As clean energy professionals, we’re rightfully proud of the rapid progress being made in deploying solar, wind, and battery storage technologies. The plummeting costs and increasing efficiencies of renewables mean that greening the grid by 2050 is now a realistic goal. This is cause for celebration.

However, we must also reckon with an inconvenient truth: even if we achieve 100% clean electricity by mid-century, atmospheric CO2 levels are still on track to reach around 450 parts per million (ppm) by 2050 – far above the 350 ppm level considered safe for humanity. The painful reality is that the clean energy transition, while absolutely necessary, is not sufficient on its own to avert climate catastrophe.

This is the stark message of Peter Fiekowsky’s recent book Climate Restoration, which argues that we must go beyond emissions reductions to actually remove a trillion tons of legacy CO2 from the atmosphere. Only by restoring CO2 to pre-industrial levels below 300 ppm can we ensure the long-term survival and flourishing of human civilization.

Fiekowsky, an MIT-educated physicist and entrepreneur, contends that relying solely on emissions cuts to stabilize CO2 around 450 ppm is far too risky. Humans have never lived long-term with CO2 that high. The last time levels were similar was over 3 million years ago, when sea levels were 60 feet higher and global temperatures 5-8°F warmer. Allowing CO2 to remain elevated for centuries risks crossing irreversible tipping points in the climate system.

The good news is that CO2 removal at the necessary scale is technologically feasible and surprisingly affordable, costing an estimated $1-2 billion per year. Fiekowsky identifies four main approaches that could restore atmospheric CO2 to safe levels by 2050:

1. Ocean iron fertilization to stimulate plankton blooms that absorb CO2
2. Seaweed permaculture to grow and sink carbon-sequestering kelp
3. Synthetic limestone manufacture using captured CO2
4. Enhanced atmospheric methane oxidation

These nature-based and biomimicry solutions harness and accelerate the Earth’s natural carbon cycle processes. Importantly, they are permanent, scalable, and financeable – key criteria for viable CO2 removal approaches. When you consider that New York City (just one major coastal metro) is currently debating whether to spend $20 to $50 billion dollars on an ocean barrier system to prevent future storm surges from flooding the city, the $2 billion/yr price tag on climate restoration seems like a better bet.

As clean energy professionals, we must expand our focus beyond just greening the grid to include large-scale carbon removal. Here’s why:

First, it’s a moral imperative. We have an obligation to restore a safe, stable climate for future generations. Stopping emissions is necessary but not sufficient – we must clean up the trillion-ton legacy CO2 mess we’ve already created.

Second, it’s risk mitigation. Relying solely on emissions cuts without CO2 removal is an enormously risky bet on humanity’s ability to thrive in a radically altered climate state. Carbon removal gives us vital insurance.

Third, it’s economic opportunity. CO2 removal solutions like synthetic limestone can produce valuable products, creating new industries and jobs. The transition to a circular carbon economy will require major infrastructure investments.

Fourth, it’s technically synergistic. Many carbon removal approaches like ocean fertilization or seaweed cultivation could be powered by offshore wind or floating solar, creating virtuous cycles.

To be clear, carbon removal is not an excuse to slow down the clean energy transition – both are essential. But the clean energy community must broaden its vision to champion carbon removal alongside renewables deployment.

Specific actions we can take include:

• Advocate for updating climate policy goals to include restoring CO2 to pre-industrial levels (300 PPM of CO2 is worthy goal), not just emissions cuts
• Support R&D funding and commercial deployment of CO2 removal solutions
• Explore integrating carbon removal with renewable energy projects
• Educate ourselves and others on the need for atmospheric CO2 cleanup

The coming decades will be pivotal for humanity’s future. By combining a rapid shift to 100% clean energy with large-scale deployment of carbon removal solutions, we can create a true climate restoration future – one with a healthy, livable planet for generations to come. But we must act quickly and decisively. The clean energy industry has shown it can innovate and scale rapidly when needed. Now we must apply that same spirit to carbon removal. Our children’s future depends on it.

Tim Montague leads the Clean Power Consulting Group and is host of the Clean Power Hour podcast. He is a solar project developer, cleantech executive coach and consultant, mastermind group leader, entrepreneur and technology enthusiast. 

The Coalition for Community Solar Access (CCSA) released its Policy Roadmap that includes a guidebook, model legislation, inclusive solar access solutions for low-to-moderate income subscribers and consumer protection best practices. It’s intended to serve as a blueprint for states without competitive community solar programs to pass legislation that supports programs. It also provides insight into how to maximize federal funding.

“Our Roadmap boils down nearly a decade of the best lessons we’ve learned from creating community solar markets across the country into a succinct set of documents,” says Molly Knoll, Vice President of Policy, CCSA. “With many states exploring the development of new, or revamped, community solar programming and federal funds ready to deploy, this felt like the perfect time to release this helpful guide for all our advocates.”

The community solar is on the rise as it brings economic and social benefits to all Americans seeking local, clean community solar energy. By its design it lets people benefit from solar energy who may be unable to install solar either due to financial restrictions or because they do not have a suitable rooftop for solar.

Wood Mackenzie expects 7.6 GW of new community solar will come online in existing state markets between 2024 and 2028, and the national total of community solar installations is expected to pass 10 GW of cumulative capacity in 2026.

The CCSA’s aim with the Roadmap is to help the industry continue on the upward trajectory it’s currently experiencing, which requires strong programmatic and policy decisions.

The Roadmap’s release coincides with the U.S. Environmental Protection Agency is set to deploy $7 billion to state applicants through its Solar for All program, a funding opportunity that has a goal of bringing solar energy to low-income households. Recipients were chosen based on their proposals to develop programs designed to serve communities facing barriers to distributed solar deployment, with 100% of funding supporting low-income and disadvantaged communities in all 50 states the District of Columbia, Puerto Rico and territories.

Supporting low-income households

As recently shown in community solar programs and research reports from Wood Mackenzie and the Lawrence Berkeley National Lab  (LBNL) community solar has effectively expanded solar access to multifamily housing occupants, renters and low-income households. Based on a sample of 11 states, the LBNL study found that community solar adopters in 2023 were about 6.1 times more likely to live in multifamily buildings than rooftop solar adopters, 4.4 times more likely to rent, and earned 23% less annual income.

“The data speaks for itself: when states implement thoughtful policy programs that simplify income verification, billing, and expand access, we see immense growth in community solar adoption by low-to-moderate income households,” said Stephanie Burgos-Veras, senior manager of equity programs, CCSA. “We hope our Policy Solutions for Inclusive Solar Access primer can lead to more community solar programming being implemented — so that ultimately, more LMI households can benefit.”

The new CCSA Roadmap is intended to be used in conjunction with a companion document that provides Model Legislation for Community Solar Programs, that serves as a toolkit for policymakers to draft effective and sustainable community solar policies. The toolkit helps them tailor the program to community residents; kickstart the market with bill credit structure, oversight and administration; ensure long-term success by integrating community solar programs into existing utility and energy infrastructure of a state.

Also covered are potential challenges, the role of utilities, interconnection issues, program size and more. It also offers strategies to ensure that programs exist long into the future and continue to serve local residents.

Community solar legislation has been adopted in 19 states and the District of Columbia and multiple states have legislation in the works with nearly a dozen considering laws to create programs. Combined with the Solar For All program, CCSA believes that now is the time for policymakers to revisit the idea of bringing community solar to their state.

Find all the documents in the Policy Roadmap here under the “CCSA & Other Resources” tab.

Recurrent Energy, a subsidiary of Canadian Solar, signed a $103 million tax credit facilitation agreement with Bank of America for its North Fork Solar Project.

The tax equity agreement is Recurrent Energy’s first production tax credit (PTC) transaction and first tax credit transfer transaction. Recurrent reports that by transferring tax credits to Bank of America, it can access funding more quickly and efficiently.

In April the Internal Revenue Service (IRS) released final guidance for the transfer of clean energy tax credits, a provision within the Inflation Reduction Act and the Creating Helpful Incentives to Produce Semiconductors (CHIPS) act that allow tax credit owners to sell their credits to other entities with a tax appetite.

Under a tax credit transfer transaction, renewable energy developers and owners can sell tax credits for cash, making financing easier for new clean energy projects. The transferability option is generally open to the entities that are not covered by the direct pay option. More information in the frequently asked questions section can be found here.

Oklahoma Municipal Power Authority (OMPA), which serves 42 municipally owned electric systems in Oklahoma, will purchase 100% of the energy produced by North Fork Solar under a 15-year agreement. This marks the first solar project in OMPA’s energy mix. Recurrent Energy will continue to own and operate the project long-term.

“This addition will further diversify our energy sources and provide our member cities with more energy options to offer their customers,” said David Osburn, OMPA general manager. “We look forward to maintaining a long-term relationship with Recurrent Energy.”

The 120 MWac North Fork Solar project, which sits on 1,012 acres in Kiowa County, Oklahoma, will provide enough electricity to power the equivalent of 35,000 homes year.

This project greatly increases the amount of solar installed in the state of Oklahoma, which ranked 46^th for installed capacity in Q1 2024 with 189 MW, according to the Solar Energy Industries Association. At that time the Covington Solar Farm at 13.2 MW, which came online in 2017, was a landmark project.

Construction by Blattner began in August 2023 and was compete in June  2024 with approximately 250 people employed during peak construction and three permanent jobs during operation.

According to Recurrent Energy’s website, the project used construction methods to minimize grading and removal of soil, and preserved topsoil was redistributed across the graded areas to assist in growing ground cover as quickly as possible.

Recurrent Energy reports that during the project’s development and construction, the company supported local initiatives, including the Snyder 4-H and FFA, Snyder Prom, and Cyclone Educational Foundation. Now that it’s operational, the solar project will contribute about $26 million to community services.

Recurrent Energy began developing North Fork Solar in 2018. NordLB and Rabobank provided project financing for North Fork Solar. CRC-IB and Latham & Watkins advised Recurrent Energy on the tax credit transfer transaction.

Community solar provider Ampion Renewable Energy is partnering with The Wendy’s Company to help the restaurant chain source renewable energy. By signing onto community solar projects, companies like Wendy’s support the generation of renewable electricity for local grids.

Nearly 100 company-operated Wendy’s restaurants and nearly 40 franchise restaurants in New York, Illinois, and Massachusetts are now enrolled in Ampion+, a product that enables organizations t secure renewable energy certificates (RECs). RECs are a green power procurement strategy that electricity consumers, such as Wendy’s, use to substantiate renewable electricity use claims.

The result of the agreement, according to Ampion, is that the enrolled restaurants will source between 30% and 100% of their energy from solar without the need to install solar panels onsite. Wendy’s plans to increase the number of restaurants enrolled in Ampion’s community solar program as additional solar generation capacity comes online and more franchise restaurants enroll in the program.

“We are excited about the opportunity this partnership provides our Company and franchise restaurant operators by making it easier and more accessible to source clean energy while ultimately realizing cost savings,” said Steven Derwoed, vice president, global design & construction at Wendy’s. “We are advancing progress toward our emissions reduction goals through community solar participation and RECs. It’s a win-win for the Company and our franchisees.”

Last year, Wendy’s set near-term science-based targets to reduce absolute Scope 1 and 2 emissions by 47%, and Scope 3 emissions from franchisees by 47% per restaurant by 2030, from a 2019 baseline.

Through Ampion, Wendy’s locations have enrolled approximately 27.5 million kWh in community solar or the equivalent electricity needed for 2,200 homes for one year. Each kilowatt hour will be accounted for, tracked, and assigned ownership to a specific restaurant location via RECs through the Ampion+ product.

“As the need for reducing carbon emissions grows, community solar combined with RECs provides a solution for environmental sustainability in the corporate sector that is both achievable and affordable, while enabling companies to quantify and disclose their progress in a standardized manner,” said Nate Owen, CEO and founder of Ampion. “We’re seeing more large companies actively seeking sustainable solutions through community solar. This partnership with Wendy’s demonstrates that Ampion is able to support these organizations in reducing emissions and putting more renewable energy on the grid for local communities.”

Community solar is expanding rapidly in the U.S. with 22 states, including Washington D.C. that have policies supporting third-party shared or community solar. According to the Coalition for Community Solar Access, 6.6 GW of community solar generation capacity has been installed to date, and Wood Mackenzie’s most recent U.S. community solar market outlook predicts that there will be 14 GW power installed across the country by the end of 2028.

Earlier this year, Ampion surpassed 1 GW of community solar generation under management. Currently active in nine states and counting, Ampion acquires and manages subscribers of all types, from housing authorities, municipalities, and enterprises such as Wendy’s, to small businesses and residential subscribers. Ampion reports that it acquired thousands of low-to-moderate income subscribers in 2023, expanding access to those who need savings the most.

Norsun plans to invest $620 million in a new 5 GW silicon ingot and solar wafer manufacturing facility on a 60-acre greenfield site in Tulsa, Oklahoma.

The Inflation Reduction Act (IRA) has motivated solar module manufacturers to build manufacturing facilities in the U.S; however, very few factories are planned for the production of ingots, wafers and cells. This shortage leaves U.S. solar module makers reliant on imports, mainly from China.

Production at the new Norsun plant is expected to begin in 2026, bringing much-needed U.S.-made silicon ingots and wafers to the supply chain, as well as 320 jobs to the Tulsa area. Norsun reports that production can be expanded up to 10 GW.

“Our business plan has an ambitious timeline, so we knew we needed a partner who can work fast and efficiently to meet the critical need for American-made energy,” said NorSun CEO Erik Løkke-Øwre. “Oklahoma impressed us even before our selection journey – its robust clean energy, manufacturing ecosystem and workforce development programs were already on our radar, and its competitive business offerings and site acceleration options solidified our decision.”

Norsun, founded in Norway in 2007, specializes in the production of monocrystalline ingots and wafers for ultra-high efficiency solar cells. The expansion was facilitated by the Oklahoma Department of Commerce and Tulsa Airports Improvement Trust.

“I’m proud to welcome Norsun to Oklahoma, and I’m thrilled that Oklahomans will benefit from hundreds of new jobs in the Tulsa area and a $620 million capital investment,” said Governor Kevin Stitt. “Our pro-growth policies, workforce development efforts, and ‘more of everything’ energy approach make us an incredible state to invest in, and I’m glad NorSun can be a part of it.”

Origami Solar announced partnerships with three steel fabricators who will domestically produce steel solar module frames. The fabricators include with Welser Profile of Valley City, Ohio; Priefert, of Mt. Pleasant, Texas; and Unimacts of Houston, Texas. Origami expects to be able to ship steel frames to customers in the first quarter of 2025, and by producing regionally says that frames will get from the fabricator to the module manufacturer in one to two days.

“America has one of the world’s strongest steel industries” said Origami Solar CEO Gregg Patterson. “We have the energy efficient steel mills and the world-class fabricators that can produce every solar frame America will ever need.”

Origami Solar, founded in 2019 and based in Bend, Oregon, is a pv magazine 2023 award winner for manufacturing. The company produces patented, steel solar module frames that are said to lower cost and improve module performance. The company reports that the frames are made of “green” recycled steel, thereby reducing greenhouse gases by up to 93%, representing a reduction of 80 kg per module or 200 metric tons per MW.

A recent report by Wood Mackenzie and Origami Solar notes that while the U.S. is working toward building up its domestic module manufacturing, thanks for the IRA, a less well-known problem is U.S. dependence on aluminum module frames. The majority of these are currently imported from East and Southeast Asia, and the report says that they are all made from carbon-intensive aluminum.

Origami sees an opportunity to supply module manufacturers in the U.S. market who are switching from imported aluminum frames to domestically made steel frames. Its use of recycled steel from suppliers in the U.S. and Europe in its frames give it a competitive edge when it comes to greenhouse gas scoring as assessed by Boundless Impact

Patterson points out that by having regional fabrication centers in the U.S., customers will avoid “shipping issues, labor strife, or impoundments delaying the arrival of the frames they need.” He added that by procuring domestically produced steel frames customers won’t have the worry of “geopolitical tensions” or “ever-increasing tariffs.” In light of recent news about fragile solar panels, he noted that steel frames may alleviate the risk of frames failing to support ever-larger solar panels.

Switching to domestically produced products across the solar supply chain has the further benefit of supporting good-paying jobs.

“Thanks to our partnership with Origami, we were able to expand our investments in the solar industry, keep our Benton, Arkansas facility open, keep our current employees hard at work and expand to up to 70 additional skilled workers over the next three years,” said Rocky Christenberry, Priefert’s executive vice president

With more than 300,000 buildings and 600,000 vehicles, the U.S. Government is the nation’s largest energy consumer. As a part of the Federal Sustainability Plan that directs the Government to achieve net-zero emissions by 2050, the Government is quickly ramping up use of solar energy at military bases, five of which will soon be drawing electricity from two solar installations in South Carolina.

In a partnership with Duke Energy valued at an estimated $248 million, the Department of Defense (DOD) will be the exclusive purchaser of all output generated by two new solar facilities. The five military installations across North Carolina and South Carolina to benefit from the clean energy include Fort Liberty, USMC-Camp Lejeune, USMC-Cherry Point, USAF Seymour Johnson and USAF Shaw.

“DoD is leading by example on climate change in ways that will spur new clean electricity production, create good-paying jobs, increase our resilience to climate change, and enhance our national security,” said Andrew Mayock, Federal Chief Sustainability Officer at the White House Council on Environmental Quality.

Duke Energy estimates that it will provide 135 MW and approximately 4.8 million MW-hours of renewable energy in both states over a 15-year delivery period. According to the DoD, these installations will achieve 75% of their 2030 carbon-free energy requirement. Fort Liberty, for example, will reduce its emissions from electricity by 27% compared to 2022, with cost savings possible by 2040. The two solar facilities, which are expected to become operational in 2026, will be developed, owned and operated by energyRe, according to Duke.

“This project is a great opportunity to assist our military departments and our warfighters in their decarbonization goals and is paramount to reaching our initial goals of Executive Order 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability. DLA Energy is committed to supporting the administration’s clean energy initiatives and helping the military services and whole-of-government partners achieve their climate change goals,” said United States Air Force Col. Jennifer Neris, director of carbon pollution-free electricity for the Defense Logistics Agency.

Duke Energy reports that it currently owns, operates and purchases more than 5,100 MW of solar power on its energy grid in the Carolinas or enough to power nearly 1 million homes annually. North Carolina currently ranks No. 5 in the nation for overall solar power. With a portfolio of nuclear, hydro and renewable energy, the utility says more than half of its energy mix in North Carolina is carbon-free.

The DoD said in a statement that it will continue to seek partnership opportunities that enable the agency and other Federal partners to achieve President Biden’s carbon-free energy goals and build a robust, clean, and domestically based electricity supply chain by 2030.

“Our partnerships with utility companies are essential to delivering energy resilience for the Army,” said Rachel Jacobson, assistant secretary of the Army for Installations, Energy, and Environment. “These partnerships are helping us put microgrids with carbon-free energy generation and storage on our installations. And our continuing collaboration with Duke Energy allows the Army to contribute to a more reliable commercial grid that strengthens the resilience of the defense communities where our soldiers, military families, and civilians live. I am proud of these partnerships and look forward to expanding them so that our installations always have access to the electricity we need to defend the nation.”

Summit Ridge Energy expanded its partnership with Qcells with an agreement to purchase 800 MW of solar panels.

The agreement builds on an existing 1.2 GW relationship between Qcells and Summit Ridge, announced in April of 2023 by Vice President Kamala Harris. At the time the 1.2 GW order was the largest equipment purchase in history for the community solar market.

