By Jonathan Spencer Jones, Smart Energy International
Toyota is expecting to invest up to $13.6 billion in battery development and production by 2030.
In a briefing on batteries, the company announced that it is aiming for a 50% reduction in battery costs through 30% improvements in both cell efficiency and manufacturing costs in the late-2020s.
At the same time, there are plans to increase the supply of batteries up to 200GWh from the currently planned 180GWh.
In the briefing, Masahiko Maeda, Toyota’s chief technology officer, revealed the company’s integrated vehicle battery development approach, which it has been pursuing and will concentrate on further as the demand for EVs increases.
Simply put, this involves selecting the appropriate battery type for the application. For example, for hybrid EVs, the focus has been on the instantaneous power output, while for plug-in hybrids and battery EVs the focus has been on capacity or ‘endurance,’ as Toyota puts it.
These have involved evolutions of nickel-metal hydride batteries and latterly also lithium-ion batteries. The latest form, a bipolar Ni-metal hydride battery offering a claimed doubled power density over the conventional structure, features in the recently launched new Aqua and is planned to appear in an expanding range of EVs ahead.
“What Toyota values the most is to develop batteries that its customers can use with peace of mind,” said Maeda in the briefing.
“Especially, we are focusing on safety, long service life, and high-level quality to produce good, low cost, and high-performance batteries. We think it is important to strike a balance between each of these factors to ensure safe use.”
Maeda described that in pursuit of these objectives, the company was expending effort on understanding issues such as localized heat generation when under large load and material degradation within the batteries and the prevention of the entry of foreign matter during the manufacturing process.Future batteries
Looking ahead, Toyota’s battery program envisages the development of new electrode materials, new manufacturing processes, and new cell structures with packs to match the vehicles.
The company also intends to advance both liquid batteries and all-solid-state batteries. The latter, which are at a prototype stage, offer the prospect of high output, long cruising range, and shorter charging times. The main challenge stated at this stage is the short service life.
“When it comes to electrified vehicles, cars and batteries cannot be separated,” Maeda concluded.
“Toyota is an automaker that has been working on battery development as a corporate group, and, into the uncertain future of electrified vehicles as well, it intends to move forward in sure-footed steps.”
Toyota is forecasting sales of 8 million electrified vehicles by 2030, comprised of approximately 6 million hybrid and plug-in hybrid vehicles and 2 million battery EVs and fuel cell EVs.
Over the weekend, Democrats in the U.S. House released the first specifics of the Build Back Better plan within the $3.5 trillion budget reconciliation bill. The overall package is seen as the most significant legislative effort ever proposed to address climate change. Reconciliation requires only a simple majority of the House and Senate to pass.
So, what's in the Build Back Better bill for renewable energy? Here's a breakdown of the highlights.Clean Electricity Performance Program The Midcontinent Independent System Operator is making it easier to connect renewable energy resources to the grid.
The Build Back Better bill includes the Clean Electricity Performance Program (sometimes identified as the Clean Electricity Payment Program), which stands to make the biggest dent in U.S. greenhouse gas emissions by cleaning up the grid. Beginning in 2023, the program would reward utilities that increase their share of clean energy by 4% per year with grants and punish utilities that fall short by imposing fees.
In the program's first year, utilities would be scored against their average clean electricity share in 2019 and 2020. The program would run through 2030.
In August, Senate Majority Leader Chuck Schumer told colleagues in a letter that President Biden's goal of cutting greenhouse gas emissions by 50% compared to 2005 levels is within reach, in large part due to the proposed CEEP. Analysis of the program found that it would create nearly 8 million jobs by 2031.Direct pay tax credits for renewable energy Germany can, and must, meet the targets of the Paris Climate Agreement by achieving 100% renewable energy by 2030, a new study claims. (Courtesy: Andreas Gücklhorn/Unsplash)
The Build Back Better bill restores the production tax credit (PTC) and investment tax credit (ITC) to their full values, and taxpayers are eligible for direct pay instead tax equity offsets.
"This allows entities with little or no tax liability to accelerate utilization of these credits, including tax-exempt and tribal entities," the bill summary reads.
For wind, solar, geothermal, landfill gas, and qualified hydropower projects commencing before 2032, the production tax credit provides a base credit rate of .5 cents/kWh and a bonus credit rate of 2.5 cents/kWh. The base and bonus credit rates phases down to 80% in 2032 and 60% in 2033.
The bill extends the ITC to 30% of full value with a base rate of 6% for property constructed by the end of 2031, then phasing down over two years. There are additional incentives for projects that utilize domestically-produced equipment and for those deployed in low-income communities. A recent study found that clean energy developers are unfairly burdened with transmission upgrade costs.
The ITC is expanded to include energy storage technology and linear generators, each eligible for a 6% base-credit rate or a 30% bonus credit rate through the end of 2031, before phasing down in 2032 and 2033.
Qualifying electric transmission projects and upgrades are eligible for an ITC with a base credit rate of 6% or a bonus credit rate of 30%. These projects are defined as being capable of transmitting electricity at a voltage greater than or equal to 275 kilowatts and having transmission capacity greater than or equal to 500 megawatats.
A new tax credit is created by the Build Back Better bill for clean hydrogen production beginning in 2022. The base rate of $0.60 or bonus rate of $3.00 is multiplied by the volume in kilograms of clean hydrogen produced during a taxable year.Electric vehicles An electric vehicle charging station (Flickr/Pat Gerber)
The Build Back Better bill provides a refundable income tax credit for new qualified plug-in electric vehicles with a base amount of $4,000, plus an additional $3,500 for vehicles placed into service before Jan. 1, 2027, with battery capacity greater than or equal to 40 kWh, and for vehicles with a battery capacity of no less than 50-kilowatt hours thereafter.
The base amount increases to $4,500 for vehicles produced in the U.S. under a union-negotiated collective bargaining agreement. The base amount increases another $500 for vehicles with 50% or more domestically-produced content. Beginning in 2027, the credit will only apply to vehicles with final assembly in the U.S.
Purchasers of pre-owned, plug-in electric vehicles would be eligible for a new refundable credit through 2031. Buyers can claim a base credit of $1,250 for qualified electric vehicles.Sustainable fuels
The Build Back Better bill extends income and excise tax credits for biodiesel and biodiesel mixtures at $1 per gallon through 2031. The $0.10-per gallon small agri-biodiesel producer credit and $0.50-per-gallon excise tax credits for alternative fuels and alternative fuel mixtures are extended through 2031.
There's also a refundable blenders tax credit for each gallon of sustainable aviation fuel sold as part of a qualified fuel mixture.
"The value of the credit is determined on a sliding scale, equal to $1.25 plus an additional $.01 for each percentage point by which the lifecycle emissions reduction of such fuel exceeds 50%. Taxpayers may elect to claim this credit as an excise tax credit against section 4041 excise tax liability," the bill summary says.
