsidiary of Pilot Offshore Renewables (POR). Cobra Wind, a subsidiary of ACS Group, is responsible for the engineering, design, supply, construction, and commissioning of the Kincardine floating wind farm.
With next week’s FERC meeting on SEEM proposal, the question is back on the table: will FERC approve a group of southeast utilities’ proposal for organizing a market? This fall is the first legislative session across the US and other states where the discussion is around clean energy and what incentives are needed for utilities to deploy more renewables. With the Biden administration’s “Build Back Better” model around infrastructure, will US Congress see a need to mandate organized markets, since we know corporate renewable energy buyers need regulatory stability in the marketplace?
A US senator’s proposal incentivizes utilities to shift to renewables using union workers counter a competitive energy market construct. Competitive energy markets have proven their worth even with voluntary utility participation. It is time to make energy markets mandatory.
Will FERC Approve SEEM?
The story on what southeast utilities would do if FERC does not approve their proposal is unwritten. FERC could ask SEEM proponents to go back to the drawing board and include governance, stakeholder participation, market monitor, and price transparency, to name a few organized market principles. Or FERC could approve SEEM since the utilities say their purpose is to interconnect more renewables.
How can FERC say no to utilities who want to organize themselves in a market construct? Midwest ISO became the first Regional Transmission Organization (RTO) in December 2001 when MISO Transmission Owners formed an agreement to organize similar to southeast utilities. But the key difference with Midwest ISO, which is Midcontinent ISO now, is, right from the start, the ISO had stakeholder committee structure and Board governance, including independent market monitoring. That structure takes a lot of scope, schedule, and budget.
How about we Build Back Better markets?
While President Biden and the energy secretary visit the national labs and showcase their “build back better” agenda, it is time to consider whether we need to give our market operators more teeth in regions that already have organized markets.
What is true for corporate buyers is true for consumers in general, which is a stable set of rules that identifies transmission studies that enable faster renewable integrations. Corporate buyers of renewable energy bring economies of scale that are a healthy compromise between utility-scale and residential-scale renewable projects.
Utility-scale renewable projects need high voltage transmission capacity to interconnect, which takes, on average, 10 years to build, if approved today. Residential-scale distributed renewable projects need distribution feeder upgrades to accommodate bidirectional energy flows.
FERC has opened doors on both fronts with an Advanced Notice of Proposed Rulemaking on transmission planning and generator interconnection and an Order 2222 on distributed energy resources aggregation. But FERC needs the backing of US Congress to mandate RTOs to execute on this administration’s vision to integrate more renewables.
Will US Congress mandate organized markets?
It remains to be seen whether the US congress would tackle the hard issue of mandating organized markets across the country because renewables are not scalable if developers face multiple regulatory approvals. It might be time to bring back former FERC Commissioner Pat Wood’s Standard Market Design, which was ahead of its time in the early 2000s.
The US Congress can achieve multiple energy policy goals with a standard market design, leveraging the experience gained by current market operators. If the entire continental US is under organized markets, renewable developers and corporate buyers pay more attention to their core business of putting together renewable deals instead of following RTO committees.
Record-breaking solar interconnection requests at RTOs are quickly becoming yesterday’s news in the energy world. The energy storage requests are today’s news, as the figure below indicates. PJM has more than 40,000 MW of energy storage requests waiting to be studied. The expertise to study these storage resources, which inject energy when they discharge and draw energy when they charge on the transmission grid, resides at RTOs. Hence by mandating RTO participation, the US Congress will be doing renewable project developers a favor because RTOs can churn out studies faster in study cycles like MISO.
What about Clean Electricity Payment Program?
Senator Tina Smith’s proposal on clean electricity standards, specifically the clean electricity payment program, is catching much press because it incentivizes utilities to use organized labor to integrate more renewables. If utilities don’t integrate more renewables, then they get penalized.
This proposal puts more pressure on utilities to organize themselves in market constructs such as SEEM because what will the utilities do with excess renewable energy? Those utilities cannot simply dump the excess energy on their neighbor’s transmission system without reserving transmission capacity.