By increasing the total commitment to 2 GW, Summit Ridge reports it will develop more than 100 additional community solar projects across the country using U.S.-made solar.

Last year Qcells announced what was then the largest investment in U.S. solar manufacturing history, investing more than $2.5  billion to build a complete solar supply chain in the United States. This made the Korean company, a subsidiary of Hanwha Solutions, the first company to establish a fully-integrated silicon-based solar supply chain in the U.S. When complete, Qcells solar panels — from polysilicon to the finished panel — will be entirely made in the U.S.

Both the build-out of Qcells U.S. manufacturing footprint and the growth of Summit Ridge Energy are incentivized by the Inflation Reduction Act (IRA). The includes tax incentives for domestic energy production as well as manufacturing. Many of Summit Ridge’s solar projects also qualify for IRA tax credits that will provide thousands of low-income households with greater access to clean energy savings.

“We are excited to expand our partnership with Qcells, which enables Summit Ridge to deliver on our promise of giving more Americans the opportunity to power their homes and businesses with locally generated clean energy,” said Brian Dunn, chief operating officer of Summit Ridge Energy. “Through our Qcells partnership, we are able to support domestic manufacturing and job creation, while simultaneously bringing low-cost clean energy to communities that have historically been left out of the clean energy transition.”

Summit Ridge’s planned fleet of community solar farms are expected to generate enough clean energy to power an estimated 200,000 homes and businesses. Since launching in 2017, the company reports that it has deployed over $2.6 billion into clean energy assets and controls a development pipeline of more than 3 GW that will provide solar power to homes and businesses nationwide.

“Expanding this relationship with Summit Ridge Energy means more communities will have access to the most affordable energy resource in the world,” said Justin Lee, CEO of Qcells. “This partnership not only supports the domestic manufacturing industry and thousands of jobs in solar, but it also ensures more people – especially those who have historically been left out – benefit from everything the clean energy economy has to offer.”

The majority of the solar panels purchased by Summit Ridge will be produced in Qcells’ new U.S. manufacturing facility located in Georgia. Additionally, Qcells will continue to provide Summit Ridge with battery storage and software solutions under separate procurement agreements.

Nearly two years following passage of the Inflation Reduction Act of 2022 (IRA), Treasury and the IRS released the unpublished version of the final rule (Final Rule) for compliance with the IRA’s prevailing wage and apprenticeship requirements (PWA requirements).

Taxpayers seeking to claim the highest available investment and/or production tax credits for renewable energy projects must comply with the PWA requirements. A taxpayer must ensure that laborers or mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of a qualifying facility comply with the PWA requirements.

The Final Rule concludes the federal rulemaking process for the PWA requirements. (Note: The Final Rule is scheduled to be officially published on June 25, 2024, and therefore this article relies on the unpublished version.)

The Final Rule will replace the previously-issued Notice of Proposed Rulemaking (released August 30, 2023) (NOPR), which replaced the Initial Guidance (released November 30, 2022). Overall, the Final Rule is generally consistent with the NOPR, providing helpful clarification on industry concerns raised in comments to the NOPR. However, the Final Rule expressly declines to address industry-specific concerns, emphasizing that determinations of compliance with PWA requirements will be made based upon specific facts and circumstances. It therefore leaves several questions open to interpretation, including whether commissioning work is subject to PWA requirements and to what extent certain post-operational work may be subject to PWA requirements.

Clarifications

First, with respect to when PWA requirements apply, the Final Rule provides two useful clarifications:

Its supplementary information notes that “unrelated third party manufacturers who produce materials, supplies, equipment, and prefabricated components for multiple customers or the general public” are not subject to PWA requirements. In other words, most suppliers (absent performance of construction, alteration or repair on a project site) will not be subject to PWA requirements.

It also clarifies that apprenticeship requirements only apply to the construction of a qualified facility, and do not apply to alteration or repair of a facility after the facility is placed in service. In other words, most operations and maintenance vendors will not be subject to apprenticeship requirements.

Second, with respect to payment of prevailing wages, the Final Rule outlines regulations consistent with the NOPR: A taxpayer must ensure that laborers or mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of the facility are paid prevailing wages for the specific type of construction in the geographic area where the facility is located. The definitions of “laborers and mechanics” and “construction, alteration or repair” provided in the Davis-Bacon Act (40 U.S.C. § 3141 et. seq.) apply to the PWA requirements. General wage determinations issued by the Department of Labor’s Wage and Hour Division on www.sam.gov provide the appropriate prevailing wages for PWA requirements. The Final Rule lists Form WH-347 (the Davis-Bacon form for certified payroll) as one example of a record that may demonstrate compliance with PWA requirements.

Notably, however, the Final Rule distinguishes prevailing wage requirements from Davis-Bacon Act requirements – noting that prevailing wage requirements pursuant to the IRA are not a mirror of the Davis-Bacon Act, but instead may be merely in harmony with Davis-Bacon requirements. Treasury and the IRS therefore declined to implement certified weekly payroll, public notice, and other Davis-Bacon Act requirements as part of the PWA requirements.

While the Davis-Bacon Act focuses on the “site of the work” to determine when prevailing wages must be paid, the Final Rule uses a similar concept of “the locality in which a facility is located.” The locality in which a facility is located is the physical place or places where the facility will be placed in service and remain – commonly understood as the project site. It also includes secondary locations where a significant portion of the facility is constructed, altered, or repaired – but excludes secondary locations for fabrication or manufacturing that are not established specifically or dedicated exclusively for a specific period of time to the facility.

Significantly, the Final Rule largely resolves the question of which prevailing wage applies to a facility. It confirms that the prevailing wage in effect at the time the agreement for construction, alteration or repair of the facility is executed is the wage that applies for purposes of the PWA requirements. The same wage general wage determination may still be used if the contractor is given additional time to complete its original commitment or if additional work is incorporated into the agreement that is “merely incidental,” which provides reassurance with respect to usual course of business change orders during construction of a facility. If, however, the agreement is modified to include “additional substantial construction, alteration or repair work not within the scope of the work of the original contract,” or if the agreement is modified to “required work to be performed for an additional time period not originally obligated,” including exercise of an option to extend the terms of an agreement, a new general wage determination will be required.

For wage determinations needed and not covered by a general wage determination, the Final Rule generally follows the NOPR’s outline for submission of supplemental wage determination requests to the Wage and Hour Division. The Final Rule notes that taxpayers, contractors or subcontractors may submit supplemental wage determination requests. Such requests should be submitted no more than 90 days before the expected execution of a construction contract (or at any time following execution), and will remain effective for 180 calendar days after they are issued (or for the duration of the time the supplemental wage determination is incorporated into the contract).

The Final Rule also provides that the Wage and Hour Division will resolve supplemental wage determination requests, or notify the requester that additional time is necessary, within 30 days of submission of a request. If a supplemental wage determination is issued after construction work has started on the facility, it applies retroactively to the date construction started.

Third, with respect to apprenticeship requirements, the Final Rule incorporates many proposed regulations from the NOPR, including the three-pronged approach necessary to comply: taxpayers must ensure the labor hour requirement, the ratio requirement, and the participation requirement are each satisfied.

Many of the ambiguities raised in comments to the NOPR regarding apprenticeship focused on the Good Faith Effort Exception, and the Final Rule addresses several of them. Requests made to registered apprenticeship programs must be made in writing and sent electronically or by registered mail. Initial requests must be made no later than 45 days before the qualified apprentices are requested to start work, and subsequent requests must be made no later than 14 days before the qualified apprentices are requested to start work. The content of each request remains as outlined in the NOPR.

The Final Rule extends the period between requests on which a taxpayer may rely on the Good Faith Effort Exception to a full calendar year. In the event a request to a registered apprenticeship program is either denied or not responded to, a taxpayer will need to ensure an additional request is submitted annually in order to rely on the Good Faith Effort Exemption. There is no limit on the number of requests that may be submitted to a program, and there is no requirement to make subsequent requests to the same program (or to follow up on requests that are not responded to).

If a request to a registered apprenticeship program is partially denied, in order to satisfy the Good Faith Effort Exception requirements, the requesting party must accept the qualified apprentices offered (and may then consider the remaining portion as labor hours performed by qualified apprentices). An employer-sponsored registered apprenticeship program may not be used by such employer to satisfy the Good Faith Effort Exception requirements, unless the employer submits compliant requests to at least one registered apprenticeship program that it does not sponsor.

Finally, the Final Rule outlines in a separate recordkeeping section a list of records that may be sufficient to demonstrate compliance with PWA requirements. It notes that taxpayers may satisfy such recordkeeping requirements by collecting and physically retaining the records; providing them to a third-party vendor; or having each party physically retain relevant records (unredacted copies of which must be made available to the IRS upon request).

It confirms again that taxpayers are entitled to a rebuttable presumption of no intentional disregard if a taxpayer makes the appropriate correction and penalty payments before receiving notice of an examination from the IRS with respect to a claim for the increased credit. While continuing to emphasize that findings of “intentional disregard” of the PWA requirements will be made based on specific facts and circumstances, the Final Rule also provides 15 examples (for prevailing wage compliance) and 13 examples (for apprenticeship compliance) of facts and circumstances that may be considered in such a finding, including whether the failure was a pattern of conduct, whether the taxpayer took reasonable steps to monitor, review and correct compliance efforts, whether the taxpayer incorporated provisions in its agreements requiring compliance with the PWA requirements, and what documentation and records the taxpayer collected to ensure such compliance.

The Final Rule also establishes a 180-day limit for the taxpayer to pay correction and penalty payments following a final determination from the IRS that the taxpayer has failed to satisfy PWA requirements.

Overall, the Final Rule provides helpful clarity to renewable energy developers and contractors enacting and enforcing PWA requirements throughout the industry. However, leaves open industry-specific questions such as what scope of work constitutes “repair” rather than “maintenance,” particularly during operation of a facility. It also fails to address whether on-site commissioning work constitutes “construction, alteration or repair” sufficient to trigger obligations to comply with PWA requirements. These questions will remain subject to assessment based on specific facts and circumstances, and prudent industry developers and contractors will need to carefully consider and document how they approach compliance with PWA requirements consistent with prudent industry practices.

Monica Dozier and Jennifer Trulock are partners at Bradley Arant Boult Cummings LLP and regularly advise clients on labor and employment issues in the renewable energy industry.

From pv magazine 6/24

The United States has set a goal of achieving 100% clean energy by 2035. To do so, a vast amount of land needs to be used for solar energy production. The US National Renewable Energy Lab estimates that if the United States were to meet all of its electricity needs with solar alone, around 10 million acres, or 0.4% of the area of the country, would be needed.

Solar siting can run into local opposition, so public perceptions need to be addressed. That was the subject of “Perceptions of Large-Scale Solar Project Neighbors: Results from a National Survey,” a report conducted by the Energy Markets and Policy (EMP) department at the Berkeley National Laboratory, in collaboration with the University of Michigan and Michigan State University.

The impetus for the study is the tremendous buildout of large-scale solar (LSS) plants (greater than 1 MW) across the United States. According to the US Solar Photovoltaic Database, as of November 2023 there were 3,676 solar projects with capacities of more than 1 MW, for a total generation capacity of 54.9 GW. As of 2022, there were more than 10 million US homes within 4.8 km of LSS plants.

Understanding the perceptions and attitudes of people who live near these installations can help with future deployment, according to Joseph Rand, lead author of the study and an energy policy researcher in the EMP department at Lawrence Berkeley National Laboratory.

As no study had previously been done asking LSS site neighbors for input, the Berkeley group teamed up with the University of Michigan and Michigan State researchers to conduct a survey of residents who live within three miles of 380 unique LSS projects ranging in size from 1 MW to 252 MW in 39 states.

Rand noted that it is early in the analysis of survey results but the key takeaways at this point are that residents had more negative reactions to installations greater than 100 MW in scale. He said the planning process also plays an important role in perception, because if residents “thought the planning process went well, they were more positive overall.”

Part of the planning process is communication about a project. Rand said the biggest surprise in the survey results was that less than one-fifth of respondents actually knew about projects before construction.

A team from the University of Michigan sent out the questionnaire along with a map showing solar power plants in close proximity to survey recipients.

The survey asked several questions aimed at determining how LSS development impacted local tax revenue, supported local workers, or contributed to the local economy overall. On employment, only 18% of respondents thought an LSS project impacted local job opportunities, with 13% of respondents saying it increased employment opportunities and 5% that it decreased them. Almost half the respondents said there would be “no effect” on employment opportunities. Most respondents did not notice any short- or long-term economic impact, although the researchers found that these perceptions were tied to attitudes about projects overall. Likewise, most respondents did not believe that projects affected local inequities.

Researchers were interested in how LSS site neighbors can play a larger role in local development and the responses showed developers can do a better job of informing the public about plans so they can play a role in LSS projects. Questions asked whether respondents were aware of projects, whether developers offered opportunities for neighbors to participate in public meetings during the planning process, and to what extent they had participated.

While respondents did not prefer increased state-level decision-making in future LSS siting decisions, they did want more opportunities to participate in decision-making and liked the idea of having third-party advocates inform neighbors of the planning process and to intervene on their behalf.

In asking how LSS site developers might locate projects that were considerate of local land-use plans, as well as community needs and values, 42% of respondents said they would support additional LSS sites in their community – compared to 18% that would oppose it – but they preferred that projects be sited on disturbed locations such as landfills and former industrial sites, rather than in forests or on productive farmland.

Savvy developers and local officials can gain much from the in-depth report, Rand said. While attitudes in general were found to be more positive than negative, the survey found a significant amount of negativity around very large projects. This is a signal that, if building very large solar sites, “developers really want to listen to the public and do a thorough planning process so people are aware of the project,” Rand said. “If I were a developer, to help the public understand a project, it’s important that that information is provided from trusted sources.” Such sources are not energy developers or state policymakers, but university faculty and staff, or non-profit organizations.

The New York State Public Service Commission approved a new framework for New York to achieve 6 GW of energy storage by 2030, representing at least 20% of the peak electricity load of New York State.

The original Energy Storage Order was developed in 2018 and had a target of 3 GW of energy storage. However, New York set ambitious clean energy goals through the Climate Leadership and Community Protection Act, including generating 70% of the state’s electricity from renewable sources by 2030 and 100% zero emission electricity by 2040. The new order doubles the energy storage goals set in 2018, increasing the target to 6 GW by 2030.

The funding authorizes $814.6 million in total energy storage funding, which breaks down to $675 million for 1.5 GW of community and C&I energy storage incentives, $100 million for 200 MW of residential incentives, and $39.6 million for program administration.

“Expanding energy storage technology is a key component to building New York’s clean energy future and reaching our climate goals,” said Governor Hochul. “This new framework provides New York with the resources it needs to speed up our transition to a green economy, while ensuring the reliability and resilience of our grid.”

According to New York State Energy Research and Development Authority (NYSERDA), these future procurements, combined with the 1.3 GW of existing energy storage being procured or already under contract and getting closer to commercial operation, will allow New York to achieve its 6 GW goal by 2030. NYSERDA reports that as of April 1, 2024, New York has awarded about $200 million to support approximately 396 MW of operating energy storage in the state.

“Governor Hochul has long been a staunch supporter of energy storage development in New York State, and with her steadfast support, we have been able to develop this roadmap to guide New York away from fossil-burning power plants to a clean energy economy,” said Rory M. Christian, chair of the Public Service Commission.

The Roadmap includes:

• 3,000 MW of new bulk storage, enough to power approximately one million homes for up to four hours, to be procured through a new competitive Index Storage Credit mechanism;
• Use of at least 35% of program funding to support projects that deliver benefits to Disadvantaged Communities (DACs) and that target fossil fuel peaker plant emissions reductions, with program carve-outs for projects sited in the downstate region, given its high concentration of DACs and peaker plants;
• Requiring electric utilities to study the potential of high-value energy storage projects toward providing cost-effective transmission and distribution services not currently available through existing markets;
• Continued prioritization by existing programs on investing in R&D related to reliable long-duration energy storage technologies; and
• Requiring payment of prevailing wage for energy storage projects with a capacity of 1 MW and above.
• Fire safety requirements must be in NYSERDA Implementation Plans, reflecting recommendations from the Fire Safety Working Group.

“By setting clear and ambitious targets for energy storage deployment and creating robust incentive structures for both retail and residential projects, this order lays the foundation for a cleaner, more reliable energy grid. NYSEIA applauds the dedication and vision of these agencies, and we look forward to continuing our collaboration to achieve these critical goals for the benefit of all New Yorkers” New York Solar Energy Industries Association (NYSEIA) said.

The roadmap will support a buildout of storage deployments estimated to reduce projected future statewide electric system costs by nearly $2 billion, according to NYSERDA, in addition to further benefits in the form of improved public health because of reduced exposure to harmful fossil fuel pollutants.

“With more renewable generation than any other state on the east coast, deep duration storage is only going to become more critical to keeping the lights on as New York continues to work towards its decarbonization goals,” said Jordan Cole, chief commercial officer of Hydrostor. “New York has recognized that 8+ hour storage is needed to move the energy transition forward while maintaining the reliability of the grid, and we’re confident that other states will follow. We look forward to working with NYSERDA on its implementation plan.”

Next steps to be taken include the development of implementation plans by NYSERDA, which will include stakeholder input. The commission will then review and approve the plans before the incentives are made available.

Nextracker, a global provider of intelligent solar tracker and software solutions, has acquired Ojjo in an all-cash transaction for approximately $119 million.

Ojjo is a California-based renewable energy company specializing in unique truss systems that uses half the steel of a conventional foundation and a design that reportedly minimizes grading requirements in utility-scale projects.

The foundation company was founded by Jack West, who also founded Zep Solar. Zep was also known for its unique design in that it offered a rail-less way of installing solar on rooftops. Zep was acquired by SolarCity, which was later acquired by Tesla.

Ojjo’s truss is comprised of underground anchors, above ground legs and a truss cap. The Ojjo Earth Truss has more than 4 feet of reveal tolerance, regardless of Truss height, the company reports, which minimizes grading requirements. A hollow Screw Anchor is the heart of the Ojjo foundation technology, and it’s designed with a crimp collar welded to the top and a hollow tip at the end. Ojjo also has a Truss Driver machine that uses automation software for installations.

Today Ojjo is made up of industry veterans from Avantus, Vestas, SunPower, Recurrent Energy, and Canadian Solar as well as original members from the Zep days. Ojjo reports that, to date, it has delivered more than 2 GW of truss foundations and has 600 total patents issued and pending.

One of Ojjo’s notable projects is Gemini, a 690 MW standalone solar and battery storage project in Nevada on Bureau of Land Management land in the Mojave Desert. The company reports that the project’s owner, Primergy, and EPC, Kiewit Power, chose the Ojjo solution because it eliminated predrilling and reduced the need for grading.

Nextracker reports that for many years it has partnered with Ojjo on testing, evaluation and collaboration on joint customer solar projects. Nextracker sees the acquisition as a bonus for developers and EPC firms as Ojjo’s patented foundations portfolio paired with Nextracker systems provides an integrated solution for a variety of soil conditions.

“Their team brings geotechnical products and expertise in foundation systems that are especially well-suited to rocky sites, with control system intellectual property that is broadly applicable to a range of equipment,” Dan Shugar, Nextracker founder and CEO. “This acquisition furthers our successful global tracker foundation business with next-generation, differentiated technology.”

Nextracker reports that Ojjo technology paired with its NX Horizon integrated tracker system will advance Nextracker’s existing foundation capabilities. In addition, Ojjo technology will continue to be available to customers for use with other compatible solar trackers.