New Jersey officials broke ground last week on the nation's first purpose-built port for the offshore wind industry.
The New Jersey Wind Port is designed to serve as a hub for the offshore wind industry along the East Coast, with access to more than 50% of available U.S. offshore wind lease areas. The project is expected to be completed by the end of 2023.
“Investing in offshore wind is vital to building a stronger, greener economy that creates high-paying jobs to support a robust recovery from the economic impacts of the COVID-19 pandemic and paves the way for long-term, equitable growth,” said New Jersey Gov. Phil Murphy. “The New Jersey Wind Port will create thousands of high-quality jobs, bring millions of investment dollars to our state, and establish New Jersey as the national capital of offshore wind.”In addition to the groundbreaking ceremony, the event also included the signing of a project labor agreement (PLA) for the project between AECOM-Tishman and the United Building Trades Council of Southern New Jersey AFL-CIO. (Courtesy: New Jersey Governor's Office)
The initial development plan includes a 30-acre marshalling area for component assembly and staging, dredging of the Delaware River Channel, heavy-lift wharf with a dedicated delivery berth and an installation berth, dedicated overland heavy-haul transportation corridor, and potential for additional laydown areas.
Long term, the site can support a development footprint of over 200 acres. Ørsted and Atlantic Shores have already expressed interest in using space at the New Jersey Wind Port, officials said.
“The New Jersey Wind Port represents the kind of technological innovation, broad-based partnership, and bold investment that we need to meet the climate challenge and create good jobs and an inclusive workforce in our country,” said U.S. Secretary of Labor Marty Walsh. “This project and the good jobs that come with it serves as an important model for future infrastructure investments in this country.”
Major construction on the New Jersey Wind Port site is expected to begin in December.
As part of New Jersey's goal of reaching 100% clean energy by 2050, Murphy has committed to producing 7.5 gigawatts of offshore wind energy by 2035.
Great River Energy, a distribution and transmission cooperative, has partnered with a Massachusetts startup on a long-duration energy storage pilot project that it hopes will help buffer its grid from extreme cold and heat impacts.
By Frank Jossi, Energy News Network
The utility cooperative partnering with Form Energy on its first “iron air” battery project sees the long-duration energy storage technology as a potential buffer for its grid during extreme cold snaps like 2019’s polar vortex.
Great River Energy, a Minnesota generation and transmission cooperative that serves 28 member utilities, had been in discussions with the Massachusetts startup company for several years before committing to the pilot project, according to Jon Brekke, its vice president and chief power supply officer.
“We’re interested in pursuing long-duration storage because it gives us reliability advantages over traditional lithium-ion batteries,” Brekke said. “We can look at a 10-day weather forecast, and if we see that the weather is going to get very cold seven or eight days out, we can make sure that the battery is charged up.”
Wind speeds tend to decrease during extremely cold temperatures. Meanwhile, turbine components can become brittle or stop working as temperatures plunge into the double-digits below zero. Those factors caused Upper Midwest wind generation to drop off two winters ago during a prolonged polar vortex. (Coal and gas plants also experienced outages.)
The stakes for wintertime grid reliability will increase as more homes and buildings transition to electric heat, but long-duration energy storage could also help utilities manage the grid during scorching hot weather that is also becoming more common in Minnesota due to climate change.Form Energy’s “iron air” battery. Credit: Form Energy / Courtesy
Form Energy’s “iron air” batteries store energy for as long as 100 hours or more, offering Great River Energy another tool to deliver electricity during challenging weather events.
Members approved the pilot as a power supply resource that will be owned and operated by the generation and transmission utility. Brekke did not reveal the cost of the project but characterized it as “small” and not involving a significant investment risk. If the pilot meets expectations, Great River Energy may make the battery a significant part of its power resources.
Form Energy has raised $367 million so far from investors. It’s among a handful of new long-duration battery companies in a field that could experience explosive growth as more utilities work toward higher clean energy goals. Great River Energy plans to generate 50% from renewable energy by 2030 and saw Form Energy as having a solution that may fit its needs.
Nearly all utilities today use lithium-ion energy storage solutions that discharge backup electricity over four hours. Form Energy’s technology is based on iron and uses electrochemistry to make reversible rust iron. The battery discharges energy while breathing in oxygen and creating rust. During charging, the electric current converts rust back to iron and breathes out oxygen.
Ted Wiley, Form Energy’s co-founder, explained that hundreds of washing machine-sized batteries are chained together to form a 1-megawatt power block. The technology uses relatively cheap and plentiful iron instead to store electricity at a tenth the price of lithium-ion batteries — a key to Great River Energy’s interest in the project.
“We saw the vision here of having ultra-cheap, long-duration storage, and we found a fit with Form Energy,” Brekke said.
Great River Energy’s deal with Form Energy could grow to as many as 300 megawatts in the future if the technology works, Brekke said. Beyond serving the utility during cold weather spells, Great River Energy sees the Form Energy batteries as a market hedge and potential economic development engine for Minnesota’s iron ore industry.
Battery storage represents 12% of projects in the queue of the MidContinent Independent System Operator (MISO). In Minnesota, three small community battery storage projects funded by a state program are being installed now, joining several other small pilots built in the last five years.
Connexus Energy, a cooperative serving several Twin Cities suburbs, began running a 30-megawatt solar-storage project in 2019 that was, at the time, one of the largest in the region. Clean Grid Alliance Executive Director Beth Soholt said that as power companies transition to more weather-dependent generation sources such as wind and solar, the need for storage grows.
Long-duration storage will help utilities deal with “extreme heatwaves or cold snaps and the crazy weather patterns we’re seeing” due to global warming, she said. However, most storage applications cannot mimic the power output of natural gas or coal plants during a weather crisis, Soholt said.
Long-duration batteries also allow utilities the flexibility to buy energy at low-cost times. Great River Energy will be able to buy energy overnight, when wind power is plentiful but demand is low, and deploy it “when the grid is stressed or in need of power supply,” Brekke said.
As Form Energy works to bring the battery technology to the market, the goal is to reach cost parity with thermal generation such as natural gas.
The battery storage pilot project is expected to begin operation in 2023 next to two natural gas plants in Cambridge owned by Great River Energy. A future installation could happen in the state’s Iron Range.
“The other thing we like about Form is the connection to Minnesota with the iron air technology,” he said. “We’re just thrilled that this is using a product that is so important to Minnesota’s economy. And Minnesota can become a significant energy player should this technology prove to be successful.”
President Joe Biden has called for major clean energy investments as a way to curb climate change and generate jobs. On Sept. 8, 2021, the White House released a report produced by the U.S. Department of Energy that found that solar power could generate up to 45% of the U.S. electricity supply by 2050, compared to less than 4% today. We asked Joshua D. Rhodes, an energy technology and policy researcher at the University of Texas at Austin, what it would take to meet this target.Why such a heavy focus on solar power? Doesn’t a low-carbon future require many types of clean energy?