This transmission reservation is not an issue in an energy market because all parties share the transmission system and depend on the independent grid manager to schedule network service. If an interconnection customer has a non-firm service, they get curtailed. The point is, the rules are transparent in the marketplace. Hence focusing on mandating organized markets enables renewables integration.
FERC is willing to work towards reforming interconnection rules and transmission planning protocols. But FERC needs help from US Congress. Unless utilities are mandated to participate in organized markets, there will be proposals such as SEEM, which may not go the whole nine yards in a market structure. With more renewables on the grid at both utility-scale and distributed-scale, it is time to make market participation mandatory.
By Elizabeth Ouzts, Energy News Network
Manufacturers, mills, and environmental interests oppose Duke-backed legislation because it hampers the role of regulators and costs ratepayers.
It’s not often that paper mills and chemical manufacturers agree with the likes of the Sierra Club.
But the debate over controversial energy legislation in North Carolina shows how companies like DuPont, Chemours, and Georgia Pacific are increasingly aligned with environmental groups on utility policy.
The strange bedfellow scenario stems in part from economics. The rapidly declining costs of clean energy mean the gas plants mandated in the bill will almost certainly cost large ratepayers more than would cleaner alternatives, a reversal from a decade ago.
“Couple that with the volatility of fossil fuel prices,” said Peter Ledford, general counsel for the North Carolina Sustainable Energy Association, “it creates risks for ratepayers whose bills are in the millions of dollars a month instead of hundreds of dollars a month.”
And though clean energy nonprofits welcome the new solar farms and early retirement of coal plants required in the bill, they, like the manufacturers and mills, think utility regulators should keep their authority to authorize any replacements — not have it usurped by legislative mandates.
The two camps are lobbying and testifying against the current draft of the Duke Energy-backed bill and even partnered on a news conference. “It’s nice to be standing together,” said Kevin Martin, director of the Carolina Utility Customers Association, a trade group that originated with textile mills. “People don’t normally see us standing together.”A decade of tumbling prices
North Carolina utility law requires energy planning and ratemaking that results in the “least-cost mix of generation and demand-reduction measures” achievable. For decades, the provision favored fossil fuel plants over more expensive wind and solar farms.
To help counteract that reality, the state adopted a mandate for both renewable energy and energy efficiency in 2007. Though a study commissioned by regulators showed the combination would save ratepayers over time, the law included tax breaks and cost caps to help win the support of large customer groups worried about rising utility bills.
In practice, the caps proved unnecessary. According to data from the North Carolina Sustainable Energy Association, utilities have spent well under them — with an outlay of $860 million to date compared to a cap of $2.4 billion. An analysis by Research Triangle Park-based think tank RTI shows the expenditures helped avoid over $4 billion in natural gas-fired electricity.
The reason, of course, is that renewable energy prices have plummeted. Over the last decade and a half, state renewable energy mandates and other incentives helped to jumpstart markets — increasing supply, spurring innovation and efficiency, and decreasing costs.
According to asset management firm Lazard, the levelized cost of energy — the price per megawatt-hour over a project’s lifetime — has fallen 71% for land-based wind power since 2009. Large solar fields have plunged 90%.
That means developing a new, large-scale solar farm isn’t just cheaper than building a new coal plant; it’s cheaper than using one that already exists. It’s cheaper than a new, single-cycle gas plant. Increasingly, it’s even cost-competitive with a more efficient combined-cycle gas plant.
And while renewable costs are still decreasing, albeit, at a slower rate than in the last decade, those for gas are unpredictable at best because of the cost of fuel.
“If you have a fuel-free resource,” said Gudrun Thompson, senior attorney at the Southern Environmental Law Center, “you’re doing away with the fuel cost and you’re also doing away with some risk — because nobody really knows what prices are going to do in the future.”New competition for natural gas
Passing the Republican-controlled House of Representatives narrowly in July, H951 includes 4.6 gigawatts of solar power developed through a competitive bidding program. The provision has the backing of solar companies, who’ve carefully avoided commentary on the rest of the bill.