“I am proud of what the Ojjo team created. Nextracker is by far the best partner to drive this technology to its fullest potential in the utility-scale marketplace,” said Mike Miskovsky, outgoing Ojjo CEO, who will be providing transitional support to Nextracker into the next fiscal quarter.

The transaction closed on June 20, 2024, and is not expected to be material to fiscal 2025 results. The purchase price is subject to working capital and other customary purchase price adjustments.

Recurrent Energy, a subsidiary of Canadian Solar Inc. has secured $513 million in project financing for its Papago Storage project located in Maricopa County, Arizona.

The 1,200 MWh Papago Storage, which will be the largest energy storage project in Arizona, is expected to begin operations in the third quarter of 2024, with commercial operations slated for the second quarter of 2025. Once operational, the project is expected to dispatch enough power for approximately 244,000 homes for four hours every day.

The Papago battery energy storage systems (BESS) project will use e-Storage’s SolBank, a containerized, proprietary battery energy storage solution designed and manufactured for utility-scale applications. SolBank, which was announced at RE+ in Anaheim in 2022, uses high-cycle lithium-ferro-phosphate (LFP) batteries with a 2.8 MWh energy capacity.

Recurrent Energy, owner of the project, secured a 20-year tolling agreement with Arizona Public Service (APS) for the energy storage project, under which the utility pays for the right to charge and discharge the battery when it needs to.

MUFG and Nord/LB acted as coordinating lead arrangers for the Papago Storage project financing. The financing includes a $249 million construction and term loan, a $163 million tax equity bridge loan, and a $101 million letter of credit facility. Joint lead arrangers for the transaction included Bank of America, CoBank, DNB, Rabobank, Siemens Financial Services, and Zions.

“Today, we are thrilled to see nearly a decade of planning culminate in the financing of what will be the largest energy storage project in Arizona,” said Ismael Guerrero, CEO of Recurrent Energy. “We appreciate the continued support from our partners Nord/LB and MUFG in our shared mission to advance the clean energy transition.”

Last April Canadian Solar rebranded its wholly owned global energy subsidiary as Recurrent Energy. This segment develops both stand-alone solar and stand-alone battery storage projects, as well as hybrid solar-plus-storage projects. To date, Recurrent Energy has delivered more than 10 GWp of solar power projects and 3.3 GWh of energy storage projects, with a global project development pipeline of 26 GWp and 56 GWh for solar and energy storage respectively, the company reports. In North America, Recurrent Energy is developing a pipeline of 6.3 GWp of solar projects and 18.9 GWh of battery energy storage projects.

The U.S. Department of the Treasury and the Internal Revenue Service (IRS) released final rules on the Inflation Reduction Act’s (IRA) prevailing wage and registered apprenticeship requirements.

The IRA includes a myriad of incentives including the production tax credit, investment tax credit, energy community adder, and more. But in order to take advantage of these, solar developers must meet specific guidelines as far as pay, number of apprentices employed and ratio of workers who come from qualified apprenticeship programs. Treasury said in a statement that by following these rules, “taxpayers can claim an increased credit equal to five times the base incentive. This includes projects utilizing the investment and production tax credits that help finance utility-scale wind, solar, and battery storage projects, as well as for credits for carbon capture, utilization, and storage and clean hydrogen projects.”

The goal of the prevailing wage and registered apprenticeship (PWA) provisions in the IRA are to ensure that those working in the clean energy industry receive fair pay, and also to encourage apprenticeship programs that will build a skilled workforce.

The clean energy projects that resulted from the IRA have created more than 270,000 jobs, according to the Treasury Department, which said studies show that more than 1.5 million additional jobs will be created over the next decade. The Department of Labor released an interactive map that shows clean energy projects across the country that could be eligible for enhanced tax incentives if taxpayers satisfy the prevailing wage and registered apprenticeship provisions, as well as other applicable IRA requirements.

“President Biden’s Inflation Reduction Act has driven an investment boom while ensuring that workers building the clean energy economy benefit from good pay and new opportunities to get ahead,” said Secretary of the Treasury Janet L. Yellen. “Treasury’s final rules ensure we have skilled workers ready to take advantage of the jobs being created by these historic investments.”

The PWA requirements took effect in January 2023, after which time more than 300 public comments were received and considered, according to Treasury, in developing the final rules.

Details of the final rules include:

• Requiring that determinations of prevailing wage rates be made by DOL, consistent with the Davis-Bacon Act;
• Incentivizing practices that will encourage contemporaneous compliance;
• Implementing strong recordkeeping requirements;
• Guaranteeing that taxpayers with projects covered by qualifying project labor agreements do not need to pay penalties; and
• Clarifying apprenticeship requirements such as clearly defining what constitutes as a request for qualified apprentices, what constitutes as a response, and when the good faith effort exception applies.

Departments of Treasury and Labor encourage developers to consider project labor agreements (PLA), which reportedly can help taxpayers comply with the PWA requirements. To better understand PLAs, read the blog “Project Labor Agreements: A Best Practice for Clean Energy Projects Seeking to Meet IRA Wage and Apprenticeship Standards” by Deputy Secretary of the Treasury Wally Adeyemo and Acting Secretary of Labor Julie Su.

The IRS said it plans to “dedicate significant resources to promoting and enforcing compliance with the final clean energy rules”. One of those resources will be a new PWA fact sheet that provides a summary of the requirements and as well as how to alert the IRS of suspected tax violations related to the PWA increase.

Furthermore, the Labor Department and the IRS will sign a Memorandum of Understanding (MOU) by the end of the year that is intended to facilitate public outreach, education and development of training content for IRS examination personnel who will be tasked with ensuring PWA compliance.

“One of the greatest promises of the Inflation Reduction Act is that it will create and maintain good-paying, union jobs in the clean economy, while building inclusive pathways into the highest quality training for lifelong careers in construction,” said Jason Walsh, executive director of the BlueGreen Alliance. “With this rule we are seeing how that promise will come to fruition. We are excited to see this progress and look forward to continuing to work with the administration to ensure that the Inflation Reduction Act delivers for workers and communities across the country.”

An unpublished rule is available here. On June 25, 2024, the IRS will publish the rules here.

Nextracker announced its second steel torque tube factory with Unimacts, a specialist in industrial manufacturing and supply chain solutions.

Like the first Nextracker/Unimacts partnership, this factory will be located in Sloan, Nevada, near Las Vegas. This factory will also will be owned by Unimacts, with all steel components produced exclusively for Nextracker, bringing the tracker specialist’s annual domestic solar tracker capacity to over 30 GW.

The steel torque tubes produced in the new 160,000-square-foot facility will be used to hold and rotate solar panels in large-scale solar power plants. The two factories will produce enough torque tubes to support more than 2 GW of new solar power each year, equivalent to the energy used by 400,000 U.S. homes.

With this new factory, Nextracker has now opened or expanded over 20 U.S. manufacturing facilities since 2021, including new or expanded dedicated production lines across the U.S. The tracker specialist locates plants near its target markets with the goal of reducing time and cost for its customers The Unimacts plant will produce steel components for Nextracker’s solar power generation plants primarily in Nevada and southwestern states. 

Since passage of the Inflation Reduction Act in 2022, solar developers are focusing on U.S. made content for solar power plants in order to qualify for the domestic content bonus credit. To qualify all steel and iron used in projects must be completely manufactured in the U.S., with the exception of certain metallurgical processes related to steel additives. This primarily applies to construction materials used for racking, trackers and foundation components anchoring solar panels.

“American manufacturing has quickly become the heartbeat of the clean energy revolution,” ​​said Dan Shugar, founder and CEO of Nextracker. “There is a trifecta of perfect conditions for this manufacturing renaissance: a terrific workforce, a great localized clean steel industry, and strong demand for renewable energy. Over the last three years, Nextracker has operationalized over 20 factories, catalyzing thousands of jobs. This is what growth and scaling look like.”

In addition to enabling solar developers to reap further tax credits, domestically produced materials is an economic driver, bringing good jobs to local communities. American Clean Power estimates that the IRA will help create 550,000 new clean energy jobs – more than doubling the current clean energy workforce. As a result, the clean power industry will support a direct workforce of nearly one million Americans by 2030.

 “Today’s announcement is a great example of clean power driving an American manufacturing renaissance in Nevada and across the United States. Creating and expanding supply chains here at home strengthens America’s energy security, creates good-paying jobs and boosts the economy. These new manufacturing facilities also exemplify the key role of American technology in creating a clean, reliable, and affordable grid,” said Jason Grumet, CEO of American Clean Power.

In addition to making torque tubes for the solar industry, Unimacts solar piles and drives for trackers as well as wind turbine components and other industrial products.

“The federal incentives allow us to confidently invest in U.S. manufacturing, provide manufacturing jobs in Nevada and growth in the local economy,” said Alan Hayes, CEO of Unimacts. “Having inaugurated our first Nevada site for solar component production in Las Vegas just nine months ago, we’re pleased to be once again partnering with the Nextracker team, expanding clean energy manufacturing capacity and contributing to local jobs.”

Princeton NuEnergy (PNE), a New Jersey-based specialist in lithium-ion battery direct recycling, announced the close a Series A funding round with a strategic investment from Samsung Venture Investment Corporation.

Founded out of Princeton University in 2019, PNE developed a patented direct recycling technology for lithium-ion batteries. The low-temperature plasma-assisted separation process, trademarked as LPAS, produces battery-grade cathode and anode materials suitable for direct reintroduction into cell manufacturing. The company reports that this recycling is done at half the cost and is 70% less energy intensive.

PNE is now commercializing its lithium-ion battery recycling process that the company reports recovers up to 95% of materials found in all lithium-ion battery chemistries.

Recovering lithium and other critical battery materials is important as the U.S. ramps up electric vehicle produciton. While the U.S. is making strides toward manufacturing batteries, it is behind in the race for raw materials as China reportedly holds the majority of the world’s lithium refining capacity.

To advance lithium battery recycling, PNE has received over $55 million in grants, strategic and venture funding including investments from Honda Motor Co. Ltd., LKQ Corporation, Samsung Venture, Shell Venture, Traxys Group, Wistron Corporation, and the U.S. Department of Energy.

Investor demand for this 50% oversubscribed round brought PNE’s Series A total to $30 million. Samsung Venture and Helium-3 join the round’s previous investors. The funds will support construction of PNE’s first standalone, full-scale direct battery recycling advanced manufacturing facility.

“The incredible interest in our Series A round, capped off by a strategic investment from Samsung Venture Investment Corporation and Helium-3 Ventures, speaks to the importance of supporting a circular economy for lithium battery manufacturing here in the U.S.,” said Dr. Chao Yan, PNE’s co-founder and CEO. “This funding enables us to implement and demonstrate our capabilities at commercial scale, helping America meet the growing demand for high-performance batteries while also creating high-quality clean energy jobs.”

PNE was named to Time Magazine’s “America’s Top Greentech Companies 2024”

From pv magazine Global

With signs of a possible switch to La Niña conditions, solar asset and grid operators will be looking to understand the impact this change could have on US solar production. Based on currently available data, the Atlantic hurricane season is expected to intensify to look more like a La Niña year, leading to more frequent hurricanes. La Niña years typically result in below-average solar irradiance in the Gulf of Mexico, while increasing solar irradiance along the Atlantic Coast of the USA, according to analysis using the Solcast API.

In La Niña years, the Gulf of Mexico historically sees irradiance levels up to 10% below the long-term average due to increased storm activity. La Niña, characterized by cooler sea surface temperatures in the equatorial Pacific, impacts the Atlantic hurricane season on the
other side of the continental USA by shifting weather patterns. The cooler temperatures in the Pacific shift the jet stream further north, reducing vertical wind shear in the Atlantic. Normally, higher wind shear suppresses hurricane formation by disrupting their vertical
structure. However, with reduced wind shear, more hurricanes can form and develop more intensely. These conditions lead to more hurricanes, convection and cloudiness in the Gulf of Mexico, resulting in decreased solar irradiance. Whether or not we actually see a shift to La Niña in 2024, these patterns are already forming, indicating a likely reduction in summer irradiance for the Gulf Coast.

In contrast, the Atlantic coast of the USA has historically seen up to 5-10% above-average irradiance during summer months in previous La Niña events. Despite the higher number of hurricanes that can transition into mid-latitude cyclonic storms along the East Coast, the
periods between these storms experience relative stability. In between these large storms, the reduced cloud convection and rainfall lead to longer periods of clear skies. These calm periods outweigh the impacts of increased hurricane activity, leading to higher average overall solar irradiance along the East Coast for summers impacted by this weather pattern.

Using this climate analysis, it is possible to apply these possible weather patterns to the current distribution of solar generation across the US. Analysis using the Solcast API shows that a typical La Nina summer would mean 2.7% more rooftop solar generation for the New York ISO (NYISO), and 2.1% for New England ISO (NEISO). In contrast, the large number of utility scale assets in the Electric Reliability Council of Texas (ERCOT) sees lower production in a typical La Niña summer, down by -1.6%.+

Grid Aggregation models are built using available production information, and applying Solcast’s irradiance data to those models. Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 350 companies managing over 300 GW of solar assets globally.

An integrated microgrid infrastructure project in Rockville, Maryland will be the largest renewable energy-powered bus depot in the nation and the first on the East Coast to produce green hydrogen on-site, according to developer AlphaStruxure.

The microgrid will be constructed at Montgomery County’s David F. Bone Equipment Maintenance & Transit Operation Center (EMTOC), which is the County’s fifth largest energy user. With the depot eventually powering 200 zero-emissions buses, it will support the County’s climate goal of reaching 100% reduction in carbon emissions by 2035.

The 7 MW microgrid will consist of 5 MW of Sunpower solar modules, a 2 MW/7.35 MWh Schneider Electric battery energy storage system, and 4.5 MW of charging capacity. It will also use SMA inverters and feature EV chargers from Heliox and PowerCharge.

The integrated microgrid, which is expected to be operational in the fall of 2025, will be interconnected to the utility, but engineered to operate indefinitely in island mode, according to AlphaStruxure. Once built, it will be able to power not just electrolysis but the depot’s five existing buildings and battery electric bus charging. As a self-sufficient microgrid, it will do so with or without utility electricity, and can export up to 2 MW back to the grid, the company reports.

Unique to this microgrid is the 1 MW hydrogen electrolyzer that will be powered by the on-site solar energy and used to support fuel cell electric buses and enhance the county’s Bus Rapid Transit (BRT) network.

The County’s 2024 fleet transition plan calls for replacing 100% of its nearly 400 fossil-fuel-powered buses with a mix of battery-electric and hydrogen fuel-cell electric buses, while also scaling the entire fleet to about 600 buses by 2035. With this microgrid, the County is planning in advance how to power these zero-emissions vehicles by strategically coupling procurement of both the vehicles and the infrastructure.

“What you don’t want is to get these vehicles on site and have no way to charge them. It’s a balance between infrastructure done and the fleets in at the same time,” said Michael Yambrach of the County’s office of energy and sustainability.

Montgomery County created a public-private partnership with AlphaStruxure to design, build, finance, own, and operate the microgrid. The Counted used AlphaStruxure’s Energy as a Service agreement under which AlphaStruxure designs, builds, owns and operates the infrastructure, and taps an investment firm for financing.

Dean Solon, founder, CEO and president of Create Energy and Shoals Technologies Group, together with Hamlet Tunyan, CEO of RECOM Technologies, announced the launch of ReCreate. This new venture will establish a state-of-the-art manufacturing facility in Tennessee with planned production of up to 5 GW of modules and 5 GW of cells for the North American and European markets.

The Inflation Reduction Act (IRA) of 2022 has stimulated solar manufacturing in the U.S. with production tax credits for manufacturers and investment tax credits for project developers using domestic content. Wood Mackenzie estimates 144 GW of announced module manufacturing capacity, 71 GW of cell manufacturing capacity and 61 GW of wafer manufacturing capacity by 2027. Compare this to the 26 GW of module capacity we have today, along with little or no wafer or cell production, and the 5 GW of both cells and modules anticipated from ReCreate will significantly bolster supply.

The facility is located at Create Energy’s manufacturing facility in Portland, Tennessee. Create is a U.S.-based renewable energy company founded by Solon that produces products ranging from transformers, switchgear, PV, BESS, and EV solutions as well as full turnkey EPC services. Solon is renowned for his creative leadership in the renewable energy industry, bringing over 30 years of experience driving engineering, innovation and manufacturing growth in both the U.S. and global markets.

“We’re excited to ignite the rocket engines on this new venture and deliver high-quality, American-made solar solutions,” said Solon. “At Create Energy, our mission is to ReCreate the renewables market and offer comprehensive solutions for solar, BESS, and eMobility projects. ReCreate will set the standard for the solar module and cell markets.”

Tunyan, well known in the European renewables sector, has decades of expertise in clean-tech manufacturing, project investments and development. RECOM Technologies is a module, cell, inverter, hybrid storage systems, batteries, and electrical vehicle (EV) charger manufacturer. The  company integrates R&D, manufacturing and distribution, with an annual production capacity exceeding 3.2 GW and sales in over 110 countries.

Speaking on the partnership with Solon, Tunyan said, “This project represents a significant advancement in our commitment to renewable energy and innovation. By manufacturing in the USA, we are supporting the local economy and setting new industry standards. Partnering with Dean Solon, whose expertise and vision are unparalleled, enhances our capacity to deliver exceptional solar solutions and drive meaningful change in the energy sector.”

Swift Solar announced the close of its $27 million Series A financing round, which follows on the heels of a $7 million award from the Department of Energy under the Advancing U.S. Thin-Film Solar Photovoltaics funding program.

The company, founded in 2017 is a spinout of MIT, Stanford University and the National Renewable Energy Laboratory (NREL), and specializes in perovskite tandem photovoltaics. The new technology combines metal halide perovskites with silicon or other perovskites to make tandem cells that have higher efficiency than traditional solar cells.

The $27 million funding round was co-led by Eni Next and Fontinalis Partners. Also joining the round are new and existing investors including Stanford University, Good Growth Capital, BlueScopeX, HL Ventures, Toba Capital, Sid Sijbrandij, James Fickel, Adam Winkel, Fred Ehrsam, Jonathan Lin, and Climate Capital.

The $7 million DOE funding is part of a $71 million investment, including $16 million from the Bipartisan Infrastructure Law, which supports research, development and demonstration projects in order to help grow the domestic solar supply chain. Swift Solar was one of four awardees that are working on tandem PV devices that pair established PV technologies like silicon and copper indium gallium diselenide (CIGS) with perovskites.

In total, Swift Solar has raised $44 million to scale its technology as it prepares to break ground on its first manufacturing facility.

“Solar is the future of energy—not just clean energy,” said Joel Jean, co-founder and CEO of Swift Solar. “Our advanced perovskite solar cells can outperform anything currently available on the market.”

A novel vapor deposition technology may help it to accelerate the manufacture of its tandem solution. The new method is a non-batch process that solves two problems associated with the use of established vapor processing in perovskite material manufacturing – the slow speed of deposition and the non-continuous nature of batch processing.

“Our deposition approach allows for the continuous deposition of a fully absorbing perovskite material within less than five minutes,” corresponding author Tobias Abzieher from Swift Solar, a U.S.-based perovskite PV startup, told pv magazine. “Solar cells prepared with these materials also outperform previously realized efficiencies of vapor processed inorganic perovskite solar cells significantly.”

In its announcement, Swift Solar noted that perovskite solar cell production uses less material and less energy, which should drive down manufacturing costs and carbon pollution, potentially decreasing the cost of solar by up to 30%. “The perovskite supply chain could be based entirely in the United States and aligned countries, creating a major opportunity to expand domestic manufacturing,” according to Swift.