The Energy Department’s Solar Futures Study lays out three future pathways for the U.S. grid: business as usual; decarbonization, meaning a massive shift to low-carbon and carbon-free energy sources; and decarbonization with economy-wide electrification of activities that are powered now by fossil fuels.
It concludes that the latter two scenarios would require approximately 1,050-1,570 gigawatts of solar power, which would meet about 44%-45% of expected electricity demand in 2050. For perspective, one gigawatt of generating capacity is equivalent to about 3.1 million solar panels or 364 large-scale wind turbines.
The rest would come mostly from a mix of other low- or zero-carbon sources, including wind, nuclear, hydropower, biopower, geothermal and combustion turbines run on zero-carbon synthetic fuels such as hydrogen. Energy storage capacity – systems such as large installations of high-capacity batteries – would also expand at roughly the same rate as solar.
One advantage solar power has over many other low-carbon technologies is that most of the U.S. has lots of sunshine. Wind, hydropower and geothermal resources aren’t so evenly distributed: There are large zones where these resources are poor or nonexistent.Most areas of the U.S. can generate at least some solar power year-round. This map shows annual global horizontal irradiance – the amount of sunlight that strikes a horizontal surface on the ground. NREL
Relying more heavily on region-specific technologies would mean developing them extremely densely where they are most abundant. It also would require building more high-voltage transmission lines to move that energy over long distances, which could increase costs and draw opposition from landowners.Is generating 45% of U.S. electricity from solar power by 2050 feasible?
I think it would be technically possible but not easy. It would require an accelerated and sustained deployment far larger than what the U.S. has achieved so far, even as the cost of solar panels has fallen dramatically. Some regions have attained this rate of growth, albeit from low starting points and usually not for long periods.
The Solar Futures Study estimates that producing 45% of the nation’s electricity from solar power by 2050 would require deploying about 1,600 gigawatts of solar generation. That’s a 1,450% increase from the 103 gigawatts that are installed in the U.S. today. For perspective, there are currently about 1,200 gigawatts of electricity generation capacity of all types on the U.S. power grid.
The report assumes that 10%-20% of this new solar capacity would be deployed on homes and businesses. The rest would be large utility-scale deployments, mostly solar panels, plus some large-scale solar thermal systems that use mirrors to reflect the sun to a central tower.
Assuming that utility-scale solar power requires roughly 8 acres per megawatt, this expansion would require approximately 10.2 million to 11.5 million acres. That’s an area roughly as big as Massachusetts and New Jersey combined, although it’s less than 0.5% of total U.S. landmass.
I think goals like these are worth setting but are good to reevaluate over time to make sure they represent the most prudent path.What are the biggest obstacles?
In my view, the biggest challenge is that driving change on this scale requires sustained political will. Other issues could also slow progress, including shortages of critical solar panel materials like polysilicon, trade disputes and economic recessions. But the engineering challenges are understood and rather straightforward.
Natural gas, coal, and oil provided almost 80% of primary energy input to the U.S. economy in 2020, including electric power generation. Replacing much of it with low-carbon sources would also require retooling most major U.S. energy companies.Shifting to a low-carbon economy would require generating much more energy from low- and zero-carbon sources and electrifying many activities now powered by fossil fuels. LLNL
Such a shift is likely to meet resistance, although some energy companies are starting to expand that way. The Biden administration plans to use the Clean Electricity Payment Program, a provision in the $3.5 trillion budget plan pending in Congress, to create incentives for electric utilities to generate more power from carbon-free sources.
Studies like this solar report also assume that a lot of supporting infrastructure that’s essential to fulfill their scenarios will be available. According to the Solar Futures Study, the U.S. would have to expand its electric transmission capacity by 60%-90% to support the levels of solar deployment that it envisions.
Building long-distance transmission lines is very hard in the U.S., especially when they cross state lines, which is what a massive solar deployment would require. Unless some agency, such as the Federal Energy Regulatory Commission, is empowered to approve new transmission lines, this kind of expansion might be almost impossible.
One potential solution is gaining traction: building transmission lines along existing rights of way next to highways and railroad lines, which avoids the need to secure agreement from numerous private landowners.How would the current system have to change to support so much solar power?
Our power system currently gets about 59% of its electricity from coal and natural gas. These resources are generally, although not always, available on demand. This means that when utility customers demand more power for their lights or air conditioners, the companies can call on these types of plants to increase their output.
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Moving to a grid dominated by renewables will require utilities and energy regulators to rethink the old way of matching supply and demand. I think the grid of the future will need much higher levels of transmission, energy storage and programs that encourage customers to shift the times when they use power to periods when it’s most abundant and affordable. It also will require much greater coordination between North America’s regional power grids, which aren’t well configured now for moving electricity seamlessly over long distances.
All of this is feasible and will be necessary if the U.S. opts to rely on a solar-heavy, decarbonized electricity grid to cost-effectively meet future demand.
Energy Vault's merger with Novus Capital Corporation II values the grid-scale energy storage provider at $1.1 billion, the company announced Thursday.
The combined company is expected to trade on the New York Stock Exchange under the symbol "GWHR." Robert Piconi will lead the combined venture as chairman and CEO.
Energy Vault's energy storage systems use gravity to store and release renewable energy on demand, giving grid-scale reliability to clean energy sources in place of fossil fuels. The company has eight executed agreements and letters of intent for 1.2 GWh of energy storage capacity, with deployments planned for later this year in the U.S., before rolling out in Europe, the Middle East, and Australia in 2022.
“We developed our energy storage solution to get to market quickly given the urgent and global imperative to accelerate the decarbonization of the energy sector," Piconi said in a statement. "Through the deployment of our transformative technology, which can store clean energy for grid-scale deployments while uniquely utilizing waste materials for beneficial reuse in the process, Energy Vault is re-defining the role that energy storage companies can and should play within a circular economic framework."
Energy Vault storage systems have a technical life of 35 years.
As the Federal Energy Regulatory Commission (FERC) begins to study transmission reform, a new report out today from ICF Resources and the American Council on Renewable Energy (ACORE) highlights the problem with transmission cost allocation today.
The study essentially found that while the entire power system typically benefits from significant transmission upgrades, new wind and solar projects are being asked to foot nearly the entire bill when they want to connect to the grid. The analysis, Just and Reasonable? Transmission Upgrades Charged to Interconnecting Generators Are Delivering System-Wide Benefits, focused on a representative sample of network upgrades in the Midcontinent Independent System Operator (MISO) and Southwest Power Pool (SPP) regions. Even with conservative assumptions, ICF found significant system-wide benefits in two-thirds of the upgrades evaluated — benefits that other users of the shared system are receiving at little to no cost.
“Regional power grids are like highway systems, moving power to where it’s needed and keeping electrons flowing to homes and businesses around the clock,” said ACORE President and CEO Gregory Wetstone.