But that injection of solar power — about a 70% increase by 2030 — isn’t raising the hackles of large industrial users of electricity, or the reason the bill could be so costly in the future.
A multi-year ratemaking scheme in the bill includes several features that favor Duke over its customers, experts say, including a provision allowing Duke to over-earn by half a percentage point but not under-earn at all.
“We’re not opposed to earnings,” said Martin of the Carolina Utility Customers Association. “But we are opposed to exorbitant earnings.”
Another provision requires Duke to retire five of its coal plants, assets worth over $1 billion but limits the company to recover less than half of that amount through low-interest securitization bonds. The rest would be charged to ratepayers on an accelerated schedule, benefiting shareholders.
“Approximately $20 million in ratepayer savings is achieved for every $100 million of the book value that is securitized,” wrote Weyerhauser, Dupont, Ashley Furniture and more than 50 other companies in an August letter to state senators, urging the $500 million cap to be lifted.
At a Senate committee hearing on H951, the North Carolina Sierra Club echoed that request. “I think we can all agree we need to move beyond coal, but we need to do it in the right way,” said Cassie Gavin, the group’s head lobbyist. “The cap should be scrapped or raised to at least $1 billion.”
The measure also allows the company to charge ratepayers $50 million in research costs for small modular nuclear reactors — experimental technology that may prove vital in curbing emissions, but which critics worry is much less safe and more expensive than today’s large, baseload nuclear plants and may not ever come to fruition.
“Most of my companies are fans of nuclear energy,” Preston Howard, head of the North Carolina Manufacturers Association, told the Senate panel. “What we’re not fans of is paying for new nuclear facilities that never generate a kilowatt of power,” he said. “It’s time for the utility to share some of the risk of nuclear investments.”
The bill also puts the thumb on the scale for natural gas — once the paragon of least cost — mandating the resource rather than leaving it up to the seven-member utilities commission to determine whether it is a necessary, prudent, and reasonable addition to Duke’s generation mix.
At the company’s Marshall plant, some 30 miles north of Charlotte, the bill gives Duke five years to swap out two coal units for a new, single-cycle gas unit of up to 900 megawatts. Such gas plants are the second priciest form of dispatchable power available today, according to the U.S. Energy Information Administration, a close second behind battery storage, whose costs are falling.
At present, the two coal units totaling 740 megawatts run up to a third of the year, per Public Staff, the state-sanctioned ratepayer advocate. Situated in the heart of Duke Energy Carolinas territory, such plants can be used for voltage support and frequency regulation as well as electricity generation, said James McLawhorn, the agency’s energy division director.
Still, battery storage can also provide those functions. To replace the coal units, Thompson asked, “Do you really need gas at all? And if so, do you need that much?”
H951 also requires Duke to submit a “retirement and replacement plan” for its Roxboro plant, north of Durham near the Virginia border, three years from now. While the replacement isn’t specified, it must meet criteria that only gas can satisfy.
Yet a study by the Brattle Group shows gas wouldn’t be the most cost-effective substitute.
Commissioned by solar developer Cypress Creek Renewables, the analysis models two scenarios under H951. Both meet the bill’s requirements for new solar and storage capacity. One limits new gas to just the 900-megawatt unit at Marshall, with none at Roxboro. The other assumes Duke will build 4.7 gigawatts of single and combined-cycle gas plants by 2030.
The limited gas scenario isn’t just cleaner, cutting 2005 carbon emissions by 74% in the next decade rather than about 60%. It’s also cheaper, saving ratepayers $530 million in 2030 and $1.2 billion five years later.
The Brattle study is the latest to show that Duke can retire coal plants earlier than now planned, ramp up renewables and storage instead of natural gas, and cost ratepayers less than the company’s favored long-range plan. An analysis by Synapse Energy Economics found the savings over 15 years could top $7.4 billion.