Swift Solar’s initial products will be designed for integration in high-performance solar-powered products such as on car rooftops or space-based satellites, and the company says it will also serve traditional solar customers.

Swift Solar was recently named one of TIME’s Top GreenTech Companies in America. In April, The Solar Energy Manufacturers for America (SEMA) Coalition announced the Swift Solar was a new member.

This article was amended to remove mention of company developing rooftop product.

Hawaii has the highest average electricity price of any state at 43.93 cents per kWh, nearly triple the U.S. average, yet this project will cut that cost for many residents. Developer AES Hawaii projects that the Kūihelani Solar-plus-Storage facility will generate enough electricity for 15% of Maui’s needs at just 8 cents per kWh.

“Maui residents will soon be seeing the benefit of Kuihelani in their electric bills and the reassurance of knowing they will have reliable electrical power for their homes and businesses,” said former Maui Mayor Victorino.

Islands that are not covering their energy needs with renewables are beholden to imported fossil fuels. The energy generated by this facility will offset the need to import an estimated 2 million barrels of oil.

Situated on 450 acres in central Maui, between Kūihelani Highway and Maui Veterans Highway, the project supports the state’s goal of 100% renewable energy and decarbonization targets by 2045. AES Hawaii broke ground for construction less than two years ago, and as with most large-scale solar projects, the company sought input from the community prior to construction. As a result, AES Hawaii modified its plans.

“We reduced the size of the project site by 35%, minimizing the project’s environmental footprint, while maximizing the usage of the available land in a responsible manner,” said Sandra Larsen, Hawaii market business leader for AES.

Hawaiian Electric is the offtaker of the electricity, having signed a 25-year power purchase agreement with AES Hawaii.

Nearly 300 jobs were supported during construction of Kūihelani Solar-plus-Storage and and generated approximately $68 million for Maui’s economy, according to AES Hawaii. In addition, project area is also designed for agricultural use.

AES Hawaii more than 300 MW of renewable energy in construction or operational, enough to power 120,000 homes statewide. The company estimates that this is the equivalent of eliminating more than 175,000 metric tons of carbon emissions and more than 15 million barrels of oil consumption over the course of project lifecycles.

Giraffe Financial announces the launch of a service that aims to make Inflation Reduction Act (IRA) tax credits accessible to underserved small- and medium-sized businesses and tax-exempt organizations such as local governments, schools, and nonprofits.

The IRA represents over $1 trillion in tax credits to accelerate the adoption of clean energy technologies in the U.S.; however, the complexities are as vast as the opportunities. With transferable tax credits value projected to grow to as much as $100 billion by 2032, according to Giraffe, smaller companies may be challenged to tap into those benefits.

In addition, direct pay issues were finalized in April, enabling non-profits such as schools and churches reap incentives for clean energy investments. Giraff intends to help non-profits navigate the process of accessing these credits.

“We built Giraffe to address the paradox that many of the organizations the IRA is intended to support are the least equipped to take advantage of it; we’re bringing IRA tax credits within reach for a broader audience,” said Giraffe co-founder and CEO Jason Prince. “We’re making tax credits far more accessible for entities that don’t have the wherewithal to become tax experts themselves.”

Giraffe is an AI-powered, end-to-end online tax preparation solution that intends to help users understand their likely eligibility and estimate the value of their tax credit. The program will also help companies and non-profits follow all rules in order to stay in compliance. And it will help potential direct-pay recipients to aggregate, insure and sell credits that they’ve obtained.

Help is available for renewable energy and energy storage investments as well as EV and EV charging purchases.

Giraffe is currently working with a partner in the private sector, Cummins, which supports dealers that are electrifying bus fleets. As each dealer has to navigate grant, rebate and tax incentives for their own business, Giraffe is providing those dealers with guidance and expertise so they can take full advantage of all opportunities.

Other customers include Butte Valley Unified School District, Weed Union Elementary, EVC Holdings, FuSE, Bird Bus, and EV charging solution providers like SWTCH, Skycharger, and XCharge.

“When we were first introduced to Giraffe, we were excited to hear that they could helpus secure tax credits that would effectively reduce our out-of-pocket costs to $0 as we moved to purchase electric school buses and the associated charging infrastructure,”

“There are many benefits to having electric vehicle charging stations at a business or other property, yet implementation can be costly and complex,” said Dan Coyne, founder and partner, EVC Holdings. “Giraffe is making the important IRS tax credit component significantly easier for its customers.”

Giraffe was spun out of the Momentum X climate finance venture studio, and it is backed by its two parent companies, Momentum and Skyview Ventures. The $1.5 million pre-seed venture capital funding round was led by Skyview Ventures with participation from angel investors representing leading EV OEM, EV charging, AI, carbon, and environmental commodity organizations.

Anza, a solar and energy storage supply chain platform, Q2 Pricing Insights Report aggregates data from 95% of the U.S. solar module supply year to date to provide pricing changes that result from market forces and regulatory changes. With the Q2 report on the U.S. solar module market shows the first price increase in years. Anza attributes this to the latest AD/CVD petition and reinstatement of bifacial import duties.

“After years of record low pricing, we’re seeing the market start to rebound as domestic manufacturers have less pricing pressure from foreign producers that are subject to tariffs,” said Mike Hall, CEO of Anza. “We’re expecting to see this upward price trend continue from here, making it critical for new projects to consider current pricing and potential tariff impacts when sourcing materials.”

Anza’s Q2 report looks at module pricing trends from March to May 2024 and finds that while there was a downward pricing trend in March and April, prices bounced up in May.

Looking at the period from February to May 2024, the median module price dropped from 27.9 cents per watt to 25 cents per watt, marking an 11% decrease. The most substantial change occurred between February and March 2024, when prices fell by 2.5 cents or 8.6%.

The report noted that while TOPCon prices remained steady from January to February, they dropped right alongside PERC through April. Anza attributes advancements in TOPCon manufacturing and increased competition from foreign suppliers as driving these price declines.

Then in May, following the AD/CVD petition, prices began to rise again at about 2%. Anza report authors acknowledge that while this is only a small increase, it is significant because it is the first time since late 2022 that prices have increased.

The report drills trend data down to a weekly basis, which that the median price dropped to 24 cents per watt the week of April 22, hitting what Anza suggests is the pricing floor. Since that time prices have climbed back and held at 25 cents per watt through the end of May; an increase of 4%. Anza anticipates that this upward trend due to the looming AD/CVD petition.

The report contends that “new solar module tariffs and regulatory changes have materially affected pricing, though we are only starting to see early signs of those impacts”.

The tariffs referred to include the new bifacial tariff as well as the looming fallout from an AD/CVD petition officially filed on April 24, 2024, against Cambodia, Malaysia, Thailand, and Vietnam. The report notes that while preliminary antidumping determinations for this case are not expected until Q4 of this year, additional duties could be applied retroactively as early as May or June 2024.

AD/CVD laws assess tariffs on goods that are found to be dodging import duties by dumping products in other countries before shipping them to the U.S. In the previous AD/CVD proceeding, four Southeastern Asian countries, Vietnam, Cambodia, Thailand and Malaysia, which were responsible for roughly 80% of the U.S. supply of solar components, were alleged as potentially harboring dumped products from China.

The recent AD/CVD petition filed by the American Alliance for Solar Manufacturing Trade Committee, which includes First Solar, Qcells, Meyer Burger, REC Silicon, and others, claims that the U.S. “manufacturing renaissance” is threatened by heavily subsidized Chinese cells and modules.

Anza’s quarterly Pricing Insights Report looks at the impact of both government incentive programs, such as the IRA, and AD/CVD tariffs—in addition to the recently reinstated tariffs on bifacial solar modules, which generate electricity on both sides of the panel. Bifacial solar modules were previously exempt from tariffs, and the removal of the exemption reinstates a 15% tariff.

The report also compares Tier 1 module pricing to that of Non-Tier 1, and finds that the gap between the two has closed in the near term. The report finds that Tier 1 module prices dropped from 29 cents per watt to 25 cents per watt, marking a 14.8% decrease. Meanwhile, Non-Tier 1 module prices fell from 25 cents to 24 cents per watt, a 4.1% reduction.

In 2023 Anza was spun out of Borrego Solar after Borrego developed the solar and battery storage online marketplace and optimization solution. The proprietary software that drives the digital marketplace identifies the most optimized solar module and storage components based on customer-provided project details.

The Catholic University of America, located in Washington D.C. was one of the first universities to sign on to the Laudato Si Action Platform, a global initiative to increase the Catholic church’s ecological practices. Not only has the University installed solar so that it can generate its own clean energy, but it has made sustainability part of its curriculum as well as part of its five-year plan.

The 7.5 MW solar project uses ZNshine solar modules, Chint Power Systems inverters and Solar FlexRack racking. The ground-mount installation is located on a 40-acre parcel, previously planned to be a parking lot, on the west campus of the University.

“This West Campus solar farm project is not just a renewable energy venture; it’s a testament to The Catholic University of America’s dedication to creating a sustainable future for our nation and world,” said President Peter Kilpatrick, Catholic University. “As we illuminate our campus with clean energy, we also enlighten minds through education and invite the community to join us on this transformative journey toward a greener and more sustainable world.”

Trees that once stood on the parcel were salvaged by the District of Columbia’s Urban Forestry Division and milled into lumber or made into benches to be donated to school and non-profits. Once the land was cleared for the solar area, the area was planted with pollinators and beekeepers will tend hives at the site.

All of this makes for an outdoor classroom for the Introduction to Energy and Energy Systems course as well as other sustainability courses taught at the University.

The solar array was developed in collaboration with Standard Solar, who will own, operate and maintain the system. The array will save an estimated 7.115 metric tons of carbon emissions annually and contribute to the city’s goal of achieving 100% renewable energy by 2032 and carbon neutrality by 2050.

The array will also provide clean energy savings to over 1,200 subscribers within the community, benefiting District residents. The 20-year projected savings to district subscribers is estimated at $3.5 million.

“Undertaking a project of this magnitude in an urban setting presents its challenges, but the potential rewards for the region are immense,” said Scott Wiater, president and CEO, Standard Solar. “The West Campus Solar Array will power the university sustainably and benefit the local community. It’s a true win-win scenario for all involved.”

The recent announcement of the $7 billion Solar for All grants on Earth Day, April 22, 2024, heralds a significant milestone in the United States’ clean energy journey. With 60 awardees committed to delivering $350 million in annual savings to low-to-moderate-income (LMI) households, this initiative marks a pivotal moment for multifamily housing, historically underserved in the landscape of clean energy transitions.

Traditionally, multifamily housing has faced barriers in accessing solar energy initiatives. The sector’s dynamics, with multiple tenants and landlords, create what is known as the “split incentive” problem. Landlords often hesitate to invest in solar systems when tenants are the direct beneficiaries, leading to a gap in low-to-moderate-income access to solar energy.

However, recent developments present avenues for change. Initiatives like Justice 40 underscore the federal government’s commitment to directing resources to LMI households. Moreover, the Biden-Harris Administration’s emphasis on Solar for All signifies a fundamental shift towards inclusive clean energy policies.

One of the key advantages of multifamily housing lies in its scalability. Portfolio-wide implementation allows for the efficient deployment of solar projects across numerous units, maximizing impact. Additionally, the national nature of real estate ownership facilitates state-by-state fund deployments, ensuring broad accessibility.

Innovations such as SolShare offer promising solutions for on-site solar generation and consumption, directly benefiting apartment renters. These technologies align with a vision where solar energy becomes as integral to apartment amenities as air conditioning or in-unit laundry.

Policy measures, including tax credits and solar mandates, provide further impetus for multifamily solar adoption. California’s Title 24 mandate, for instance, requires newly constructed multifamily buildings to integrate solar panels, signaling a proactive approach to address the split incentive challenge.

Looking ahead, initiatives like Solar for All promise a future where multifamily housing is at the forefront of the clean energy transition. By bridging the gap between landlords and tenants, these programs not only reduce energy costs but also contribute to environmental justice and climate resilience.

The $7 billion Solar for All grants represent more than just a financial investment; they symbolize a commitment to equitable and sustainable energy solutions. As multifamily housing emerges as a key player in the solar revolution, it is poised to not only benefit from but also drive positive change in the clean energy landscape.

Mel Bergsneider is executive account manager at Allume Energy, responsible for business development in the U.S. market. As the first U.S.-based employee at Allume, Mel leads the Australian startup’s expansion across its target markets in the U.S. Mel works closely with affordable housing providers, solar installers, and real estate developers to provide solar energy benefits to tenants.

Community solar makes solar accessible to those who live in multifamily housing and don’t own their rooftops, can’t afford the upfront cost of solar or whose roofs are not oriented favorably for solar. A recent study by researchers at Lawrence Berkeley National Labs (LBNL) and published in Nature Energy, shows that community solar extends clean energy to communities that would have otherwise struggled to adopt rooftop solar.

“Their findings are compelling: community solar subscribers are 6x more likely to live in multifamily housing and 4x more likely to rent. This reaffirms what we have known to be true for years — community solar is one of the best ways to increase equity in our energy system,” said Molly Knoll, vice president of policy for the Coalition for Community Solar Access (CCSA).

Wood Mackenzie found that the share of community solar serving low-to-moderate income (LMI) subscribers grew from 2% to 10% in just one year, with costs decreasing 30% over the same period. In a report on community solar, Wood Mackenzie expects 7.6 GWdc of new community solar will come online in existing state markets between 2024 and 2028, and the national total of community solar installations are expected to pass 10 GW of cumulative capacity in 2026.

The Wood Mackenzie report noted that residential customers are representing an increasingly larger share of community solar subscriptions, suggesting a shift in focus for developers and providers. Low- and middle-income (LMI) customers rose from 2% of the customer base to 10% from 2022 to 2023, with costs to subscribe these customers declining 30% year-over-year.

Knoll pointed out that the Wood Mackenzie findings along with the LBNL findings, shows that policy that supports community solar adoption by LMI customers cannot only increase solar adoption but can also decrease overall costs.

For the first time, the researchers combine household-level data from Berkeley Lab’s Tracking the Sun rooftop solar adopter data set with data compiled under NREL’s Sharing the Sun community solar research, as well as additional community solar adopter data collected for the study. To determine how well community solar is serving the needs of those who are underserved by the rooftop solar market, the study looked at the demographic characteristics of the two adopter groups.

Based on a sample of 11 states, the LBNL study found that community solar adopters in 2023 were about 6.1 times more likely to live in multifamily buildings than rooftop solar adopters, 4.4 times more likely to rent, and earned 23% less annual income. Based on this, the researchers conclude that community solar has effectively expanded solar access to multifamily housing occupants, renters and low-income households.

The researchers also looked at what drives community solar participation: business models or policy. The business model removes barriers to adoption by allowing households to adopt solar without owning a home or having exclusive access to a rooftop. This is especially appealing to those who live in multifamily buildings and/or who are renters.

On the other hand, the researchers found that policy has helped to provide targeted support to help low-income households adopt community solar.

The conclusion was that business models and policy are equal in influencing community solar.

According to CCSA’s Knoll, this equitable access will increase substantially as more state policies include requirements that projects serve LMI customers. She noted that the $7 billion infusion from the EPA’s Solar for All competition will further speed LMI adoption.

“This study is important confirmation of one of the values community solar can bring to the electric grid and the tireless work our broad and diverse coalitions are doing to bring community solar to every state in the country,” said Knoll.

The authors of the Berkeley Lab study will host a free webinar on June 18^th at 11 a.m. PT/2 p.m. ET.

The Inflation Reduction Act of 2022 (IRA) makes available several new financial incentives to encourage the installation of clean energy projects in economically stressed locations. One such incentive is a bonus federal tax credit for projects built on brownfield sites. The brownfield credit is available for wind, solar, geothermal, and other renewable power projects, as well as energy storage facilities, green hydrogen projects, and biogas manufacturing plants.

The brownfield credit is significant. Project owners receive a 10% adder on top of either a Section 48 investment tax credit (ITC) or a Section 45 production tax credit (PTC). A project qualifying for the base 30% ITC would earn an additional 10% ITC, for a total 40% ITC tax credit, while a project receiving the base PTC would earn an additional 10% increment on top of the PTC.  Thus, a project qualifying for a PTC of $27.50/MWh would receive an additional $2.75/MWh.

A project developer that wants to qualify for the brownfield credit should be careful not to present a case that also exposes it to potential cleanup liability or environmental remedial actions, thereby undermining the economic value of the tax credit. The IRS has published guidelines that are helpful to understanding how to walk this hazardous line to sidestep potential liability and still qualify for the brownfield credit. Notice-23-45.pdf

What qualifies as a brownfield site?

A brownfield site is one of three categories eligible for a new “energy community” bonus tax credit.  The other two categories are:

1. Areas that had significant employment related to oil, gas, or coal activities;
2. Census tracts or adjoining tracts in which a coal mine closed or a coal-fired electric power plant was retired after December 31, 2009.

The energy community tax credits were created to encourage developers to build clean energy projects at sites that are disproportionately found in historically economically disadvantaged areas, and to repurpose environmentally distressed properties while providing other economic benefits to the community.

For purposes of receiving the tax credit, the IRS defines a “brownfield site” differently from the definition used by the Environmental Protection Agency (EPA) for Superfund liability and federal brownfield cleanup purposes.

The IRS definition of brownfield site is found in Section 39(A) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, or CERCLA,  42 U.S.C. § 9601(39)(A).  The IRS defines a brownfield site as:

Real property, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant (as defined under 42 U.S.C. § 9601) and certain mine-scarred land (as defined in 42 U.S.C. § 9601(39)(D)(ii)(III)). A brownfield site does not include the categories of property described in 42 U.S.C. § 9601(39)(B).  Notice-23-45.pdf.

The Section 39(B) exclusion generally covers Superfund sites and other contaminated sites that are currently the subject of a court or administrative cleanup order, consent decree, or closure or removal action under designated federal laws.

Unlike the EPA cleanup program, the brownfield definition under the IRA does not include contamination from Controlled Substances (i.e., chlorofluorocarbons and other ozone-depleting substances) or petroleum products.

The EPA, however, recently expanded its definition of hazardous substances under CERCLA to include polyfluoroalkyl substances, otherwise called “PFAS.” PFAS are a group of chemicals found in a wide variety of consumer products, commonly referred to as “forever chemicals” due to their persistence in the environment.

The inclusion of PFAS in the brownfield definition significantly expands the number of potential sites that could be eligible for the brownfield credit. By the same token, it raises the risk that developers qualifying for the brownfield credit due to the presence of PFAS could end up becoming potentially responsible parties in a cleanup obligation under CERCLA. The EPA has carved out exceptions to incurring such liability. The prudent approach, however, is to carefully thread the needle to avoid opening up a project to this cleanup obligation in the first place.

Applying the safe harbor rules

The IRS definition of a brownfield site has three parts. The taxpayer must show:

1. The presence or potential presence of a hazardous substance, pollutant, or contaminant on the site.
2. That the presence or potential presence “complicates” the site’s reuse or redevelopment.
3. That the site does not fall within the excluded category of properties in CERCLA Section 39(B), i.e., sites designated as Superfund sites or that are the subject of a court or administrative cleanup order, consent decree, closure, or removal action.