Indeed when the rules were first developed they were reasonable, said Himali Parmar Vice President, Energy Markets with ICF in a webcast about the report. She likened them to the cost of adding a driveway to a road. The costs would be around $10-50 per kW. But with so much demand for renewable energy, developers today are being asked to pay around $250-450 per kW, said Parmar, akin to asking them to add a new lane to the highway or even build an entirely new highway altogether.
“Right now, new wind and solar projects are essentially asked to shoulder the financial burden of adding new lanes to that electron highway, lanes that benefit everyone,” Wetstone said in a statement.
Building an entirely new transmission line benefits the entire system, and ACORE points out that such improvements should be addressed in long-term planning by grid operators like MISO and SPP. Without careful long-term planning, low-cost renewable resources that are needed to meet climate goals will end up stuck in lengthy interconnection queues.
Caroline Golin, Global Head, Energy Markets & Policy, Google, explained in a panel discussion about the report that “buyers across the U.S. are looking to invest and grow the clean energy market and we are being foolish if we don’t recognize the need to massively overhaul the interconnection process.”
Chair Ted Thomas with the Arkansas Public Service Commission who is also a member of the FERC-led Federal-State Electric Transmission Task Force, said that “cost allocation issues will be before the Task Force” and added that “while the study does not focus on the length of time for interconnection studies, reducing the time for studies to be completed in the interconnection queue is an urgent issue.” The Task Force will begin by addressing the issues laid out in the ANOPR that FERC put out in July, he said.
According to FERC’s “beneficiary pays” principle, regional transmission organizations are required to ensure that transmission costs are assigned at least “roughly commensurate with estimated benefits.” Under current rules, new generators in MISO pay for 90 percent of the cost of significant upgrades (345 kilovolts and larger), while others on the system pay 10 percent. In SPP, new generation pays the total cost of any upgrades necessary to interconnect, and other users of the system receive the resulting benefits for free.
Matt Pawlowski, Executive Director, Business Management and Regulatory Affairs, NextEra Energy, one of the largest developers of renewable energy in the country, explained as a builder of renewable energy, that the lack of clarity on cost and timing for a transmission interconnect is really problematic and can “kill” projects.
“If we have a better planning process, we’ll have better visibility on cost and more certainty on schedule,” he said. Lower costs for developers ultimately leads to lower costs for end-users of the energy, he added.
There are currently over 150 gigawatts of active solar, wind, and hybrid resources stuck in interconnection queues across both MISO and SPP, all while the demand for renewable generation is expected to significantly grow in the coming years.
It’s that increased demand for interconnection coupled with an increasing amount of roadblocks in front of renewable energy developers that has really pushed the problem with transmission interconnection front and center said Pawlowski. “We are very excited that this issue is being recognized,” he said.
A unit of East Coast renewable power generator Algonquin Power & Utilities Corp. is working on a new wind power project in Illinois.
The 108-MW Shady Oaks II wind project is a collaboration of Liberty, a part of Algonquin, and JPMorgan Chase. Construction began this spring on the wind farm to feature 22 wind turbines in Lee County, Ill.
JPMorgan Chase will purchase approximately 70% of the wind farm’s energy output, which will serve as the largest contribution to date toward JPMorgan Chase’s 100% renewable energy commitment, supplying the equivalent of about 14 percent of its global power needs. Shady Oaks II is expected to generate close to 350,000 MWh of electricity per year.
“We’re extremely pleased to partner with JPMorgan Chase, a global leader in the finance industry and a sustainability-focused company that is as passionate as we are about advancing renewable energy solutions,” said Brenda Marshall, Senior Vice President, Renewable Generation – Wind for Algonquin. “Shady Oaks II is an important contributor to our goal of continuing to add low-cost renewable generation capacity into our supply mix and supports our commitment to leading the change to a greener, cleaner planet.”
The U.S. Energy Information Administration recently reported that some 2.8 GW of wind power capacity was connected to the grid in the second quarter.
Algonquin is the parent company for Liberty and owns several renewable energy projects in North America. It owns, operates or has an interest in close to 4 GW of clean energy capacity overall.
JPMorgan Chase is a global financial services firm with assets of $3.7 trillion and operations worldwide.
Wind turbine manufacturer Goldwind has connected its 5-megawatt onshore test unit to the grid, as the company prepares to begin deliveries next year.
Goldwind's permanent magnet direct-drive (PMDD) onshore GW 5S Smart Wind Turbine features scaled rated power of 5.2 MW to 5.6 and 6 MW, a 165-meter rotor diameter, and hub heights that can range from 100-130 meters.
"The GW 5S wind turbine is our most powerful onshore turbine to date that takes into account global wind market requirements, customer direction, and extensive research and development – further marking it as a top-rated turbine among Goldwind's already impressive suite of mature PMDD turbine platforms," Goldwind president Cao Zhigang said.
The IEC wind class IIIB product is being developed for China and international markets. The test unit was installed in China in late July 2021 and was grid-connected in mid-August.
It will now undergo a series of testing and international type certifications by DNV.
Contributed by Erik Lensch, CEO of Leyline Renewable Capital
You’ve likely seen the news: The Intergovernmental Panel on Climate Change (IPCC) recently released a report emphasizing humans’ extensive impact on global climate. The report outlined the devastating consequences of our actions and warned that we must make a rapid and unprecedented societal change to combat the perils of a world warmed by 1.5 and 2 degrees Celsius. We have long dragged our feet on making these transitions, particularly as it pertains to limiting fossil fuels used to produce electricity and for transportation. But what if we are undergoing it even more than we think, and the costs of inaction are more severe than we realize? What if the IPCC’s dire warning is based on information that underestimates the need for lightning-fast decarbonization?
A new study and economic model from the Grantham Research Institute on Climate Change and the Environment suggest just that. Most people understand the general impacts of climate change: sea-level rise, worsening weather events, severe heat, etc., but there are also concerns around climate tipping points: When temperatures reach a certain, yet-undefined level, we may cross thresholds of “no return” that cause sudden, more dramatic shifts in climate behavior. The Grantham study examined some primary IPCC tipping points. These include:
The study linked the geophysical mechanisms of these tipping points to quantified economic damages. The conclusion? We are drastically underestimating the social cost of carbon (SCC) – the total social and environmental damage that will result per ton of carbon dioxide emitted. What’s more, the study noted that the examined phenomena are not the only possible tipping points and that even their findings are a “probable underestimate.”
We use the SCC to weigh the costs and benefits of the actions we take to mitigate climate change, i.e., how much must we pay to alleviate X value of climate damage? As of right now, the United States values SCC at $51 per ton, a number which many argue does not account for uncertainty in climate risks, weight for environmental justice, or discount at a rate that will ensure intergenerational equity. $51 is only an interim value to replace the Trump Administration’s $1 to $7 rate, and the final calculation will be set by January 2022.