“The Synapse report shows that renewables, storage and efficiency — as a portfolio — are already cost-competitive with new gas,” Thompson said.‘Numbers like that close plants’
The question of cost is tantamount for industries like textiles because electricity is a large and growing portion of their operating expenses. That’s in part because the global trend toward automation has increased kilowatt-hour needs. It’s also because electricity is the one expense manufacturers can’t control by seeking a better deal in a competitive marketplace.
Then there’s the sheer scale, Martin said. “Something that might cost an annual residential bill to go up $200 might cost an industrial bill, on an annual basis, to go up $5 million or more,” he said. “Numbers like that close plants.”
The numbers are also crucial factors as industries weigh moving operations overseas — or coming back to the country. “We believe in manufacturing in the U.S. and we’ve grown in the U.S.,” Dan Nation, government affairs director of Gastonia-based Parkdale Mills, a textile company, told Senate lawmakers. “This bill puts that in danger.”
To be sure, industrial users don’t want any resource — including solar and battery storage — to bypass the existing process by which regulators permit power plants. “It’s not necessarily that we’re opposed to or supportive of one particular technology or another,” said Christina Cress, whose law firm is counsel to Carolina Industrial Group for Fair Utility Rates, a business association that began with the pulp and paper mills.
“What the replacement generation resources are going to be, how it gets paid for — all of that is currently in the commission’s purview,” said Cress, and it should stay that way. “We think the commission does a really good job at being a regulator.”
The motivations of many large electricity users who oppose H951 aren’t purely economic. In the absence of enforceable carbon reduction targets in either North Carolina or the country, 66 companies with a presence in the state— from engine manufacturer Cummins to soap producer Unilever — have adopted their own ambitions for 100% renewable energy. Many want H951 to do more to expand Duke’s green tariff program and revitalize its failed community solar program.
“We support the need to transition to clean energy,” said Cress, who helped draft the August letter on H951. “We have several member companies who have very ambitious carbon reduction goals.”A market left?
Furniture, textiles, and logging and milling have a long legacy in the state, and their opposition has helped stall the legislation in the Republican-controlled state Senate for now.
But Duke Energy also holds tremendous sway, having handsomely rewarded its legislative allies with campaign donations and a web of dark money assistance. The company has repeatedly promised stockholders that it can and will pass some version of H951 and continue to build its asset base.
“That’s just the way their business model works,” Thompson said. “They’re pretty candid with Wall Street that their value proposition to shareholders is that they’re planning to build a lot of new big capital projects.”
Solar companies, meanwhile, caution that the status quo is bad for their industry. Economics aren’t the only factor when it comes to plant approval, they say, and that without some change in policy at the state or federal level, natural gas could continue to win the day with regulators.
A competitive procurement program for solar energy that began with a 2017 law has almost come to close, and “there is no mechanism by which this market is guaranteed to be extended,” said Tyler Norris, a senior director with Cypress Creek and the vice chair of the Carolinas Clean Energy Business Association, a trade group. In North Carolina, he said, “there is no market left for large-scale renewables.”
Like Norris’s group and other stakeholders, the Carolina Industrial Group for Fair Utility Rates continues to meet with lawmakers and other interests to try to reach an agreement.
“But without seeing some significant changes,” Cress said, “I don’t see us getting to a point where we can do anything but oppose the bill.”
Duke Energy’s newly formed Sustainable Solutions unit, merged from several entities only months ago, is building a 207-MW wind power project in Iowa.
Construction on the Ledyard Windpower site in Kossuth County will be Duke Energy Sustainable Solutions’ first renewable energy project in Iowa. The non-regulated commercial brand of Duke was formed with the combination of several previous units, including REC Solar, Duke Energy Renewables Wind, and other subsidiaries.
Verizon Communications has contracted for 180 MW of the Ledyard wind power generation on a 15-year virtual power purchase agreement (VPPA). A virtual PPA means that the electricity generated will not go directly toward the customer company’s power use, but help fund investment in the renewable energy capacity.