To simplify the process of qualifying for the brownfield credit, the IRS has established three “safe harbor” categories that it will consider as brownfield sites if a project satisfies any one of the categories and the site does not fall within the Section 39(B) exclusions:

1. The site was previously assessed through federal, state, territory, or federally recognized Indian tribal brownfield resources as meeting the definition of a brownfield site under 42 U.S.C. §9601(39)(A). Examples of these sites can be found in the category of Brownfields Properties on the EPA’s Cleanups in My Community website or on similar websites maintained by states, territories, or for federally recognized Indian tribes.
2. An ASTM E1903 Phase II Environmental Site Assessment (Phase II ESA) is completed for the site using the most currently applicable ASTM standards that confirms the presence on the site of a hazardous substance, pollutant or contaminant as defined under CERCLA.
3. If the project has a nameplate capacity no greater than 5MW (AC), an ASTM E1527 Phase I Environmental Site Assessment (Phase I ESA) has been completed for the site using the most currently applicable ASTM standards, and the Phase I ESA identifies the presence or potential presence of a hazardous substance, pollutant or contaminant as defined under CERCLA.[3]

How must a contaminant “complicate” use of a site?

The IRS safe harbor guidelines provide a straightforward way to qualify for the brownfield credit. Notably, the guidelines do not explicitly require a showing that the second prong of the statutory brownfield definition is satisfied, i.e., that the contaminant “complicates” reuse or redevelopment of the site.

The IRS seems to suggest that if one of the safe harbor conditions has been met it will presume that the “complicates” prong is satisfied (The IRS “will accept that a site meets the definition of a brownfield site…if it satisfies at least one of the [three safe harbor] conditions and the site is not described in [CERCLA Section 39(B)].” Notice 2023-29.)

It nevertheless may be prudent for a taxpayer to provide evidence that the presence of contaminants at the site complicates its development or reuse. Such a showing also will be necessary where a project does not fit into the safe harbor categories.

The word “complicate” is a fairly broad term and is not defined either in the IRA or in CERCLA. The term, however, has been interpreted by the courts and the EPA in the context of CERCLA’s brownfield definition. It has been construed to mean “can add cost, time or uncertainty to a redevelopment project,” or make redevelopment “more complex, involved, or difficult in some way.”

These cases make clear that the phrase “may complicate” does not have to rise to the level of a recognized environmental condition, or REC, which can trigger a cleanup obligation or remedial action under federal or state environmental laws.

Thus, the New York Court of Appeals in Lighthouse Point, interpreting the CERCLA brownfield site definition, held that the “statutory definition does not, on its face, mandate the presence of any particular level or degree of contamination.”  Rather, the property will qualify as a brownfield site, “as long as the presence or potential presence of a contaminant within its boundaries makes redevelopment or reuse more complex, involved, or difficult in some way.”

There are several ways to potentially demonstrate how the presence of a contaminant will increase the cost or otherwise make redevelopment of a site more difficult. An environmental consultant who finds the presence (or potential presence) of a contaminant in a Phase I or Phase II ESA, for example, can recommend that the developer or landowner:

• Use protective equipment or take other precautionary measures for workers on the site.
• Exercise caution and take protective measures to not unduly disturb soil or groundwater when installing e.g., project foundations, pilings, conduits, frameworks, etc.
• Undertake testing procedures or install monitoring equipment to check for contaminants.
• Place transmission lines and other conduits above rather than underground to avoid soil disturbances.
• Reroute roads and other easements to avoid potential contaminated areas.
• Apply other common-sense restrictions to site development such as prohibiting installation of drinking wells, residential structures, playgrounds, day care facilities, etc. on the property.

How close to a contaminated area must a project be located to qualify for the brownfield credit?

For the other two “energy community” categories, the IRS looks to see where the energy project will be built to determine whether it is actually “located in” an energy community. For example, the IRS rules use a nameplate capacity test to require that at least 50% of the project’s footprint is located within the census tract that had significant employment related to oil, gas, or coal activities.

Similar locational language does not appear to be applicable to brownfield sites. The IRS instead will permit a project to be located anywhere on a site where a hazardous substance, pollutant, or contaminant is present without requiring that the project be located on the contaminated portion of the site. The IRS states that:

A brownfield site is delineated according to the boundaries of the entire parcel of real property, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant. A brownfield site is not limited to only the portion of a parcel of real property that has or may have a hazardous substance, pollutant, or contaminant that complicates redevelopment.

Accordingly, if a project satisfies the safe harbor rules, or demonstrates that the presence or potential presence of contamination on the site may complicate its redevelopment or reuse, then the project will be eligible for the brownfield credit, whether or not the project is located on the contaminated portion of the brownfield site.

Merrill L. Kramer is an attorney and partner at Pierce Atwood in Washington D.C. He represents energy project developers, private equity companies, and institutional lenders on the development, financing, sale, acquisition, and investment in energy projects and portfolios. He has been ranked as one of the top energy lawyers in the country by Best Lawyers, Martindale-Hubbell and The Legal 500and recently was awarded the National Law Review’s “Go-To Thought Leadership Award” for his detailed and cogent analysis of the impact of the Inflation Reduction Act of 2022 on the clean energy industry.

When you picture a solar farm, you might imagine a vast, flat desert landscape adorned with neat rows of solar panels.

For years, this image has epitomized the ideal solar site. However, as the demand for renewable energy grows, such “ideal” sites are becoming increasingly scarce. Traditional solar farm site selection criteria focused on flat topography as well as large, contiguous parcels, lack of land features, and mild climate. These criteria often limited the potential sites. Advancements in solar tracker technology are now reshaping the landscape of solar farm site selection and opening up new possibilities for developers.

For example, slopes beyond five degrees were historically considered “unbuildable.” This is because traditional solar trackers typically used continuous torque tubes that don’t flex. Even as torque tubes are being forced to flex, these trackers have limited ability to adapt to undulating terrain, requiring developers to grade the land before installation or use variable foundation reveal heights.

Flattening the land requires bringing in bulldozers and dump trucks, adding to the cost and complexity of the project, as well as creating a negative environmental impact. Some states require significant civil engineering and stormwater management measures to even approve grading, including large and expensive retention ponds, topsoil testing, revegetation measures, and more. Satisfying these requirements can be so expensive that developers may avoid the state entirely.

Solar sites can be disqualified for development for being located in a floodplain, wetland or protected area. The site may also have an increased risk of differential settlement due to earthquakes, soil instability, or a history of underground mining. With trackers more capable of following natural, or shifting, terrain, these issues can be managed.

Solar sites in areas at risk of hurricanes, flooding, and high winds have also historically been ruled out due to the potential damage they can cause to traditional solar trackers and other PV system equipment.

New tracking technologies eliminate the need for costly and time-consuming land grading. Unlike traditional solar trackers that require level ground, an all-terrain tracker can adapt to the land’s natural shape.

Even if a flat site is found, or created, to build a solar power plant, things can change. Over a project lifespan of 30 to 40 years, the ground under a solar project can shift and eventually break or damage long continuous torque tubes.

Think of a sidewalk — when the concrete is freshly poured, everything is perfectly flat and even. But over time, the ground shifts, raising or lowering tiles. Often the rigid sidewalk tiles crack over time from the relative motion.

The same can happen to a solar array if you install a rigid traditional tracker on land affected by differential settlement. By installing flexible bearings instead, the steel piles can shift without disrupting the plant’s performance.

Breaking the paradigm of the long, continuous torque tube required a string of innovations. In addition to the articulating hardware, we needed to reimagine the tracking technology and software controls to ensure that panels can optimally track the sun’s location given the changing slope from bay to bay.

We had to develop tools to enable engineers and contractors to design a construction plan on non-flat terrain, since all of the prior software and modeling tools were only for flat terrain.

An all-terrain solar tracker also offers environmental benefits by reducing the amount of earthwork required. For example, the 170 MW Bartonsville Energy Facility solar project was recently awarded a gold medal by Virginia’s Department of Environmental Quality for going beyond regulatory requirements to improve the environment and promote sustainability. By using a flexible all-terrain tracker to fit to the natural landscape, the project was able to eliminate grading, exceeding the state’s notably strict regulations.

We need to continue to scale up solar development to reach net zero goals. As solar projects are built increasingly in populated areas, community pushback against solar development has become a major risk to our sector’s growth and achievement of climate targets. Solar development need not create negative local environmental consequences for the communities it’s built near.

By allowing solar installations to fit the land in its natural form, we can remove one of the most significant sources of pushback. We shouldn’t have to protect nature from solar development. With responsible development practices, we can actually protect nature with solar development.

One of the most significant benefits of all-terrain solar trackers is their ability to preserve the topsoil on agricultural land. Traditional solar installations often require the removal of topsoil, rendering the land unsuitable for farming in the future.

With all-terrain trackers, the rich topsoil remains intact and native plants can grow around the panels, maintaining and even improving the land’s agricultural value over time. A solar array can be used as a “cover crop” to protect the land for future generations from more permanent forms of redevelopment.

With their ability to adapt to the land’s natural shape, innovative trackers are making solar energy more accessible, cost-effective, and environmentally friendly than ever before. And they’re opening up a world of new possibilities for solar developers.

Yezin Taha is founder and CEO of Nevados, a solar tracker specialist. Prior to Nevados, Taha worked in engineering design and management, project development, energy consulting and bankability for solar projects from GE, Trane, and Black & Veatch. While at Black & Veatch, he discovered major unmet needs in the solar industry for a better mounting solution and he left to form Nevados Engineering to bridge that gap. 

The  U.S. Solar Market Insight Q2 2024 report says 11 GW of new solar module manufacturing capacity came online in the United States during Q1 2024, the largest quarter of solar manufacturing growth in American history.

The report, released by the Solar Energy Industries Association (SEIA) and Wood Mackenzie, estimates that total U.S. solar module manufacturing capacity now exceeds 26 GW annually.

In addition to solar manufacturing, the U.S. is also quickly ramping up solar installations. With 11.8 GW of new solar capacity installed thus far in 2024, total capacity now stands at 200 GW in the United States. The utility-scale segment alone accounts for nearly 10 GW of the new capacity added.

The report shows that the U.S. added over 40 GW of new solar capacity last year, and Wood Mackenzie now projects that the U.S. is on target to achieve the same goal in 2024.

“This quarter proves that new federal investments in clean energy are revitalizing American manufacturing and strengthening our nation’s energy economy,” said SEIA president and CEO Abigail Ross Hopper. “Whether it’s a billion-dollar investment in a nearby solar project or a new manufacturing plant employing hundreds of local workers, the solar and storage industry is uplifting communities in every state across this country.”

The report points to Florida and Texas as leaders in new solar capacity in Q1. Florida installed 2.7 GW in Q1 and Texas 2.6 GW. California, historically a solar leader, falls into third place with 1.4 GW of new installs; however, it is notable that in 2023, Texas installed nearly 12 GW, while California was about 6.4 GW. New Mexico is another leading market with 686 MW installed in Q1, with Ohio following close behind at 546 MW. Bringing up the bottom is North Dakota, Alabama and Alaska.

“The U.S. solar industry continues to show strength in terms of deployments,” said Michelle Davis, head of global solar at Wood Mackenzie and lead author of the report. “At the same time, the solar industry faces a number of challenges to its continued growth including availability of labor, high voltage equipment constraints, and continued trade policy uncertainty.”

The residential solar segment has been hard hit by high interest rates and unsupportive state policies. California, where the highly controversial NEM 3.0 went into effect, experienced its worst quarter in two years. Overall the residential sector installed 1.3 GWdc in Q1, reflecting a 25% decline year-over-year and 18% quarter-over-quarter but going forward residential solar is expected to be steady.

Commercial solar showed 23% growth in 2023 and expected to grow by another 14% in 2024. This sector is somewhat buoyed by California projects that were submitted under NEM 2.0 still being in the interconnection queue.

Looking at community solar, installations resulted in 279 MWdc of new capacity in Q1, with New York topping the charts at 17% year-over-year in Q1 2024, making up 46% of national installed capacity.

Again, state policy changes in California are punching holes in a previously growing market. As a result of the CPUC’s vote on AB 2316, the report authors revised their five-year outlook for California and now expects just 200 MW rather than the 1.5 GW—an 87% decline. Overall the community solar market is expected to grow 4% in 2024, exceeding 1.3 GWdc of annual capacity.

Questions and challenges

With many unanswered questions about tariffs on imported solar modules and other components, the report contends that a tariff increase will not have a significant direct impact on the U.S. solar industry, given that the U.S. is importing less than 0.1% from China at the present time.

Moving forward, the report’s five-year outlooks expects the U.S. industry to install around 40 GWdc a year for the next five years. Trade policy uncertainty coupled with shortages in workers as well as high-voltage equipment, will keep overall growth in the single digits through 2029. The five year projection, however, is for U.S. solar capacity to grow to 438 GW by 2029.

The U.S. has a net-zero by 2050 goal, which means moving away from fossil fuel generated energy as fast as possible as much as 40% of all carbon dioxide pollution comes from fossil fuel power plants, according to the Department of Energy (DOE). The good news is that for the first time, solar accounted for over half of new electricity generation capacity added 2023 and, by 2050, solar is expected to be the largest source of generating capacity on the U.S. grid.

As the more large-scale solar projects seek approval in the U.S., the Department of Energy is concerned that measures are taken to gain public trust and understanding of the need for and scope of the projects. To that end, the DOE is investing $9.5 million in four new projects that support social science research that examines the ways that siting practices can influence public attitudes toward and permitting of large-scale solar facilities.

The award was one of four made by DOE’s Solar Energy Technologies office under their Solar Energy Evolution and Diffusion Studies 4 (SEEDS 4) program. The organizations receiving funding under the program include the Solar and Storage Industries Institute, Michigan State University, Princeton University, the and the University of Pennsylvania.

The Solar and Storage Industries Institute (S12) was awarded $2.5 million for a project that builds off the stakeholder-driven Uncommon Dialogue: Large-Scale U.S. Solar Development, convened by Stanford University, the Solar Energy Industries Associataion (SEIA) and The Nature Conservancy, and balances three imperatives in the development and deployment of large-scale solar projects: climate, conservation, and community.

In partnership with the Uncommon Dialogue working groups, the project team will identify the best ways to engage community, and these practices will be tested at large-scale solar project sites. The University of California, Santa Barbara and Lawrence Berkely National Labs will study how these practices shape local support for large-scale solar projects.

“We are incredibly excited to receive this award and thank the DOE for this opportunity to perform cutting-edge research on large-scale solar siting and permitting,” said David Gahl, executive director at SI2. “By testing stakeholder-developed community engagement practices at actual solar sites, we hope to yield new insights that improve outreach to host communities.”

Michigan State University was awarded $2.5 million for a project in which researchers will evaluate the potential to speed up large-scale solar siting and permitting processes while also reducing community burdens and improving procedural justice and energy equity. The project will study ten large-scale projects in four different regions of the country.

Princeton University was awarded $2 million for a project in which researchers will assess the potential for Community Benefit Agreements. These legal agreements between community groups and large-scale solar developers can deliver tangible benefits to communities, build credibility in solar projects and strengthen trust across stakeholder groups.

University of Pennsylvania researchers were awarded $2.5 million to evaluate how different siting practices shape community support for large-scale solar projects and how those dynamics differ across different types of communities.

Also read: Solar project developers face opposition from Joshua Tree conservationists

PV Evolution Labs (PVEL), an independent test lab for the downstream solar industry and member of the Kiwa Group, published its 2024 PV Module Reliability Scorecard. This 10^th edition of the Scorecard names 388 model types of PV modules from 53 manufacturers as Top Performers in PVEL’s testing, the most in the company’s history. Last year the Scorecard named 250 model types among 35 manufacturers.

Kiwa PVEL uses the Product Qualification Program (PQP) to provide the solar industry with empirical data for PV module benchmarking and project-level energy yield and financial modules to identify top performing PV modules.

The PQP was expanded in the fall of 2023 with a new test to address concerns around ultraviolet induced degradation (UVID). It also refocused the hail stress sequence (HSS) on identifying the threshold of glass breakage and modified the mechanical stress sequence (MSS) to target module mechanical durability concerns.

In addition to expanded PQP testing, other updates to the Scorecard include a new Top Performer category for hail, highlighting modules that did not experience glass breakage with ≥40 mm hail, and a higher bar for LID+LETID and PAN Top Performers, with a raised threshold for Top Performer qualification as technologies have improved,

This year’s Scorecard is emphasizing manufacturers who are Top Performers in multiple categories, providing key takeaways on the impacts of various cell technologies and module designs, and offering a deep dive—for the first time– into Kiwa PVEL’s Incidence Angle Modifier (IAM) test results.

“Our 2024 Scorecard showcases strong results across a diverse group of solar module manufacturers, which reflects the excellence and growth we have observed in PV manufacturing in recent years.” said Kevin Gibson, managing director of Kiwa PVEL. “For over a decade, we’ve tested assumptions about solar module reliability and performance while continuing to refine our methodology as the industry continues to innovate with new technologies and module designs. We’re proud that we’re still setting a high bar for manufacturers and providing downstream buyers with the crucial information they need to make educated procurement decisions.”

This partial list shows for which tests each manufacturer achieved Top Performer status with one or more models. Kiwa PVEL noted that in some cases, test results for some test categories were not available at the time of Scorecard publication. Manufacturers are listed by the number of tests, followed by the number of years they have been designated a Top Performer, in alphabetical order. Click here to find model numbers. The full list of Top Performers is a searchable database, where results can be filtered by PQP test, manufacturer name, module type, cell technology, and more.

“With over 50,000 unique visitors to the 2023 edition, our Scorecard is the industry’s go-to resources for module reliability insights. While we applaud the advances in manufacturing and the number of Top Performers listed, we remind buyers to remain vigilant,” said Tristan Erion-Lorico, vice president of sales and marketing at Kiwa PVEL. “We encourage them to explore each page of the Scorecard to better understand the range of test results that we’re seeing every day at Kiwa PVEL’s labs.”

Notable in this year’s test results is that 66% of module manufacturers experience at least one test failure, which Kiwa PVEL said is the highest percentage ever reported.

With the extreme weather events wreaking havoc on some solar installations in recent months, the new Top Performer category for hail shines a spotlight on how the hail testing is performed. Kiwa PVEL focuses almost exclusively for 2.0 mm glass//glass and 3.2 mm glass//backsheet, but results showed that three tested BOMs of 2.5 mm glass//glass showed no glass breakage with 50 mm hail. Kiwa PVEL noted that while glass breakage typically is not considered a Scorecard “failure,” some manufacturers required multiple retests of the same hail diameter before achieving the desired hail test performance, and three manufacturers had modules where the junction box lid fell off due to hail impacts.

To be eligible for the 2024 Scorecard, manufacturers must have completed the PQP sample production factory witness after October 1, 2022, and submitted at least two factory-witnessed PV module samples to all PQP reliability tests, as per Kiwa PVEL’s BOM test requirements.

Kiwa PVEL, a testing lab for downstream solar project developers, financiers, and asset owners around the world, is part of the Kiwa Group.

Access the Scorecard here.

The Turlock Irrigation District (TID) seeks to procure new or existing clean energy projects delivering either directly into California ISO (CAISO) or TID regions, via the Ascend Analytics Energy Exchange (AEX). TID is a publicly owned company that owns and operates an integrated and diverse electric generation, transmission and distribution system that provides power to a population of 240,000 in California.

The AEX is a marketplace that facilitates renewable energy transactions between buyers and sellers. Ascend AEX has facilitated the procurement of millions of megawatt-hours per year of renewable energy and battery storage capacity.

Offers may be structured as all-in power purchase agreements (PPAs), bundled renewable energy credits (RECs) or ownership offers.

All offers must have a minimum nameplate capacity of 50 MW or annual renewable generation of at least 150,000 MWh. Acceptable commercial operation dates are no later than December 31, 2030.

TID seeks proposals for Portfolio Content Category 1 (PCC) eligible renewable generation (including solar photovoltaic, wind, biomass, biofuel, small hydroelectric generation, and geothermal) or PCC1 renewable generation plus storage (hybrid). Storage discharge duration must be at least 4 hours.