The Grantham study affirms that, while every SCC estimate requires assumptions and cannot be precise, our current number is extremely off the mark. Gernot Wagner, one of the leads on the report, notes that if the Biden Administration runs the same calculation from the Obama era, the SCC will come out around $125. The study’s new model still pegs that as an underestimate; “when modeled separately and then summed together, the individual tipping points increase the expected SCC by 24.5 percent.” This accounting for tipping point risk aversion places SCC somewhere closer to $250.
And yet, this number could still be too low. The tipping points’ 24.5 percent influence was the median estimate. Depicting the model’s trials on a bell curve produces a long right “tail” of possibility. The trials’ average percent change ran around 43 percent; the model also depicts a one in 10 chance that tipping point accounting could double the SCC.
Putting numbers aside, what does this all mean for our future? The IPCC already says we are on a catastrophic path without rapid change, and so far, the global community has not made strong enough moves to avert this future. We aren’t even close to accounting for climate change’s negative externalities – we aren’t even expending a value close to the grossly underestimated $51.
All is not lost, but we must act, and fast. The U.N. Secretary General called the IPCC report a “code red” for humanity that sounds a “death knell for coal and fossil fuels.” He couldn’t be more correct. We must adopt proper climate accounting, fast-track decarbonization, and transition to a clean global economy. There is no time to waste.
About the author:
Erik Lensch is the CEO of Leyline Renewable Capital, a team of former project developers that combat climate change by providing capital to accelerate the deployment of renewable energy projects. Erik is active in renewable energy advocacy, education, and advancement efforts and brings a sales, finance, and management background to Leyline. Previously, he was CEO and Managing Director at Entropy Solar Integrators, part of York Capital Management, a large global hedge fund. Prior to joining Entropy, Erik spent eight years as the CEO and Founder of Argand Energy Solutions, a commercial and utility scale solar company.
Contributed by Rogér Baylon, Clean Energy Associates
Despite last year’s reinstatement of US tariffs on bifacial modules, solar developers are often considering bifacial modules for their utility-scale solar projects. But the promise of bifacials’ higher energy yield of 6% to 10% – or more – compared to traditional monofacial PERC technology comes at a higher dollar-per-watt module cost, as well as increased expenses for balance of system (BOS) and installation.
To truly understand whether selecting a bifacial module will bring more revenue over time, clients often ask CEA to make an apples-to-apples, levelized cost of energy (LCOE) comparison that takes into account project design, location, insolation, BOS, trackers, and many other factors.
CEA’s approach to calculating the LCOE of different kinds of technologies and pricing is designed to account for a range of variables affecting system performance while providing a clear picture of the increased module value of bifacial systems. This same LCOE methodology can be used for comparing bifacial modules not only to mono PERC but also to the new crop of larger-format modules. However, this case study will focus on comparing bifacials to mono PERC modules.Consider Which PV Technology is Best for You
Before calculating LCOE, the first step is to identify two to three solar module products that have already been assessed for quality, reliability, and bankability. This can be done by identifying some of the most widely used panels with a proven record of production in existing projects.
Second, consider the goal. For example, some clients may be making a large purchase of bifacial panels for different locations. On an LCOE basis, bifacials may be perfect for Massachusetts, where the reflexivity of white snow cover will take advantage of bifacials’ back side and generate more kilowatt-hours (kWh). However, bifacials may not be cost-effective for a similarly sized project in Hawaii, where the state’s greener ground cover may yield less energy and not justify the bifacials’ higher upfront cost.
Another client may be exploring whether purchasing a lower-cost tracker paired with bifacial panels will have a lower upfront cost and higher LCOE. Similarly, a higher-priced tracker with sophisticated, yield-boosting technology may provide more revenue with or without bifacials over 25 years.
With CEA’s LCOE and module value comparison methodology and system modeling, these financial puzzles can be answered, helping developers to make the most informed purchasing decisions.Calculating the LCOE Value of Bifacial Modules
Capturing bifacial’s value and its impact on a project’s bottom line over a 25 to 30-year life cycle begins with the basic LCOE formula:
To create a baseline for the apples-to-apples module evaluation, CEA uses Pvsyst to model optimized layouts for the modules and locations being analyzed. We then price all equipment, labor, design, and engineering, permitting, overhead and margin, and other costs–except the module.
The formula also inputs the estimated annual kWh generated, the power purchase agreement (PPA) price, the investment tax credit, and operations and maintenance (O&M) cost. Variables include the longer life cycles of bifacials – 25 to 30 years – and their higher BOS and installation costs, while degradation and O&M are set at about 0.5% per year.
To compare different panels, the first step is to set a benchmark or “hurdle price” — the price below which a bifacial panel will provide additional value, based on the LCOE of a sample monofacial system.
The hurdle price is then used to back-calculate the price-per-watt module value for one or more bifacial panels, incorporating the specific performance that results from backside output. System parameters, such as site insolation and PPA price, are held constant, although changing them will generally not affect module value.
All LCOE calculations and comparisons are based on projects with a BOS using a uniform set of top-tier, high-quality components. However, as noted, if a client’s goal is to compare trackers or inverters, for example, the model can also evaluate the impact on LCOE.
The charts below show the results of a hypothetical comparison between monofacial Module A, and two bifacials, Module B and Module C, calculated for projects in Massachusetts and Mexico. In this example, the goal is to see if purchasing a large supply of one of the selected bifacial panels will make financial sense for the two locations.
Note that even with the very large differences in production and base LCOE related to location, Bifacial Module C delivers higher and comparable module value, in both cases within a cent of each other.LCOE of Monofacial vs Bifacial Modules vs New Technologies
While the popularity of bifacial panels is relatively new, the technology is not. The difference between monofacial PERC modules and bifacial modules is based more on materials and structure — white back sheet versus glass — than technology, and the industry is becoming increasingly comfortable with bifacials’ long-term performance. Moreover, CEA’s LCOE evaluations used to compare multiple monofacials and one bifacial module, but the situation has since been reversed.
The move toward larger cell formats and larger monofacial panels presents another opportunity to compare the LCOE of bifacial panels to the new formats and cell technologies. For example, larger modules require wider row spacing, which in turn could mean longer wire lengths and a resulting voltage drop. An LCOE module comparison can reveal the positive or negative value of these tradeoffs.
Another key point is that as bifacial module prices continue to come down, the bifacial boost in production needed to offset higher upfront costs will also come down. While bifacials’ increased production is generally estimated at 6% to 10% per year, a much lower percentage could be needed to cover the upfront costs. The exact number will depend on a project’s location and other factors.
It should also be noted that fluctuations in module pricing are occurring due to constraints in the supply of glass. As of this writing, such supply shortages are elevating module pricing for all technologies, but especially for bifacial modules, which have an extra layer of glass on the backside.
As system modeling and data on bifacial performance improve, the timing of these kinds of panel evaluations should also shift. By integrating LCOE and module value comparisons into supply chain management, developers and asset owners can streamline design and procurement, further reducing the time and cost of project development.