“We’re excited to enter into the Iowa market, a state that has valuable wind resources and is ranked second in wind energy generation,” Chris Fallon, president of Duke Energy Sustainable Solutions, said in a statement. “Ledyard Windpower will not only add cleaner energy and economic value to Kossuth County, but it will also contribute to Duke Energy’s goal of reaching 47,000 MW of renewable energy by 2050.”
Work on Ledyard is scheduled to be completed by the end of 2022. Once operational, it will increase Duke Energy Sustainable Solutions’ U.S. wind capacity to more than 3,100 MW.
The 12,000-acre site could provide enough power for the equivalent of 72,450 homes, according to Duke. The construction phase will create approximately 200 jobs during the peak of work, the release says.
Iowa is host to about 11,000 MW of installed wind energy capacity, according to reports. It ranks a distant second to Texas, but ahead of Oklahoma and Kansas.
North Carolina-based utility giant Duke Energy launched the Sustainable Solutions spinoff in April. The move unified many of the company’s renewable energy efforts and offered services from financing to planning, construction and management of projects.
India's rooftop solar market is booming.
India added 521 MW of rooftop solar capacity in the second quarter of 2021, representing an increase of 53% from the previous quarter and 517% year-over-year growth.
That's the latest from Mercom's India Rooftop Solar Market Report Q2 2021-- India's best quarter for rooftop solar ever.
“The rooftop solar segment had a strong quarter, and demand is up," Mercom CEO Raj Prabhu said in a statement. "Finalizing the net metering cap at 500 kW has removed uncertainty for installers and paved the way for future growth."
In the first half of 2021, 862 MW of rooftop solar capacity was added in India-- more than the total installed capacity in all of 2020. Much of the demand came from corporate and industrial customers. Cumulative rooftop solar capacity reached 6.1 GW by the end of Q2 2021, according to the report.
The Mercom report warns that "haphazard" rooftop solar policies across states are holding the sector back. Increasing system costs also threaten the industry's growth.
While PPA prices are trending upward, LevelTen doesn't expect demand to soften. According to a survey by the firm, only 12% of solar developers are responding to supply chain pressures by delaying projects.
The price of solar and wind power purchase agreements in North America increased 4.3% in the second quarter of 2021, and is up 14.4% year-over-year, according to an analysis by LevelTen Energy.
Demand for renewable energy by public and corporate groups, coupled with global supply chain constraints, are likely causing the pricing pressure, analysts wrote.
“Much like we’re seeing supply constraints in other areas of the economy, the most desirable wind and solar projects are going fast," said Rob Collier, vice president of developer services at LevelTen Energy. "The key takeaway for organizations with fast-approaching emissions reductions targets is to act now to capture high-value PPAs."
Solar prices increased quarter-over-quarter and year-over-year in Q2 2021 for the first time since Wood Mackenzie began modeling solar market prices in 2014.
Important trend to watch. My explanation:
1) wind/solar PPAs are growing in popularity
2) global supply chains are still messed up
3) might be that some of the easiest places to build have already been snagged, so less desirable locations/resource are now being exploited https://t.co/c1prKUnGXQ
Trade issues, meanwhile, threaten President Biden's goal of generating 45% of electricity from solar energy by 2050. The U.S. government's enforcement of the Withhold Release Order (WRO) on metallurgical-grade silicon (MGS) from companies with facilities in China's Xinjiang region, as well as the possible extension of the Section 201 tariffs on imported solar modules, have added to the uncertainty. Additional tariffs could come, too, from the Antidumping and Countervailing Duties (AD/CVD) case involving companies from Malaysia, Thailand, and Vietnam.
While PPA prices are trending upward, LevelTen doesn't expect demand to soften. According to a survey by the firm, only 12% of solar developers are responding to supply chain pressures by delaying projects.
“ERCOT solar prices have increased by nearly 10% since Q2 2020, driven by steady quarterly increases in pricing at ERCOT’s North, South, and Houston settlement hubs,” Collier said. “Still, ERCOT continues to be the most competitive solar market in the U.S., as abundant land, a unique market structure, and high insolation provide a favorable environment for solar development."