Offers are grouped in two categories:

Group A: Proposals for direct delivery to TID’s balancing authority (BA) system Power Purchase Agreements (All-in): All-in PPAs must have a term length between 10 and 30 years. Ownership Options: EPC contracts for turnkey projects with the option of offering a long-term service agreement (LTSA).

Group B: Proposals for CAISO connected resources: PPAs (All-in, Energy + RECs, Index+): All-in PPAs must have a term length between 10 and 30 years and bundled RECs (fixed price or Index+) must be between 10 and 20 years. Ownership offers will not be considered for Group B projects.

Build option proposals can take the following forms:

1. Build a power generation facility, retain 100% ownership of the facility, operate the same facility, and sell the
facility’s output to TID (respondent submits a PPA offer).
2. Build a power generation facility, TID owns 100% of the facility, TID operates the same facility, and TID takes the
facility’s output (respondent submits an ownership offer).

Regardless of the form of the build option, Respondents submitting proposals that include a build option must provide,
after being shortlisted, a legal analysis of how their proposal will comply with California procurement laws. Proposed build
options that do not comply with the procurement laws of California will not be considered.

Note that standalone storage and RA-only offers will not be considered as part of this RFP.

The RFP team will host an informational webinar for interested bidders on June 19th at 11 a.m.PT. Submissions are due July 2, 2024, at 5 p.m. PT. To participate, ask questions, and receive RFP updates and materials, prospects must register on the TID RFP website.

The Inflation Reduction Act (IRA) of 2022 sets forth both demand and supply-side incentives to encourage solar manufacturing within the U.S., both in the form of production tax credits for manufacturers and investment tax credits for project developers using domestic content. While these incentives have driven a rush of investments on U.S. lands in from major global solar component providers, Wood Mackenzie takes a look at whether the IRA is paying off in terms of growing a supply chain that includes solar components such as wafers, cells, modules and more.

According to Michelle Davis, head of global solar at Wood Mackenzie, the IRA has successfully promoted domestic solar manufacturing investment. Wood Mac is looking at 144 GW of announced module manufacturing capacity, 71 GW of cell manufacturing capacity and 61 GW of wafer manufacturing capacity by 2027. Compare this to the 26 GW of module capacity we have today, along with no wafer or cell production.

But announced versus expected are two different things, and several challenges put the buildout at risk. Wood Mac predicts only about 45% of module capacity, 25% of cell capacity, and 5% of wafer capacity will come to fruition.

According to Davis, “Some investments will fall through and less experienced companies won’t have the expertise and wherewithal to execute on their plans”.

The first challenge, she notes, is seen in the discrepancy between the capacity of modules being produced in the U.S. compared to cells and wafer. As a result, the domestic industry will continue to rely on imports for these upstream materials.

While announced capacity of 71 GW of cell manufacturing and 61 GW of wafer manufacturing could come online by 2027, cell and wafer facilities are much more expensive and complex plants to build. Davis said that because the likelihood of success is lower than with module manufacturing plants, the U.S. solar industry will continue to rely on imported cells and wafers.

The second challenge, according to Davis, is that very few of the “other” solar components are made in the U.S. and this includes glass, backsheets, frames, junction boxes and more. As demand increases, capacity will grow—but it will take time.

One example is U.S. dependence on aluminum module frames, which are mostly imported from East and Southeast Asia, and the report notes that they are all made from carbon-intensive aluminum. A report produced by Wood Mackenzie and Origami Solar, a manufacturer of steel frames, says that if the U.S. solar industry switched from aluminum to recycled steel frames, it would no longer be dependent on foreign imports because “the  massive, well-established U.S. steel industry is positioned to easily meet the demand of domestic manufacturers with a more reliable, durable, less carbon-intensive, and readily available product”.

A third challenge is price. With overseas manufacturers expanding stockpiles, oversupply is causing steep price competition, according to Davis, and U.S. manufacturers are selling modules at a loss to compete.

In response to the price competition, the Department of Commerce initiated its investigation for alleged antidumping and countervailing duty (AD/CVD) infractions in Vietnam, Malaysia, Thailand, and Cambodia. Historically, tariffs have ranged as high as 50% to 250% of the cost of shipped goods. The International Trade Commission (ITC) must make a preliminary determination by June 10, 2024, on whether the domestic industry has suffered injury from import of dumped goods.

These issues and challenges will be discussed in the upcoming Wood Mackenzie’s Solar and Energy Storage Summit June 12 to 13 in San Francisco.

A solar project that was unanimously approved by the Kern County, California Board of Supervisors in 2021 is coming under fire by some who oppose the cutting of western Joshua trees to make way for the Aratina solar project. An environmental review process is conducted prior to approval and before construction begins on any large-scale solar plant, including Aratina.

Aratina is a solar-plus-storage project with an intended generation capacity of up to 530 MW and 600 MW battery energy storage system. Once fully operational, it is expected to produce enough clean electricity to power 180,000 homes. The electricity generated by the Aratina Solar Center will be transmitted to utilities and community energy providers throughout California.

In addition to reducing 860,000 metric tons of carbon emissions every year, which is the annual equivalent to planting 14 million trees or removing 180,000 cars from the road, the project is expected to benefit the local community. Avantus has allocated over $135,000 toward programs and services in Boron and Desert Lake. It is also is expected to generate over $30 million in local tax revenue over the solar center’s lifetime that can go toward local services like schools, public safety, and street services. During construction, Aratina is expected to create approximately 570 construction jobs paying between $31 and $75 an hour.

To receive approval to develop the project located in the Boron and Desert Lake area of eastern Kern County, California, Avantus, the developer produced an Environmental Impact Report, as required prior to beginning construction. The company held public forums as part of the County review, during which some local residents raised concerns about visibility of the plant, and the developer altered its plans, stating that it “listened to the concerns and have incorporated them into a revised design that increases project setbacks from residential areas by up to a half-mile (almost nine football fields)”.

The revised site design, referred to as Aratina 2.0 by Kern County, increases project setbacks from Boron and Desert Lake’s residential areas. The company said the raised bed railroad that runs by the location and vegetation alongside the road will also reduce visibility of the project.

Because the site of the Aratina plant is home to western Joshua trees, the developer has to comply with the Western Joshua Tree Conservation Act (WJTCA), a California Law that was enacted in July 2023. Incidental Take Permits of the WJTCA authorize renewable energy developers to take western Joshua trees with an option to pay a standard mitigation fee rather than complete mitigation actions. Under the act, the fees collected are deposited into the Western Joshua Tree Conservation Fund for the purposes of acquiring, conserving and managing western Joshua tree conservation lands and completing other activities to conserve the tree.

To meet these requirements, Avantus hired qualified biologists, approved by the California Department of Fish & Wildlife (CDFW), to a complete count of all western Joshua trees within the site and they will provide the CDFW with a complete Tree Census report. As part of the mitigation requirement in the WJTCA, Avantus must pay a mitigation fee of $10,521.95 per acre to be mitigated to the Western Joshua Tree Mitigation Fund. In addition, prior to removing any western Joshua tree or engaging in groundbreaking activities, the developer was required to contribute $10,000 to cover the account fees and the cost of retaining a land acquisition specialist to assist the department in locating, acquiring and conserving the mitigation lands.

According to Avantus, the process of selective clearing of vegetation, including Joshua Trees and large natural obstacles, will soon begin. The removal has been approved by Kern County and the CDFW, with all impacts such as noise and traffic minimized throughout.

Going beyond the requests of local residents and requirements of the WJTJCA, Avantus purchased the grazing rights on 215,000 acres of federal land in Kern County and created the Onyx Conservation Project. The contiguous land area is seven times larger than the city of San Francisco and considered among the largest mitigation projects in the nation.

The habitat is home to 20 sensitive wildlife species including the California condor, Mojave Desert tortoise, American badger, Mohave ground squirrel and golden eagles. It is also estimated to include more than 80,000 acres of western Joshua tree habitat, including 3,000 acres of dense woodland. This conservation effort will help sustain the health and diversity of the desert ecosystem, which is underlaid by designated Wilderness Areas, Desert National Conservation Lands, and Areas of Critical Environmental Concern. All 215,000 acres will also be open for public recreational use, including hiking and camping.

Avantus will also invest millions of additional dollars for habitat enhancements across Onyx to jumpstart restoration for desert plants and wildlife species.

The CDFW is cognizant of how renewable energy development is necessary in the effort to combat climate change, and endorses such protective measures.

“Our Department is committed to the conservation, protection and restoration of the Golden State’s habitat, and this groundbreaking state and federal public-private partnership provides a roadmap for how renewable energy can continue to combat climate change while also providing landscape-level ecosystem benefits to native plants and wildlife,” said CDFW regional manager, Julie Vance. “By purchasing and permanently retiring the grazing rights, Avantus is assuring this rich, vibrant land is preserved and its inhabitants can flourish.”

Avantus, formerly 8Minute Energy, is a leading solar and energy storage provider and is on track to provide more than half of California’s utility-scale solar and storage demand over the next decade. Aware of the impact that solar projects can have on land, Avantus works closely with wildlife agencies and environmental organizations safeguard species throughout all stages of a project’s life. Avantus reports that its past projects have received support from groups including the Sierra Club, Audubon California, Defenders of Wildlife, and the Natural Resources Defense Council.

Why large-scale solar?

Climate change threatens our nation and planet, as evidenced by the increasing number of extreme weather events. The U.S. has a net-zero by 2050 goal, which means moving away from fossil fuel generated energy as fast as possible as much as 40% of all carbon dioxide pollution comes from fossil fuel power plants, according to the Department of Energy.

The good news is that for the first time, solar accounted for over half of new electricity generation capacity added 2023 and, by 2050, solar is expected to be the largest source of generating capacity on the U.S. grid.

According to data from the Solar Energy Industries Association (SEIA) and Wood Mackenzie, the U.S. has officially exceeded five million solar installations, marking a milestone that comes just eight years after the U.S. reached one million installations in 2016.SEIA forecasts that solar installations in the U.S. will double to 10 million by 2030 and triple to 15 million by 2034.

While the number of installations in itself is impressive, cumulatively they are making a serious cut to carbon emissions. SEIA estimates that the installations displace 198 million metric tons of CO2 every year. This reduction is the equivalent to 22 billion gallons of gas, or enough gas to travel to the sun and back nearly 3,000 times in a traditional ICE vehicle. Overall, SEIA calculates that the current solar capacity in the U.S. offsets the emissions of 12 million Americans, which is greater than the population of New York City and Los Angeles combined.

With PV expected to triple in the United States by 2028, to reach an estimated 380 GW of solar capacity, according to the SEIA and analysts at Wood Mackenzie, sharing facts early on is important. Not only is it important to seek input from area residents—modifying plans when necessary—but going above and beyond permitting requirements to mitigate potential environmental damage is becoming more common among large-scale developers in the U.S.

The Climate Superfund Act (S.259) was signed into law into law with a Senate voted of 26-3 and a House vote of 106 of the 150 members in favor. However, it was passed without a signature or a veto from Republican governor, Phil Scott.

The Act, modeled on the federal EPA Superfund program, requires the fossil fuel companies who produced more than 1 billion metric tons of greenhouse gas emissions from 1995 to 2024 to contribute to the Climate Superfund Cost Recovery Program Fund.

“With the enactment of the Climate Superfund Act, we are entering a new era in the effort to hold Big Oil accountable for the damages they have caused,” said Elena Mihaly, vice president of Conservation Law Foundation Vermont. “No longer are we reliant on litigants. Finally, the legislative branch of government is saying it’s time to make the world’s biggest polluters pay a fair share of the cleanup costs.

The Climate Superfund Cost Recovery Program Fund will be administered by the Secretary of Natural Resources to provide funding for climate change adaptation projects in Vermont.  Monies from the Fund will go toward “climate change adaptation projects” that will be implemented according to the State Hazard Mitigation Plan.

The fossil fuel companies will be expected to begin payments of at least 20% of the total cost recovery demand no later than six months following the issuance of the cost recovery demand, followed by annual payments of up to 10% of that demand.

“Vermont’s citizen legislators really stepped up on this bill,” said Lauren Hierl, executive director of Vermont Conservation Voters and a Montpelier city councilor. “Without the Climate Superfund, the costs of climate change falls entirely on taxpayers – and that’s not fair. Now, there’s finally a law in place to require the corporations that caused the damage to pay, too.”

The law will likely be challenged by the fossil fuel industry. In a letter to the Vermont House Judiciary and Environment and Energy Committees the American Petroleum Institute said it “believes S.259 is bad public policy and may be unconstitutional”. The Institute thinks the bill is imposing charges for activities that were legal, and it says it’s “holding companies responsible for the actions of society at large”.

“We know that Big Oil will fight this in the courts,” said Representative Martin LaLonde (South Burlington), chair of the House Judiciary Committee, “But, as an attorney myself, and having worked closely with many legal scholars in shaping the bill, I believe we have a solid legal case. Most importantly, the stakes are too high – and the costs too steep for Vermonters – to release corporations that caused the mess from their obligation to help clean it up.”

Last summer Vermont felt the full effects of climate change when record-breaking rainfall washed out roads and caused flooding in many part of the state. President Biden declared a State of Emergency when the storms caused what Governor Scott referred to as “historic and catastrophic” flooding.

“For too long, giant fossil fuel companies have knowingly lit the match of climate disruption without being required to do a thing to put out the fire,” said Paul Burns, executive director of the Vermont Public Interest Research Group (VPIRG). “Finally, maybe for the first time anywhere, Vermont is going to hold the companies most responsible for climate-driven floods, fires and heat waves financially accountable for a fair share of the damages they’ve caused.”

The bill received broad support in addition to the legislators who voted in favor. Vermont Public Interest Research Group, Vermont Natural Resources Council, the Conservation Law Foundation and the Sierra Club are among the many supporters of the bill.

“For decades, the oil industry has profited while their products and practices continue to cause societal harm in the forms of global climate change, public health hazards, and environmental degradation,” said Luke Miller, Vermont Sierra Club Executive Committee Member. “The Climate Superfund bill seeks to make Big Oil companies acknowledge and compensate the public for the damages they have caused over the years.”

As expected, the California Public Utilities Commission (CPUC) voted on changes to its utility-backed community solar program despite strong opposition from industry groups, community solar developers and even Assemblymember Chris Ward who introduced the original version of the bill (AB 2316).

Community solar enables small businesses and residents who are renters or who otherwise cannot put solar on their roof to subscribe to a portion of an off-site solar facility, receiving a utility bill credit for the power it generates. In California, approximately 45% of California households are renters who don’t own their roofs and, therefore, can’t install a solar system.

The Community Renewable Energy Act (AB 2316) put forth by Assemblymember Ward was sponsored by the Coalition for Community Solar Access (CCSA), and supported by the Solar Industries Energy Association, GRID Alternatives, Vote Solar, the Sierra Club, and more. Notably, investor-owned utilities, which serve over 75% of the electricity usage in the state, opposed the bill.

Riding on the tail of the CPUC’s net metering change, which dealt a serious blow to the residential solar industry, developers and other industry experts expect this new legislation will stall the buildout of community solar in California.

California was previously the leading state in solar energy; however, the tide is turning. Aaron Halimi, founder and president of Renewable Properties, a community solar developer, said that this recent decision by the CPUC will prevent California from being a leader in community solar. An increasing number of states are implementing pro-active community solar policies just as the market is starting take off.

Calling the new rules a “misguided decision”, Halimi said it’s unlikely the industry will invest in building community solar and energy storage projects in California.

“The CPUC’s decision primarily benefits the financial interests of utilities and does not support the State’s climate goals or the aim of reducing electric bills for low-income Californians, which was the purpose of AB 2316,” said Halimi.

Derek Chernow, Western regional director for the Coalition for Community Solar Access (CCSA) released a statement saying that the ruling “ignored the will of the California Legislature and the broad coalition of ratepayer, equity, environmental, labor, agricultural, and business groups who have demanded a functional community solar program for more than a decade”.

The legislation passed with a 3-1 vote, and CCSA thanked the lone dissenter, Commissioner Darcie Houck, for her vote and remarks for how this Decision will fail to reach community solar’s full potential.

The CCSA characterized the CPUC’s choice to accept the utilities’ proposal as doubling down on failed programs that “have not — and will not — establish a viable community solar market that would provide affordable energy to Californians that need relief the most”.

“It’s also further evidence that California’s utilities are doing everything they can to stifle distributed energy generation in order to tighten their grip on the state’s electricity grid. The vote solidifies California’s place near the bottom of community solar markets nationwide, ceding leadership to other states to truly democratize solar energy and fulfill national energy equity goals,” said CCSA.

Hail can cause significant damage to solar installations and is the root cause of half of insured project losses, according to risk expert VDE Americas. While hail cannot be avoided, damage can be prevented by tilting solar modules on a tracker, called stowing, turning the face of the modules away from the hail.

FTC Solar, a Texas-based solar tracker specialist, introduced the Automated Hail Stow Solution that uses meteorological data to automatically stow solar modules when a hail storm is on the horizon.

After collaborating with VDE Americas on studying the impact of hail events on solar installations, FTC developed a hail stow strategy that positions solar modules to minimize the impact from direct hail and wind.

The automated hail stow solution integrates with FTC’s Sunops, a cloud-based PV asset monitoring solution designed to manage and improve solar asset performance. FTC reports the software considers factors like advanced tracking algorithms and appropriate tracker stowing for extreme weather events.

Ken Kozizki, chief marketing officer of FTC Solar told pv magazine USA that the tracker quickly moves to >50 degree hail stow with modules facing away from the wind in response to the meteorological predictive data. The hail-stow algorithm is driven by meteorological data that FTC gets from an industry-leading third party provider, and weather conditions are analyzed using multiple radars that combine to form an accurate forecast for a single location.

There is also a feature that allows the plant manager to manually move to the nearest high angle stow to further reduce stow time, Kozizki said. Stow thresholds can also be customized, based on risk appetite and site location, including factors such as hail size, probability and radius.

The Community Renewable Energy Act (AB 2316) was sponsored by the Coalition for Community Solar Access (CCSA), and supported by the Solar Industries Energy Association, GRID Alternatives, Vote Solar, the Sierra Club, and more. However, the California Public Utilities Commission (CPUC) opposed the bill.

The CPUC asserted in its proposed decision that the Net Value Billing Tariff (NVBT) outlined in the Community Renewable Energy Act “conflicts with federal law and does not meet the requirements” of the bill, which CCSA has noted is erroneous.

In comments filed in March by CCSA, it characterized the original proposed decision as misguided and misinformed, and determined it will not result in the development of community solar projects as envisioned by the legislature with the enactment of AB 2316.

Now the CPUC has revised its proposed decision and in it concedes that it needs guidance as to what a successful community solar program looks like:

…the record of this proceeding contains no details on what would be considered a successful community renewable energy program. Accordingly, the workshop with parties to discuss the objectives, methodology, and metrics for the evaluations of the community renewable energy program will include a discussion of what a successful community renewable energy program would look like, including metrics for success and a megawatt baseline expectation for the community renewable energy program.

This revised proposed decision says it’s beneficial to ratepayers to layer a customer subscription model and a non-ratepayer-funded adder on standard supply-side tariffs. This “revised” proposed decision still intends to rely on one-time funds from the EPA’s Solar for All program as a subsidy. The CCSA warns against subsidizing “an unworkable program” instead leveraging private capital “to serve hundreds of thousands of income-qualified customers and small businesses”.