About the author:
Rogér Balyon, Senior Manager, Engineering Services, Clean Energy Associates
Based in the Portland Oregon area, Mr. Balyon joined CEA as a project engineer / project manager. He has over 14 years of extensive Solar PV experience including Solar PV system project management, financial modeling, system design and optimization, performance modeling, sales, and as a balance of system engineer. Mr. Balyon is responsible for project management and technical support to Solar PV projects as well as performing technical due diligence of system design, testing and commissioning procedures, quality assurance, and quality control.
Contributed by Bob Fesmire, ABB Inc.
Today is World EV Day, a celebration of the electrification of transport. But while consumer vehicles take up most of the e-mobility headlines, there is another segment of the market that is poised to take EVs (and charging infrastructure) to the next level.
I’m talking about fleets—delivery vans, transit buses, and other commercial vehicles.
Fleet vehicles are well suited to electrification for several reasons. They are used far more than passenger cars (i.e., they have a high utilization factor), so their lower maintenance and fuel costs overcome the higher purchase price (vs. diesel or gas-powered alternatives) sooner. EVs are also highly reliable, due mainly to having a handful of moving parts and far fewer potential points of failure.
In the case of vehicles with predictable routes such as transit buses and delivery vans, going electric allows the fleet operator to plan their operations and optimize charging across the entire fleet. They can also take advantage of green power options from their local utility to reduce their environmental footprint even further.
Finally, EVs can protect fleet owners from the uncertainty around the future of combustion vehicles. The regulatory landscape is shifting rapidly, and it’s almost impossible to predict whether a diesel-powered van purchased today, for example, will reach the end of its design life before being rendered obsolete by electric alternatives.
Ultimately, though, the electrification of fleets comes down to cost. Fleet owners are more likely to see past the higher initial cost of EVs as they evaluate purchases looking at the total cost of ownership over the life of the vehicle. Some studies have already found electric buses to be less costly (again, on a TCO basis) than diesel alternatives, even without tax incentives. For commercial fleets, lower operating costs combined with falling battery prices point to an electrified future.
It’s still early days for EV fleets, but we can expect this segment of the market to move decisively once the business case has been made. We can also expect to see analytics and software play an increasingly important role in fleet operations as tools become available for operators to optimize schedules, routes and charging operations.
If you want to learn more about EV charging and the importance of fleets, check out this recent ABB podcast.
About the author:
Bob Fesmire is a Content Manager at ABB, based in Cary, North Carolina. He has written more than 150 articles and white papers on a variety of topics including energy efficiency, industrial automation, and big data. In addition to his work at ABB, Bob is also the co-author of Energy Explained, a non-technical introduction to all aspects of the energy industry.
The Mountain Iron facility will become the second-largest solar module manufacturing plant in the U.S.
The $21 million expansion of the Mountain Iron, Minnesota facility will begin this month, with production slated to commence in June 2022. The company’s goal is to meet the growing demand for solar modules and help secure the U.S. solar supply chain.
“The State of Minnesota is proud to collaborate with Heliene and the City of Mountain Iron to expand Minnesota’s largest solar panel manufacturer to bring jobs to the region. This is a good day for the Iron Range, and a good day for Minnesota’s clean energy economy,” said Minnesota Governor Tim Walz.
Heliene’s Mountain Iron campus will grow to 95,000 sq. ft. and will feature advanced automation technologies. Production will focus on M6, M10 and M12 size super high efficiency monocrystalline PERC cells.
The company said the expansion will create 60 new, high-paying clean energy jobs. The Mountain Iron facility will become the second-largest solar module manufacturing plant in the U.S.
“Amid consistently strong solar demand and trade volatility, our customers seek peace of mind that they are receiving the highest quality, competitively priced solar modules exactly when and where they need them,” Heliene CEO Martin Pochtaruk said. “The investment in this ultra-efficient new manufacturing line will significantly increase the rate of American Made module delivery while eliminating costly supply chain risks for customers.”
Last month, Heliene launched a new facility in Riviera Beach, Florida, its third in North America.
Heliene is taking over the facility previously occupied by SolarTech Universal, which closed over a year ago, to produce its 66-cell HJT 370W module.
WATCH: Heliene CEO Martin Pochtaruk joined Renewable Energy World Content Director John Engel to discuss the new facility, global solar supply chain pressures, and the growth opportunity with heterojunction solar cell modules.
The U.S. connected 2.8 gigawatts of wind power capacity to the grid in the second quarter of 2021, according to analysis by S&P Global Market Intelligence.
Q2 2021 was one of the strongest second quarters on record for wind power capacity additions, according to the analysis. The U.S. now has 127 GW of cumulative wind power capacity with a pipeline of 62 GW under development through 2025.
Read more: What a year for wind
“Wind power is the dominant source of renewable energy in the U.S., and it is helping to drive the transformation of the nation’s power grid away from fossil fuels,” S&P analysts Justin Horwath and Krizka Danielle Del Rosario wrote. “The turning point occurred in 2020 when renewable energy became the second-most prevalent source of electricity behind natural gas.”
The U.S. wind power capacity pipeline includes 8.6 GW in advanced development. Wyoming leads the nation with 5.2 GW of capacity in late project stages. Apex Clean Energy is the largest owner of planned wind energy installations with 8 GW of projects under development.
An environmental consultant tasked with creating a business model to monetize carbon capture on solar sites will study the ability of different plant mixes to absorb and retain carbon at a 1-megawatt Alliant Energy array.
By Karen Uhlenhuth, Energy News Network
As thousands of acres of Iowa farmland are eyed as possible sites for solar farms, a research project is getting underway to explore a new crop that could co-exist with this burgeoning source of power: carbon sequestration.
The state’s economic development office last month awarded $297,000 to an environmental consultant to create a business model “for monetizing carbon capture on solar energy farms.”
Although solar energy production and “carbon farming” exist independently, the consultant, Mike Fisher, said he didn’t think they’ve been combined, as he has proposed. He will test his theory that the right combination of crops could stash significant amounts of carbon in the ground while enhancing the soil’s fertility. Both the landowner and the solar developer could benefit, he said, from the sale of credits for the sequestered carbon and the enhancements to the soil.
The most common Midwestern crops — corn and soybeans — don’t sequester much carbon because they put most of their energy into producing above-ground “fruits,” said Randy Jackson, an agronomy professor at the University of Wisconsin. Perennials, which plow much more of their energy into roots, stash more carbon as a result. Pasture grasses, such as brome, direct carbon into just the top 12 inches or so, Jackson said. Prairie grasses, by growing roots that tunnel several feet into the ground, stash the carbon for the longer term.
Iowa has been a leading ethanol and wind energy producer for many years, and now is seeing growth in solar development. And in recent years, the state’s economic development authority has been investing research funds in new energy technologies including battery storage, hydrogen, and, now, carbon sequestration.