Furthermore, the revised proposed decision gives no details such as a method for dispersing external funding to the projects and participating customers, reporting requirements, the process for participating, eligible tariffs, cost recovery mechanisms, and more.

According to the CCSA, CPUC is moving nothing forward and instead, “doubles down on supporting the broken proposal from the state’s utilities and would make California’s community solar program dead on arrival. It will not result in the development of new projects as envisioned by AB 2316 and will continue to leave California with no functional community solar program.”

The CCSA emphasizes the value that community solar can bring to California’s grid and help the state achieve both clean energy and equity objectives. Moving forward with the revised proposed decision, CCSA contends, would mean ignoring the many groups from the legislature to a broad coalition of ratepayers and other groups who seek a functional community solar program.

An increasing number of states are implementing pro-active community solar policies just as the market is starting take off. While installations of community solar contracted in 2022, Wood Mackenzie forecasts the U.S. community solar market to grow 118% over the next five years, with at least 6 GW expected to come online in existing markets between 2023 to 2027.

“California should be seizing this once-in-a-generation opportunity to create a vibrant market. We urge the CPUC to slow down and take the additional time necessary to get this important decision right,” said Derek Chernow, Western regional director for the CCSA.

The Federal-State Modern Grid Deployment Initiative received commitments from 21 states. The program aims to bring together states, federal entities and power sector stakeholders to help modernize the U.S. power grid in order to meet an onslaught of both challenges and opportunities the sector will face in coming years.

The 21 states include Arizona, California, Colorado, Connecticut, Delaware, Hawai‘i, Illinois, Kentucky, Maine, Maryland, Massachusetts, Michigan, New Jersey, New Mexico, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Washington, and Wisconsin.

These states have committed to prioritizing efforts to adopt modern grid solutions to expand grid capacity and build modern grid capabilities on both new and existing transmission and distribution lines.

“American economic competitiveness globally relies on access to low-cost, reliable power. The Federal-State Modern Grid Deployment Initiative announced earlier today and already supported by 21 states, is meaningful progress toward the upgraded and better-connected transmission system that lies at the heart of the vision of ACORE’s Macro Grid Initiative,” said Ray Long, President and CEO of the American Council on Renewable Energy (ACORE). “This announcement builds on the commendable commitment to upgrade 100,0000 miles of existing transmission lines by utilizing public-private partnerships to deploy readily available technologies, such as grid enhancing technologies and high-performance conductors.

U.S. power grid used today was built in the 1960s and 70s. The aging grid struggles to handle the extreme weather events caused by climate change, let alone the renewable energy needed to meet energy goals. According to the U.S. Department of Energy, 70% of transmission lines are over 25 years old and approaching the end of their typical lifecycle.

In the past, expanding the capacity of the U.S. power grid had relied on building new transmission lines with technologies that have not changed since the mid-twentieth century. However, with today’s new modern grid technologies such as high-performance conductors and grid-enhancing technologies enable double or more the amount of power than is handled on today’s transmission lines, the grid can be upgraded quickly and in a cost effective manner compared to constructing new transmission lines.

States can receive technical and analytical assistance from the U.S. Climate Alliance. In conjunction the Department of Energy(DOE) has many technical assistance programs that aim to support analysis for utilities, policy makers, regulators, state energy offices, and other stakeholders.

Funding to help states deploy advanced grid technologies is made possible through the Inflation Reduction Act (IRA) and Bipartisan Infrastructure Law (BIL). For example, the DOE’s Grid Deployment Office is administering $10.5 billion in competitive grant funding through the Grid Resilience and Innovation Partnerships (GRIP) Program.

The DOE Loan Programs Office has $250 billion of loan guarantee authority to provide low-interest financing to projects that upgrade existing energy infrastructure, with program guidance that highlights reconductoring as a qualifying project example. The Department of Agriculture’s Empowering Rural America (New ERA) program provides $9.7 billion in low interest loans or grants and represents the largest investment in rural electrification since 1936, with eligibility for transmission system upgrades.

Funding is also available through the Grid Resilience and Innovation Partnership (GRIP) program, which recently closed applications for up to $2.7 billion in DOE grant funding under a second round. The intention of the program is to fund projects that will upgrade and modernize the transmission and distribution system to increase reliability and resilience to prepare the grid for extreme weather as well as to ensure delivery of affordable, clean electricity to all communities across the nation.

Grid-enhancing technologies (GETs) were cited by an RMI study as potentially capable of saving project developers collectively hundreds of millions of dollars in interconnection costs compared to default network upgrades, while the project-level savings “could be the difference” that allows a developer to build a project instead of dropping out of the queue. The study notes that GETs can also be installed more quickly than other network upgrades.

The Federal Energy Regulatory Commission (FERC) recently issued a final rule on Regional Transmission Planning and Cost Allocation, Order 1920, which adopts requirements for how transmission providers must conduct long-term planning for regional transmission facilities, consider the use of advanced conductors and Grid Enhancing Technologies.

The Solar Energy Industries Association (SEIA) has been involved with this rulemaking proceeding over the past two years, advocating for reforms to the transmission planning process to account for all the benefits that clean energy offers.

“We’re pleased FERC took several steps to improve America’s outdated transmission system, including following SEIA’s recommendations requiring transmission providers to engage in long-term regional planning,” said Melissa Alfano, senior director of energy markets and counsel for SEIA.

Wyoming ranked 50^th in installed solar in 2023, according to the Solar Energy Industries Association (SEIA) with only 124 MW installed. As of Q4 2023, SEIA expected it to pop up to 43^rd place with 685 MW expected to be installed over the next five years. However, the Cowboy Solar Project, at 771 MW and 268 MW of battery energy storage, will surpass that in one fell swoop.

The Cowboy project was just approved by Wyoming’s Industrial Siting Council, and developer Enbridge plans construction in two phases with both beginning in March 2025. Commercial operation of Phase 1, which will include 400 MW of solar and 136 MW battery energy storage system (BESS) is expected in January 2027. Commercial operation of Phase II with 371 MW solar and 133 MW BESS is expected to begin in August 2027. The company estimates that the onsite workforce will have average of 285 temporary workers monthly, with a peak workforce of approximately 375 workers in April 2025.

For more on the process of obtaining permits for large-scale renewable energy project in Wyoming, read Early engagement avoids perils of Wyoming industrial siting.

The combined 771 MW of solar is estimated to be enough to serve 771,000 homes, or more than three times the number of homes in Wyoming. Enbridge has not yet announced an offtake agreement for the electricity generated.

Enbridge, a Canadian multinational pipeline and energy company headquartered in Calgary, Alberta, Canada, intends to build the project about 4 miles south of Cheyenne on 3,845 acres of private land that it will lease.

While the company reports that it is currently responsible for moving about 30% of the crude oil produced in North America and 20% of the natural gas consumed in the United States, the company says it has committed to reducing emissions 35% by 2030 and being net-zero by 2050. It has a portfolio of over 5.2 GW of wind, offshore wind and solar projects in Canada, the U.S., France, Germany and England.

To keep the public informed about the massive Wyoming project, Enbridge held public meetings to notify neighbors within 1 km of the project in October 2023, which were advertised in the local newspaper, the Wyoming Tribune Eagle. The company said it is planning further engagement with broader public notification and outreach to community stakeholders and Tribal communities as the project gets closer to the 2026 in-service date. Details of future outreach will be posted here.

(Read Opposition stymies solar—sometimes)

Approval by the Industrial Siting Council is just the first step in the process, as Enbridge must also obtain permits from Laramie County as well as necessary environmental and municipal permits required before constructing the project.

Once operational, the Cowboy solar project will be just the third utility-scale solar installation in the state. In April Southern Power, a wholesale energy provider and subsidiary of Southern Company, announced the operation of the 150 MW South Cheyenne Solar Facility, currently the largest in Wyoming. Southern Power acquired the project from Qcells USA, which had served as the project developer, module manufacturer and engineering procurement construction (EPC) provider of the site. Cheyenne Light, Fuel and Power signed a 20-year power purchase agreement for the electricity generated, which will be used to provide renewable energy to a data center customer.

Prior to the South Cheyenne facility, the largest was the Sweetwater solar project, a 98 MW installation by SOLV Energy, developed by Clenera, an Enlight Renewable Energy company. Covering roughly 700 acres the project generates enough power to serve the equivalent of 12,000 homes each year.

Solar siting tool

With so much unspoiled land in Wyoming, The Nature Conservancy (TNC) developed the Brightfields Energy Siting Initiative (BESI) tool specifically for Wyoming. The intention is to guide new energy development to previously disturbed areas or “brownfields” so as to diversify the state’s energy mix without compromising the state’s iconic wildlife and natural areas.

The BESI tool identifies areas where new energy development is unlikely to encounter significant land use conflicts, permitting delays and cost overruns. It can locate sensitive places to avoid as well as provide information down to an individual project site. For example, it can determine if a potential site would risk conflict with a known mule deer migration route, a location with an abundance of cultural resources nearby or a golden eagle nesting area. It can look at habitat and can flag it as a site that would be better for restoration rather than the site of a new energy facility.

Access the BESI map tool here.

Excitement about the IRA continues to surge, with developers and tax credit investors poised to leverage unprecedented growth opportunities while accelerating the country’s clean energy transition. The IRA has attracted $110 billion in private investment and has created close to 100,000 jobs across the U.S.

The key to ensuring expected financial returns from the IRA comes down to a single word: compliance.

Tax credit compliance is fraught with risk and complex to manage. Tax credit investors and transfer buyers, including those utilizing the new T-Flip structures and corporate buyers leveraging tax transfer marketplaces, are all subject to IRA audit risk and the associated tax credit losses and/or expensive non-compliance penalties.

Who holds the risk?

In terms of risk management, tax credit transactions tend to focus on protecting the investor from recapture audit risk, but compliance risks affect the entire clean energy project value chain.

Risks across the value chain:

• Tax credit insurers ultimately hold claim risk, but do not have oversight over EPCs, sub-contractors, or supplier compliance.
• Investors do not have insight into whether or not their investments are compliant with IRA requirements.
• Project developers need to protect investors but don’t have a way of understanding or reporting whether engineering, procurement, and contractors (EPCs), sub-contractors, or suppliers are compliant.
• EPCs can’t guarantee prevailing wage and apprenticeship (PWA) compliance for projects.
• Sub-contractors do not have capabilities to comply with PWA requirements- they rely on contractors for this.
• Suppliers are hesitant to share the confidential cost data required for IRA domestic content compliance.

Risks passed across the chain

What can developers do to mitigate risks? They can provide sponsor indemnifications, require EPC contracts to guarantee PWA compliance, hire an accounting firm to do an AUP (Agreed Upon Procedures) review, and even offer to pay for insurance, but none of these methods fully protect investors. In other words, even with all of these efforts, a tax credit buyer could still fail an IRS recapture audit, which would trigger a cascading set of insurance claims and lawsuits through the entire project value chain.

Risk assessment

Pre-IRA, traditional energy project risk mitigation typically began with a series of questions about a developer’s track record and the project technology size and scope. The questions then focused on an EPC’s history, supplier bankability, and supplier technology risk.

IRA tax credits have created a new, additional layer of risk. Tax credits can be worth 30%, 40%, or even 50% of the value of a project, but need to be protected from IRS recapture audit risk with meticulous proof of compliance throughout a project’s lifecycle.

False comfort

False comfort regarding compliance risk is perhaps the biggest of all.

A tax equity investor or transfer buyer may believe that a contract or an insurance policy mitigates recapture audit risk, when in reality, the investor has significant exposure. These are heightened by four key factors:

1. Unchartered territory: In a typical investment risk assessment, investors have resources like credit rating agencies, historical track records, and market expertise to evaluate internal and external risks. Since guidance on IRA tax credit’ compliance is new and still evolving, investors don’t have the same level of expertise or policies in place to mitigate these new risks.

2. The role of insurance: Because tax equity investors and corporate tax credit transfer buyers assume responsibility post transaction for IRA compliance, it’s common to assume they can use tax credit insurance to cover the risks of IRS audit failure and the resulting loss of tax credits plus any penalties.

However, the market capacity of tax credit insurance is limited, tax credit insurance can be expensive, and insurance companies still expect stakeholders to have some sort of active compliance management in place to reduce risk. In short, insurance companies are not the first line of defense in IRS recapture audit failure.

3. The limitations of accounting practices: Traditional accounting firms typically have limited risk management capabilities for IRA compliance. Because formal audits are prohibitively expensive, they offer AUP reviews, spot checks, and monthly reviews. Still, since they don’t work directly with project EPCs or subcontractors, they can’t sign off on actual compliance for the project PWA requirements.

4. Post-build compliance- Federal PWA requirements extend beyond initial construction phase compliance. Any alterations or repairs throughout the audit recapture period need to meet PWA compliance. Without adequate PWA programs and systems in place to manage operations and maintenance (O&M) contractors, asset management teams can jeopardize tax credits for the entire project.

Tax equity investors and transfer buyers can protect themselves from audit risk and recapture by seeking a platform that was designed specifically for the IRA compliance requirements across the entire project value chain.

The risk management imperative

Tax equity investors and corporate entities utilizing the tax credit transfer market will be held accountable for any error, omission, or lack of compliance from project EPCs and subcontractors. Without an active compliance verification program in place from the onset of a project, investors are taking on significantly more risk than they may understand.

How to approach risk mitigation

Similar to other federal requirements, there are dedicated software platforms designed specifically for IRA compliance. When combined with guidance from compliance experts, they can provide the maximum risk mitigation possible.

To best protect against risk, a single platform should be able to manage all of the intricacies of IRA compliance over the lifecycle of a project. It should be able to ensure compliance for PWA and the adders for domestic content and energy communities. It should also manage compliance for PWA from initial construction to O&M-phase alterations and repairs, and provide protection from recapture audits from the full five year (ITC) or 10 year (PTC) recapture audit periods.

The future of compliance risk management

Investors with the foresight to recognize the risks of IRA non-compliance and require a third-party compliance management system in place prior to construction kick-off will be ahead of the game. By leveraging IRA compliance software and data analytics, investors will be able to fully leverage their IRA tax incentives and reduce their IRS recapture audit failure risk while contributing to a solar-powered, decarbonized future.

Charles Dauber is founder and CEO of Empact Technologies, an IRA compliance management platform. Empact delivers software and services that ensure utility and community-scale project developers and investors are compliant with Prevailing Wage and Apprenticeship, Domestic Content, Energy Community, and Low-Income Community requirements. 

SunPower announced it will now be offering Tesla Powerwall 3 as part of its portfolio of residential solar and storage products.

“Homeowners are increasingly turning to battery storage to protect themselves against ongoing utility rate hikes and grid outages. We witnessed record-breaking battery storage sales in 2024 and see a future where almost all solar systems are paired with storage,” said Shawn Fitzgerald, SVP corporate development and product strategy at SunPower.

Tesla launched the Powerwall 3 in 2024 after it was unveiled at the RE+ trade e show in September 2023. It has the same storage capacity as the Powerwall 2 (13.5 kWh) but a key differentiator is that it can provide at least 50% more power at 11.5 kW of continuous power. It is a hybrid battery with the solar and battery inverter fully integrated, and is designed for new solar installations as opposed to retrofits. Some of the innovations over the Powerwall 2 are that it is reportedly easier to install, and it is smaller and lighter, while slightly deeper.

“Pairing Tesla Powerwall 3 with our industry-leading SunPower Equinox solar system was a natural progression in offering homeowners the best products on the market.” Fitzgerald said.

According to a report by Wood Mackenzie, one in every four American homeowners who install rooftop solar this year will also add battery storage. Reasons include resiliency as well as changes in net metering policy such as California’s  NEM 3.0, which cut payments for exported solar energy by about 75%.

Powerwall was the choice in over half of home battery installations last year, according to Wood Mackenzie.

“Expanding access to Tesla Powerwall 3 allows us to offer homeowners a comprehensive energy solution under one roof including sales, financing and installation,” said Joe Holstein, owner of SunPower by Quality Home Services, a SunPower Master Dealer.

SunPower Financial reported it has expanded its suite of solar financing options to include loan and lease financing through Mosaic for Tesla battery installations. SunPower reports that qualified customers can finance a Powerwall 3 with no down payment.

SunPower specializes in residential solar installations, a market that has been hard hit by rising interest rates and policy changes such as NEM 3.0 In April SunPower announced it planned to close business segments as it restructures to lower costs. At the time the company’s stock was trading 96% lower than all-time highs and was down 86% over the past year.

SunPower’s revenues reported last December reflected a 28% year-over-year decline, while operating expenses increased, and net income resulted in a loss of $123.9 million. The company said that after a short transition period, all project pipeline operations from pre-installation through system activation would be conducted by Blue Raven Solar and other installation partners and SunPower certified dealers.

With his signature on SB24-207, Governor Polis signed into law legislation intended to modernize the state’s community solar program, start a new dispatchable distributed generation program, upgrade the power grid, and promote energy equity.

Colorado was awarded a $156 million grant from the EPA’s Solar for All program to provide loans and incentives for community solar development, including directly funding community solar projects in the state, helping to deliver lower utility bills, create jobs, and expand the benefits of solar to low-income and disadvantaged communities.

One of the major benefits of community solar is it opens access to customers that may not have a suitable roof or financial situation for rooftop solar. It allows residents, businesses, organizations, and municipalities to subscribe to a portion of a solar asset’s electricity generation to receive credit on their electricity bills for the power it generates.

The Solar for All program is one of three grant programs under the Greenhouse Gas Reduction Fund created by the Inflation Reduction Act. EPA intends to design the grants competition to “maximize impact toward” that fund’s objectives, namely reducing greenhouse gas emissions and other air pollutants, delivering program benefits “particularly” to low-income and disadvantaged communities, and mobilizing financing and private capital.

The DOE estimates that the average low-income household benefiting from this program will save around $400 a year on their electric bills; collectively that’s over $350 million in annual household savings from all 60 selected applicants, totaling over $8 billion in cumulative savings for over a standard solar project 25-year asset life.

“All Coloradans, regardless of income level or homeownership status, should be able to participate in the transition to renewable energy,” said Senate President Steve Fenberg, sponsor of SB24-207. “With the signing of this bill, we have taken a major step to remove barriers to accessing solar energy — like homeownership or credit score requirements — to ensure renters, non-profits, and small businesses can take part without breaking the bank.”

Colorado was the first in the nation when, in 2010, it passed pass legislation “truly enabling” a third-part community solar model, according to Kevin Cray, Mountain West

“It was time for an upgrade. Today’s action by Gov. Polis will reinvigorate Colorado community solar, positioning the state to regain its leadership position in providing equitable clean energy options for customers,” said Cray.

The new law is expected to deliver the following benefits:

• Deliver meaningful bill savings of 25-55% to thousands of additional income-qualified Colorado households;
• Reserve at least 51% of each community solar project for income-qualified residential subscribers;
• Enhance subscriber experiences with best-in-class enrollment methods, consumer protections, and consolidated billing;
• Prioritize projects sited on preferred locations, like rooftops and brownfields, and drive dual-use practices, such as agrivoltaics; and
• Improve the methods that third-party stakeholders use to develop community solar projects with investor-owned utilities.

“This law is a reflection of the state’s ongoing commitment to ensure an equitable clean energy transition and to leverage local energy resources to create a cost-effective and resilient grid,” said John Bernhardt, Vice President of Policy for Pivot Energy. “As a Colorado-based company, we are proud of our state’s leadership and stand ready to help realize the goals of SB 24-207.”

Organizations and advocates including Vote Solar, Nature Conservancy, Grid Alternatives, Colorado Solar and Storage Association, among others, are optimistic about the opportunities presented by this legislation.

From pv magazine Global

There has been little movement in the price of solar modules in the low-performance class this month. However, there was a significant price adjustment for modules with efficiency levels of more than 22%.

The prices of these modules, which are now mainly equipped with n-type/TOPCon cells and double-glass, are increasingly aligning with those of mainstream modules. There are only upward outliers for some types with interdigitated back-contact (IBC) or heterojunction (HJT) technology, which are not considered separately in this analysis.

Production volumes in China for n-type cells and modules appear to have increased, but the new customs situation in the United States might already be having an impact. The question is, what will this do to the European market? Increasingly lower prices would mean that demand would continue to rise if it weren’t for several disruptive factors.

There are still larger stocks of modules produced in 2023 or earlier at distributors, but also among installers themselves. However, if these measure 2 sqm in size, they are selling poorly due to their low performance. Building owners usually want to see high performance and the latest technology installed in new systems, which makes it much more difficult for existing goods to sell.

Despite the expected reduction in module production and import volumes, more Asian modules are still reaching the European market than are currently in demand. This is causing inventories to grow, even for high-performance models, putting additional pressure on module prices.

Inventories of old modules, which were produced and purchased at significantly higher prices in the past, must therefore be continually devalued. However, this is not possible for all players, which means that there are very different prices for modules with PERC technology in the market. Overall, the price difference between these categories is increasingly shrinking.

Africa and Southeast Asia will probably also become oversaturated with modules and Chinese products cannot be sold to the U.S. market. One strategy that is becoming popular is to accommodate the soft factors of the commercial business – that is, payment and delivery conditions. Instead of offering modules at lower prices, credit lines are granted – often without requiring collateral – and free delivery is promised. However, it is doubtful that this tactic will work over the long term. Many smaller companies, in particular, are on the brink and imminent payment defaults cannot be ruled out.

Some suppliers also take refuge in online marketplaces, where they try to quickly sell their stock goods to international customers without incurring sales and marketing costs. But the competitive pressure there is also great and such goods can often only be sold at dumping prices. The other issue is that there is hardly any way to get to know the potential business partner in advance –you have to take what you get.

Misunderstandings can arise in business transactions, especially across national borders, and online platform operators are not always available to provide support and advice. The efforts involved in running an online business quickly become greater than purchasing or selling within an established business relationship.

My preference for using surplus older modules is clear: installing them in larger open-space or rooftop systems. The often smaller formats are not a bad choice, especially in areas with higher wind or snow loads. The material and assembly costs increase slightly in favor of better statics, but the easier handling makes up for the disadvantage.

And there is another undeniable advantage: the modules are already in stock and are therefore guaranteed to be available, meaning there can be no delivery problems and thus delays in the construction process. You may also find a few unsold inverters and cable reels, and then the components for your PV system are almost complete.

Once a system has been built and connected to a network, nobody is interested in whether the modules are of the very latest generation or not. In any case, the resulting assets can be sold.

Martin Schachinger studied electrical engineering and has been active in the field of photovoltaics and renewable energy for almost 30 years. In 2004, he set up a business, founding the pvXchange.com online trading platform. The company stocks standard components for new installations and solar modules and inverters that are no longer being produced.

Acciona Energía, a renewable energy company headquartered in Spain, announced that the 458 MW Red-Tailed Hawk solar plant near Houston, Texas is now operational. The project is the company’s largest solar plant to date.

Acciona acquired the solar project in 2022 from Avondale Solar and Solar Plus Development. It is Acciona’s fifth investment in Texas, joining the Fort Bend Solar Farm and three operational wind farms in Cameron County.

Expected to generate clean energy equivalent to the consumption of 66,500 homes and avoid the emission of 430,000 tons of CO2 into the atmosphere every year, Red-Tailed Hawk created approximately 400 jobs during the peak construction phase, and will sustain up to 15 permanent positions.

The new facility features solar panels affixed to solar trackers that follow the sun’s path, maximizing sunlight exposure and production. It is expected to generate 742 GWh of clean electricity per year, equivalent to the consumption of around 66,500 Texas households. The solar generated will avoid the emission of approximately 430,000 tons of CO2 annually.

The project falls under Acciona Energía’s Social Impact Management program, which reallocates a portion of its annual revenue to support local community initiatives in education, wellness and environmental stewardship.

Texas is the number two solar state in the U.S., according to the Solar Energy Industries Association, with nearly 23 GW installed or enough to power 2.7 million homes. SEIA says that with supporting policy that removes market barriers, Texas can expect to see over 4 GW of solar capacity installed in the next five years. The Red-Tailed Hawk installation moves the state closer to that milestone.

Red-Tailed Hawk joins Acciona Energía’s existing portfolio of renewable energy projects in North America, which it reports now stands at 2.7 GW installed. The company currently has a 325 MW photovoltaic plant under construction in in Ohio. Worldwide the company reports it has 13.5 GW in renewable energy capacity.

GoodWe Technologies, a solar inverter and smart energy specialist, announced that it has been added to the approved vendor list of Sunnova Energy. This partnership enables Sunnova to provide GoodWe’s SMT-US inverter for medium- to large-scale commercial and industrial (C&I) solar sites.

This partnership allows GoodWe and Sunnova to meet the growing demand by commercial and industrial customers that want to stabilize energy costs.

GoodWe reports that its SMT-US three-phase, 50/60 kW inverter provides improved safety and design flexibility, and meets safety shutdown standards with a built-in rapid shutdown transmitter that eliminates the need to install additional module-level hardware. It also complies with safety standards with type II surge protection for both DC and AC to prevent voltage spikes.

The SMT-US inverters have up to 6 MPPTs and a Max 15A DC input current per string for high-power module compatibility. GoodWe claims that the inverter’s 150% DC input oversizing, 110% AC output overloading, and 180-980V wide input operating range provides for improved system uptime and increases the system’s energy output during the system’s lifetime. Furthermore, the company says the inverter has a unique fuse-free design that increases reliability while decreasing maintenance requirements, thus lowering operating costs.

“GoodWe’s C&I inverters offer benefits at every stage of the system lifecycle, from design flexibility during planning to simpler O&M and increased system uptime after interconnection,” stated Michael Mendik, country manager of GoodWe USA and Canada. “By collaborating with Sunnova, an industry-leading energy services company with national reach, GoodWe is expanding and simplifying access to its products across the U.S. as market demand is on the rise and EPCs are looking for cost-effective and competitive solutions to grow and scale their businesses.”

GoodWe offers products and solutions tailored for residential, commercial and industrial, and utility-scale PV systems. The company reports that it has over 52 GW of installations in over 100 countries and regions.

Sunnova Energy International, a provider of solar, energy storage, and home energy adaptive services, has been in the news recently for its Q1 2024 earnings report as well as recent partnerships, such as with Home Depot, for which it is now the sole provider of solar and energy storage for Home Depot customers.

In a less than stellar earnings report, the company noted a continued decline in revenues amid a challenging U.S. macroeconomic environment for the residential solar industry. Investors had been concerned about the company’s ability to generate enough cash. In response the company continued reductions in operational costs and secured unrestricted cash, which increased by $18.9 million in the first quarter compared to the prior quarter. The company reports it now has about $232 million in unrestricted cash.

Cleanleaf Energy, formerly Borrego O&M, announced the signing of agreements to provide operations and maintenance (O&M) services to new utility-scale projects totaling 350 MW in Georgia and Pennsylvania.

The portfolio consists of five total projects–four in Georgia and one in Pennsylvania, all of which are owned by Heelstone Renewable Energy.

Heelstone was launched in 2012 initially with projects in North Carolina. By 2016 the company had expanded its development into California and in 2019 received an investment from Ares Infrastructure and Power, to help develop its utility-scale solar projects across the U.S. In January of 2024, Heelstone was acquired by Qualitas Energy, at which time the developer reportedly had a portfolio of 20 GW of solar and storage assets.

“We did our homework, and Cleanleaf stood out with the most advanced and competitive services,” said a representative from the Heelstone Renewable Energy leadership team.

The agreements for the O&M of these projects are set for five years, with automatic renewals thereafter. All projects are scheduled to go live within the next 30 to 90 days, Cleanleaf told pv magazine USA.

“This achievement underscores our capabilities and readiness to handle more utility-scale projects and the synergies of our large DG footprint in 27 states combined with a growing utility-scale portfolio creates an exciting future for effective, high performing O&M services to the solar industry,” said Cleanleaf’s CEO, Mikael Backman.

With the addition of 350 MW in projects, Cleanleaf’s O&M portfolio now encompass a total of 1.8 GW. These new projects will be supported by Cleanleaf’s Realtime Operations Center in Dallas.

Cleanleaf was spun out of Borrego in 2022. Borrego, which was formed in 2002, began offering O&M services about ten years ago and grew to provide services for commercial and industrial as well as utility-scale solar.

The New York Power Authority (NYPA) has pre-qualified 79 private developers and investors to collaborate on the development of renewable energy generating projects, including solar, wind, battery storage, green hydrogen, geothermal, and related transmission.

The developers and investors were selected based on a Request for Information (RFI) issued in March that sought to assess potential interest and opportunities for renewable developers, contractors and companies. While the RFI was seeking developers across a range of renewable energy sectors, some were qualified only for one technology or category.

Respondents were assessed based on several considerations, including an evaluation of experience, financial overview, partnership structure customization and flexibility, knowledge of market dynamics and incentives, previous successful engagement within New York State, and team size and resources.

Those that were chosen are prequalified for 5 years and may now respond to both future Requests for Proposals (RFP) or other procurement offerings from NYPA.

“Through this solicitation we have identified 79 qualified potential partners that are eager to join with us to advance renewable energy generation at scale and help us advance the state’s bold climate agenda,” said NYPA President and CEO Justin E. Driscoll. “We are confident that building this stable of prequalified companies will allow NYP to move forward decisively in deploying additional renewable energy generation for the benefit of all New Yorkers.”

New York State’s nation-leading energy goals has set it on a path to achieving a zero-emission electricity sector by 2040, including 70% renewable energy generation by 2030, and economywide carbon neutrality by mid-century. In 2019, New York enacted the Climate Leadership and Community Protection Act, which established objectives and requirements aimed at addressing climate change and guiding the state toward a clean energy-based economy.

With solar as a strong part of the clean energy mix, the state created a framework to achieve at least 10 GW of distributed solar by 2030, enough to annually power nearly 700,000 average-sized homes. That framework provides a strategy to expand the state’s already successful NY-Sun initiative into one of the largest and most inclusive solar programs of its kind in the nation.

The 2023-24 Enacted State Budget provided NYPA with enhanced authority over renewable energy generation and storage projects to help support the state’s renewable energy goals. In addition, new renewable projects will support the new

REACH program, which aims to enable low-income and moderate-income electricity customers to receive bill credits through the production of renewable energy by NYPA.

 The RFQ will remain open and additional participants may still submit qualification. Also NYPA says that companies that did not qualify for this solicitation may respond to future procurement actions that may better align with their business models.

“We are very encouraged by such a positive response to our RFQ,” said Vennela Yadhati, NYPA vice president of renewable project development. “Having a deep bench of qualified partners will allow us to proceed deliberately and expeditiously as projects are identified.”

NYPA will now proceed with a planning process that will include conferrals and public hearings on its renewable energy development strategic plan, which NYPA will publish in January 2025.

Virtual power plants (VPPs) are attracting a lot of attention at the moment. Our upcoming 50 States of Grid Modernization Q1 2024 report documents numerous policy and program actions taken by several states, and our very own Autumn Proudlove moderated a session on VPPs at the 2024 North Carolina State Energy Conference. Additionally, the U.S. Department of Energy published an extensive report on VPPs last year, and even mainstream media is publishing articles on their potential. But what exactly are VPPs, and what are states doing to enable their development?

VPPs can incorporate a variety of technologies with different characteristics, leading to the challenge of adequately defining them. However, all VPPs share the common elements of quantity and controllability. At their heart, VPPs involve the aggregation of a large number of distributed energy resources (DERs), which can be collectively controlled to benefit the grid and potentially obviate a utility’s need to activate a traditional peaking power plant.

The Smart Electric Power Alliance (SEPA) groups VPPs into three general categories: Supply VPPs, Demand VPPs, and Mixed Asset VPPs. Supply VPPs involve electricity-generating DERs, such as solar-plus-storage systems, which can be aggregated and controlled as a single resource when needed. Demand VPPs build off traditional demand response programs by aggregating curtailable load at a scale that can have a meaningful impact on the grid. Mixed Asset VPPs include a mix of both supply and demand resources.

While the benefits of VPPs are clear, the pathway to greater deployment is not. However, state policymakers are currently testing a variety of methods to encourage their development. Common approaches include a mix of mandates for utilities to procure energy from VPPs, incentives for utility customers to deploy DERs and participate in utility programs, and market access reforms to allow third-party aggregators to participate. Different varieties of these approaches have been considered by several states and utilities over the past year.

California

The California Energy Commission (CEC) approved a new incentive program for VPPs in July 2023. The Demand Side Grid Support (DSGS) program compensates eligible customers for upfront capacity commitments and per-unit reductions in net energy load during extreme events achieved through reduced usage, backup generation, or both. Third-party battery providers, publicly-owned utilities, and Community Choice Aggregators (CCAs) are eligible to serve as VPP aggregators. At a minimum, each individual customer site participating in the program must have an operational stationary battery system capable of discharging at least 1 kW for at least 2 hours. Incentive payments will be made to VPP aggregators based on the demonstrated battery capacity of an aggregated VPP. VPP aggregators will then allocate incentive payments between the VPP aggregator and its participants based on their own contractual agreement.

California lawmakers are also currently considering legislation to stimulate the market for VPPs. S.B. 1305 requires the California Public Utilities Commission to estimate the resource potential of VPPs in the state, and to develop procurement targets for each utility to be achieved by December 31, 2028 and December 31, 2033.

Colorado

The Colorado Public Utilities Commission opened a new proceeding in September 2023 to explore third-party implementation of virtual power plant pilots in Xcel Energy’s service area. The Commission issued a decision in April 2024 requiring Xcel to issue an RFP for a distributed energy management system (DERMS), which would then be used to manage a VPP. The Commission stopped short of directing Xcel to file a VPP tariff, but speaks of their merit and suggests that Xcel should propose  separate “prosumer tariffs” for residential and non-residential customers, including different aggregation capacities.

Georgia

A stipulation agreed to by the Public Interest Advocacy Staff and Georgia Power in its 2023 Integrated Resource Plan Update proceeding commits the utility to developing a residential and small commercial solar and battery storage pilot program that will provide grid reliability and capacity benefits. Georgia Power will work with interested stakeholders to develop the program and will file it for approval with its 2025 Integrated Resource Plan.

Hawaii

In December 2023, the Hawaii Public Utilities Commission approved a new VPP program for the Hawaiian Electric Companies (HECO). The Bring-Your-Own-Device (BYOD) will replace HECO’s Battery Bonus Program and will provide varying levels of incentives based on the value of the grid services provided. The program will only allow energy storage systems at first, but may be expanded in the future to include other DERs.

Maryland

The Maryland General Assembly enacted a bill in April 2024, which opens the door to VPPs in the state. H.B. 1256 requires investor-owned utilities in the state to develop pilot programs to compensate owners and aggregators of DERs for distribution system support services. The programs must be filed for approval with the Public Service Commission by July 1, 2025.

Michigan

Michigan lawmakers introduced legislation in 2024 related to VPPs. S.B. 773 requires the Public Service Commission to develop requirements for programs that would allow behind-the-meter generation and energy storage owners to be compensated for services they provide to the distribution system, including through aggregators of DERs. Utilities would then need to file applications for these programs during their rate cases.

Massachusetts

In January 2024, the state’s three investor-owned utilities filed their Electric Sector Modernization Plans (ESMPs) with the Commission for approval. The three ESMPs include plans to invest in DERMS and customer programs to advance VPPs.

For more states, click here. 

Brian Lips is a senior energy policy project manager for the NC Clean Energy Technology Center. He manages the Database of State Incentives for Renewables & Efficiency (DSIRE).

The U.S. recently exceeded five million solar installations, with the residential sector accounting for 97% of all solar installations in the U.S., according to data from the Solar Energy Industries Association (SEIA) and Wood Mackenzie.

A recent report, The state(s) of distributed solar—2023 update from the Institute of Local Self Reliance (ILSR), estimates that 29 GW of solar capacity was installed in 2023; 31% of which is distributed solar. Distributed solar is solar that is owned by individuals, small businesses and public entities—and is generated at or very near the site where it is used.

The map below shows how much distributed solar was installed in each state through 2023, relative to population.

For the purposes of the map, community solar in Colorado, Hawaii, Illinois, Maryland, Massachusetts, Minnesota, New Jersey, New York, and Oregon is included as distributed solar.

To arrive at these figures, ILSR added its own figures on state community solar capacity to the U.S. Energy Information Administration’s (EIA) figures on small-scale photovoltaic capacity by state. This sum was divided by state population estimates from the U.S. Census Bureau, resulting in a figure of watts per person. The U.S. EIA did not collect data from Alabama or North Dakota.

A key finding is that 21 states and the District of Columbia have a distributed solar saturation of more than 100 watts per capita.

California, Arizona, Nevada, and Massachusetts all land in the top ten for both distributed solar saturation and total solar generation capacity.

California, Texas, Florida, and North Carolina have the largest overall capacity whereas Hawaii, Massachusetts, Rhode Island and California have the greatest distributed solar saturation, as measured in installed distributed solar capacity per capita.

Several state solar markets have made significant changes since ISLR’s 2022 update. Installed distributed capacity grew by more than 1 GW in Texas (6 GW), California (4.7 GW), Florida (2.5 GW), Ohio (1.8 GW), Virginia (1.2 GW), and Colorado (1.1 GW).

Five states doubled or more than doubled installed capacity in 2023, including South Dakota, Ohio, Pennsylvania, West Virginia, and Arkansas. While doubling capacity is good news, it still may not amount to much as both South Dakota and West Virginia are considered “solar laggards” according to PV Intel’s analysis, based on EIA data.

Other states that saw strong growth include Wisconsin, Indiana, Montana, Louisiana, Maine, and Michigan.

Community solar

Community solar provides a way for people to benefit from solar energy who may be unable to install solar either due to financial restrictions or because they do not have a suitable rooftop for solar.

ILSR’s 2024 Community Power Scorecard states that “a model community solar policy has no cap, has a fair compensation rate, simplifies the billing process for subscribers, meaningfully accounts for the challenge of reaching low- and moderate-income (LMI) subscribers, and rewards other beneficial development or small subscriber-friendly practices”.

ILSR reports that state policies like community solar, net metering, simplified interconnection rules and a renewable portfolio standard carve-out for distributed energy are crucial in promoting the adoption of distributed solar.

The distributed solar report notes that 19 states and the District of  Columbia currently have community solar policies and highlights nine states that ILSR calls “solar-enabling” for their strong community solar policies and installed capacity.

Total installed community solar capacity at the end of 2023:

1. New York 1.72 GW
2. Minnesota 904 MW
3. Massachusetts 852 MW
4. Illinois 251 MW
5. Maryland 149 MW
6. Colorado 147 MW
7. New Jersey 137 MW
8. Oregon 29 MW
9. Hawaii 4 MW

ILSR tracks these policies and others in its Community Power Map. According to the ILSR’s Community Power Scorecard, 26 received failing grades in 2024, suggesting that many states have much room for improvement.

ILSR’s State(s) of Distributed Solar analysis is updated annually. For a historical snapshot, explore archived analyses of distributed solar by state in 2022, 2021, 2020, 2019, 2018, 2017, and 2016.