In June, Gov. Kim Reynolds appointed a Carbon Sequestration Task Force to recommend to the Iowa Legislature policies that could help to build a carbon sequestration industry in the state. The task force held its first meeting last month.
“We are always looking for that new project idea that could have a good impact for the state and our ratepayers,” said Dan Nickel, vice chair of the board of the Iowa Energy Center, the state office that funded Fisher’s pilot project. “The board tries to fund projects where there might be a risk, but is also really good potential.”
Fisher is pursuing his experiment on a seven-acre brownfield site in Perry, Iowa. Alliant Energy, one of the state’s two major electric utilities, is developing a 1-megawatt solar array that it expects will begin producing power sometime in 2022. The city will receive about $45,000 in rent each year from Alliant. The utility will own the power and would receive any proceeds from selling carbon that is sequestered on site.
Fisher aims to test three plant mixes to determine which one sequesters the most carbon. He is considering rye, a mix of prairie species and a combination of flowers that attract pollinators. He’s still refining the particulars with two science professors at Drake University in Des Moines.
Students from Drake will measure the amount of soil carbon before and after the planting regimens. An outside party will verify the students’ measurements. Any change in the soil carbon level may not be apparent for a few years, he said.
Big questions remain about the ability of agricultural land to absorb and retain carbon, according to Michael Castellano, a soil scientist at Iowa State University who has investigated the impact of different cropping systems on soil carbon content. He professed to be “not very excited” about soil’s ability to sequester large amounts of carbon given certain planting regimens.
“Sometimes it works, and sometimes it doesn’t,” he said. “The science isn’t there. Even the idea that restoring a corn/soybean field to prairie will increase carbon, is not guaranteed.”
It is true that prairie soil in the past contained much more carbon than tilled soil does today, Castellano said. Before Europeans arrived and began tilling it, prairie soil was about 3% carbon, Castellano said. The average of farmed soil now is closer to 1%.
“We can get to 3% if we manage like the pre-Europeans, but we don’t know how to manage the land like the natives did.”
Storing the carbon is one challenge. The other is finding a buyer for the accompanying carbon credits. Enterprises such as IndigoAg and TruCarbon are providing an array of services aimed at facilitating carbon market transactions.
TruCarbon, launched in February by Land O’ Lakes, the Minnesota-based dairy cooperative, advises farmers on how to sequester more carbon through measures such as planting an overwintering cover crop, and no-till planting. It takes measurements to determine whether additional carbon is, in fact, being sequestered, and finds a buyer for the carbon credits.
Large corporations with ambitious clean-energy goals are the major market so far for agricultural carbon credits, Fisher said. TruCarbon made its first deal earlier this year with Microsoft, which agreed to purchase up to $2 million in carbon credits through TruCarbon.
Although he estimated the current price for agricultural sequestered carbon hovers at or below a very modest $15 or $20 per ton, Fisher believes the price – and the interest in the farm community – is likely to increase, especially if Congress approves a subsidy for sequestered carbon.
There is interest in Washington D.C. In an April address to Congress, President Joe Biden called soil “the next frontier of carbon innovation.”
The infrastructure bill and reconciliation package before Congress would achieve about 8% of projected carbon reductions by 2030 by sequestering carbon in farmland and forests, according to analysis by the office of Sen. Chuck Schumer, D-N.Y.
Fisher believes that a stable price of at least $35 per metric ton could persuade more landowners to adopt more carbon-sequestering land management techniques.
“If a farmer is going to change management practices,” Fisher said, “they need to be assured as to what price they might obtain year in and year out.”
Germany can, and must, meet the targets of the Paris Climate Agreement by achieving 100% renewable energy by 2030, a new study claims.
Switching to 100% renewable energy for all energy sectors is not urgently needed to limit global warming to 1.5◦C above pre-industrial levels, but is also economically viable, authors of the study, published in the peer-reviewed journal Energies.
“Only technologies that harvest renewable energies are scalable in time and space due to divisibility,” the authors wrote. “Carbon capture technologies, as well as power from nuclear plants, are also frequently brought to the forefront as relevant technical mitigation options. However, they are becoming increasingly irrelevant when confronted with the time scales left for the remaining switch to a climate-friendly system.”
The authors assumed that Germany will need renewable energy sources to cover 1102 TWh heat demand and 967 TWh electricity demand. Under the proposed scenario, newly installed electricity generation capacity is 1143 GW — 80% of which is made up of solar PV and wind power plants. Capacity is secured by 208 GW of bioenergy, geothermal, hydrogen, battery, and pumped storage.
The scenario depends heavily on green hydrogen to reach an energy storage target of 20 TWh.
“The annual costs for the minimum cost target system with 100% RE in Germany are EUR 155 billion and compare favorably with the costs of the current system,” the authors wrote.
As new, more efficient photovoltaic cells become cheaper and more common, and they spread to more and more installations at every scale, they come with a future problem that could get out of hand in the United States, or it could be a source of great opportunity in the industry: solar waste recycling.
According to The MIT Technology Review, the materials used in solar panels could be worth $2 billion a year by 2050, with the amount of decommissioned cells reaching 80 million metric tons. An analysis by Research and Markets predicts that the market for recycled solar panels and parts could grow over 18 percent per year and be worth over $100 million by 2027.
This value can be captured by manufacturers redesigning their products for greater recyclability ahead of regulators — especially since, as prices fall and efficiencies improve, consumers will be more likely to want to upgrade before the 30-year lifespan of their panels is up, according to Harvard Business Review.The solar waste problem
Solar waste is generated from both cells that reach the end of their useful lives and from cells that get destroyed in natural disasters. In 2017, Hurricane Maria destroyed several solar installations in Puerto Rico, resulting in tons of waste as panels were smashed by high winds or flying debris or were uprooted from their housings and became debris themselves.
The waste that resulted presented difficulties not only because of its quantity but because it can’t go into normal landfills on account of the toxic chemicals used in solar cell production: heavy metals like cadmium can leach into the environment through water. To make things worse, much of the United States’ e-waste has historically been exported to China, where low labor costs and limited environmental protections meant that some valuable materials were recovered and the rest caused lots of birth defects. But China no longer accepts e-waste on the same scale, creating a potential ecological backlash to decarbonization.
A solar cell is mostly made out of materials like glass and aluminum. These are easy to recycle. For cells that have reached the end of their working lives, they may even be possible to directly reuse. The rest is the meat of the cell, the materials that exhibit the photovoltaic effect, combined with the semiconductors and other things needed to get a useful electric current out of them.
According to Waste Dive, it currently costs $20-$30 to recycle a solar panel, but the recovered materials are only worth about $3-$4, which creates a substantial barrier to keeping them out of landfills. Some businesses are focusing on reuse — recovering functional panels and selling them to markets that can’t afford new ones.
One problem is that regulators sometimes classify solar panels as hazardous waste, which adds substantial costs to recycling. Another is that many solar panels are not designed with recycling in mind, although the European Union requires manufacturers to produce solar cells that are 85 percent recyclable — similar regulation doesn’t exist in the United States.
The global pandemic, the rise of populist politics in the United States, and greater environmental awareness may also combine to create opportunities. COVID-19 continues to disrupt global shipping routes while it’s increasingly recognized that shipping so many products across the Pacific is very bad for the environment. Politicians of both major parties in America have made tentative steps towards adopting some kind of industrial policy to promote the manufacturing industry and while the Trump administration’s tariffs are gone, The New York Times reports that some Democrats want to replace them with taxes on imports from polluting countries, like China. Such a combination of factors may provide subsidies to manufacturing solar panels in the United States while making Chinese imports more expensive — and the raw materials recovered from solar waste would be in demand because mining and refining metals like aluminum is also very dirty.
The Solar Energy Industry Association, the main trade group for the solar industry in the United States, is pushing for states and the federal government to adopt regulations in line with the European Union. Companies that already handle solar waste also support the regulations, while ones that design, manufacture, and import the modules fear resellers and recyclers shutting them out of markets with their own products.
Solar recycling has definite potential and a large role to play in creating an “ecosystem” for renewable energy. Businesses should not let the opportunity go to waste.
OYA Solar, a renewable energy developer and independent power producer, has started construction on six community solar projects in New York State.
The combined 32 MWDC community solar projects are part of the NYERDA VDER program, benefiting residents and businesses in Franklin, Jefferson, Livingston, Onondaga, and Oswego Counties.
The projects are expected to generate approximately 895,000 MWh of power and offset 699,000 tons of carbon dioxide over their 25-year operation.
Read more: What a year for wind
“OYA Solar has an ambitious goal of becoming one of the largest constructors and operators of community solar projects that will support New York’s transition to a cleaner and more resilient energy source,” said OYA Solar CEO Manish Nayar. “Our strong development and construction platform has a proven track record in New York, and more broadly across the Northeast U.S. and Canada, and we embrace our role as a driver of solar energy expansion and accessibility.”
OYA Solar expects to build an additional 140 MWDC of community solar projects in New York State by the end of next year. The company has a 2 GWDC pipeline of community solar and utility-scale projects across the Northeast U.S. and Canada.
The Biden administration on Wednesday outlined an ambitious plan for wind and solar energy to provide 90% of U.S. electricity by 2050.
The U.S. Dept of Energy’s Solar Futures Study is a blueprint that broadly shows how the U.S. could reach the milestone in the Biden administration’s quest for a zero-carbon grid. The 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.
The remainder of the energy mix under the blueprint would be wind (36%), nuclear (11-13%), hydroelectric (5-6%), and biopower/geothermal (1%).
“The study illuminates the fact that solar, our cheapest and fastest-growing source of clean energy, could produce enough electricity to power all of the homes in the U.S. by 2035 and employ as many as 1.5 million people in the process,” said Secretary of Energy Jennifer M. Granholm. “Achieving this bright future requires a massive and equitable deployment of renewable energy and strong decarbonization policies – exactly what is laid out in the bipartisan Infrastructure Investment and Jobs Act and President Biden’s Build Back Better agenda.”
To meet President Biden’s 2035 clean energy goal, the #solar workforce must grow 4x to over 900,000 #AmericanJobs. Today 750 solar companies outlined how we get there in a letter to Congress.
Read the letter: https://t.co/ewUAJNG95Z | #BuildBackBetter pic.twitter.com/OEWSmAg65B
The blueprint calls for U.S. energy storage capacity to grow from 30 GW to 1,700 GW by 2050 to provide flexibility and resilience for renewable energy sources. Grid-forming inverters, forecasting, microgrids, and transmission expansion will all be needed, too, the study said.
The study states that a renewable-based grid, and reduced carbon emissions, will result in savings of $1.1 trillion to $1.7 trillion.
Jean Su, energy justice program director at the Center for Biological Diversity, said the Biden administration’s target shows “real promise in addressing the climate emergency, but it has to include careful considerations of scale and design.
By prioritizing rooftop and community solar and storage, Biden’s team could boost energy affordability and resilience in extreme weather events like Hurricane Ida. Because private utilities are fighting distributed energy, the Biden administration should make utility reform a key part of this important climate and justice transformation.”
As the New York Times noted, the blueprint offers only a broad outline of the target, not how to get there.
Last month, Senate Majority Leader Chuck Schumer wrote to colleagues that approving the bipartisan infrastructure bill and the budget reconciliation package would allow the U.S. to nearly reach the Biden administration’s goal of cutting greenhouse gas emissions by 45%, compared to 2005 levels, by the end of the decade.
Here's the chart Schumer's office sent out on how they'd get to this 45% emissions reduction number. The vast, vast majority comes from reconciliation and a Clean Electricity Payment Program (a CES) + clean energy tax incentives for wind, solar & other renewables. pic.twitter.com/efUNSIHDST— Ella Nilsen (@ella_nilsen) August 25, 2021
Schumer’s office said the Clean Electricity Payment Program and tax credits for renewable energy sources will make the biggest impact, accounting for 42% of emissions cuts. Incentives for electric vehicles would make up 15.7% of cuts, the analysis shows.
“When you add Administrative actions being planned by the Biden Administration and many states – like New York, California, and Hawaii – we will hit our 50 percent target by 2030,” Schumer said in the letter, according to The Hill.
Lindsey Walter, deputy director of climate and energy for the think tank Third Way, joined Renewable Energy World’s John Engel to discuss the importance of the Clean Electricity Payment Program.
Invenergy and BW Offshore are partnering on a bid to build a massive, 5.4-gigawatt wind project proposal offshore Scotland, the companies announced Wednesday.
The offshore wind project will be a mix of floating and fixed foundations off the northeast coast of Scotland, as part of the first ScotWind leasing round.
“We are uniquely positioned to deliver innovative offshore wind infrastructure to Scotland through leveraging Invenergy’s decades of experience, expertise in leading complex projects to completion and network of strategic supplier relationships such as with GE Renewable Energy,” said Bryan Schueler, senior executive vice president and construction business leader for Invenergy. “This joint venture represents an important milestone in furthering our partnership with BW Offshore and Invenergy’s continued investment in Scotland and its clean energy future.”
Invenergy has developed 180 projects across four continents totaling more than 29 GW of renewable energy capacity. BW Offshore is a floating production specialist that supports the transition to a low carbon economy.
“Together, we represent a unique blend of expertise and ambition to deliver the next phase of energy transition in Scotland, bringing substantial international project development experience and a strong track record for local value creation,” said BW Offshore CEO Marco Beenen. “ScotWind will play a critical role in delivering the nation’s offshore wind targets and our ambition is to be a central part of this journey, committed to working with Scotland’s supply chain to accelerate the energy transition.”