Santee Cooper Solar Farm Becomes South Carolina’s First Gold Certified Solar Habitat
January 4, 2022
by Vanessa Nikolic
APPA News
January 4, 2022
South Carolina public power utility Santee Cooper’s Jamison Solar Site, a 1.2-megawatt facility located on over 5 acres in Orangeburg, has become South Carolina’s first Gold Certified Solar Habitat Site.
To become a Gold Certified Solar Habitat, Santee Cooper had to commit to planting a variety of native flowering plants underneath and around the site’s 4,482 solar panels.
The plantings of native pollinator plants provide added ecological benefits to solar arrays. It aids in reducing soil erosion, protecting water quality and enhances the aesthetic of a solar site.
South Carolina governor Henry McMaster signed the Solar Habitat Act into law in 2018. Under the authority of the law, the South Carolina Department of Natural Resources (SCDNR) established “Technical Guidance for the Development of Wildlife and Pollinator Habitat at Solar Farms” and worked with Clemson University’s Department of Fertilizer Regulation and Certification Services to develop the S.C. Certified Solar Habitat Program.
The South Carolina Solar Habitat Act provides a framework to encourage owners of commercial solar energy generation sites to follow voluntary site management practices that provide native perennial vegetation beneficial to songbirds and pollinators, and reduce stormwater runoff and erosion at the solar generation site.
“We are pleased that Jamison Solar Farm is the first Gold Certified Solar Habitat in the state and even more pleased to help lead the way to more certified solar habitats across South Carolina,” Santee Cooper Chief Power Supply Officer Marty Watson said.
Watson said creating the habitat for pollinators is a way the public power utility puts its environmental stewardship into action. He also recognizes the guidance of the team at SCDNR.
For more information about the S.C. Solar Habitat Program, visit www.dnr.sc.gov/solar.
Secretary of Energy Visits SMUD Battery Storage Site, Training Facility
December 19, 2021
by Paul Ciampoli
APPA News Director
December 19, 2021
Secretary of Energy Jennifer Granholm on Dec. 17 visited a Sacramento Municipal Utility District (SMUD) solar farm and battery storage facility in south Sacramento, Calif., as well as a SMUD facility that trains people to become highly skilled utility professionals.
Granholm was joined in her visit to the SMUD Power Academy by U.S. Rep. Ami Bera, D-Calif., and SMUD CEO and General Manager Paul Lau.
Each year, the training facility produces 500 skilled trade professionals through 12 apprenticeship programs, supporting regional workforce development opportunities.
Granholm also toured SMUD’s Hedge solar farm and battery energy storage facility, along with Lau and Rep. Bera.
The energy storage units are part of SMUD’s first utility-scale battery energy storage project — and a major element in its 2030 Zero Carbon Plan.
The six units, which weigh about 52,000 pounds each, are part of a SMUD Energy Strategy, Research & Development department project that also includes a myriad of other SMUD employees from throughout the organization.
Combined, the lithium-ion batteries will generate 4 megawatts of electricity and store 8 megawatt hours of energy, which is enough to power 800 homes for 2 hours. Inside each of the 6 units are 3,840 battery cells stacked and connected together.
They will soon be fully operation, but SMUD will continue to gather and research data. SMUD will learn about the feasibility of utility-scale battery storage and the practicality of reserve power at a large scale for future grid integration into SMUD’s Battery Energy Storage System, known as BESS.
According to SMUD, Granholm spoke about the criticality of achieving a clean energy future and the need for workers that can build the grid of the future, bringing good paying jobs.
She praised SMUD’s leadership for setting an example for the nation to follow in both setting such an ambitious goal to achieve zero carbon by 2030 and in training the utility workers of the future through the Power Academy, SMUD noted.
Granholm said that SMUD’s example “of how we can get” to clean, dispatchable baseload power “is what we want to take across the nation.”
She also said that “if we want to build out all of this clean electricity, we have to build out transmission for that clean electricity. That means we’re going to need the workers to be able to build that out.” The example being set by SMUD “is to create good jobs for people to be able to install the kinds of technologies” including the transmission grid.
“It was an honor to give U.S. Energy Secretary Granholm and Congressman Bera a tour of SMUD’s Hedge solar farm and battery energy storage facility and the adjacent Sacramento Power Academy,” Lau said.
He thanked Secretary Granholm for recognizing SMUD’s clean energy leadership.
“We’re proud and excited to be pursuing the boldest clean energy goal of any large utility in the country — to remove 100% of all carbon emissions from our power supply by 2030. The Secretary and I agree, we have to act with urgency to address the impact of climate change and create a clean energy future for all. And to get there, we’ll need skilled utility workers in good-paying jobs,” Lau said.
“That’s why inclusive workforce development is a key part of our Zero Carbon Plan. Sacramento’s Power Academy is training people to build and maintain the grid our clean energy future needs and will create good-paying jobs,” he said.
Lau discussed SMUD’s zero carbon plan in an episode of the American Public Power Association’s Public Power Now podcast earlier this year.
New York Governor Unveils Framework For State To Achieve At Least 10 GW of Distributed Solar
December 19, 2021
by Paul Ciampoli
APPA News Director
December 19, 2021
New York Gov. Kathy Hochul on Dec. 17 unveiled a framework for the state to achieve at least 10 gigawatts (GW) of distributed solar by 2030.
The roadmap was submitted by the New York State Energy Research and Development Authority (NYSERDA) and the New York State Department of Public Service (DPS) to the New York Public Service Commission for public comment and approval.
The announcement supports the state’s Climate Leadership and Community Protection Act mandate to generate 70 percent of the state’s electricity from renewables by 2030.
The roadmap proposes a comprehensive strategy to expand the state’s NY-Sun initiative into one of the largest and most inclusive solar programs of its kind in the nation.
NYSERDA and DPS evaluated multiple strategies to deploy 10 GW or more of distributed solar — projects that are under five megawatts (MW) in size, including rooftop installations and community solar projects — by 2030 and determined that extending the NY-Sun initiative provides the most efficient, familiar, and cost-effective path forward.
The roadmap proposes at least 1,600 MW of new solar capacity to benefit disadvantaged communities and low-to-moderate income New Yorkers, with an estimated $600 million in investments serving these communities.
It also proposes at least 560 MW to be advanced through the Long Island Power Authority and at least 450 MW to be built in the Con Edison electric service area.
The roadmap is available for public comment on the DPS website and subsequent decision-making in 2022.
Since the NY-Sun initiative was launched, NYSERDA has worked closely with local governments, agricultural communities, other state agencies, and a wide range of stakeholders to ensure that projects are developed and sited in a manner that fully considers land use and are advanced in close collaboration with local stakeholders and agricultural communities.
NYSERDA will extend its ongoing technical assistance for all municipalities in the state to assist localities in aligning solar development with local priorities.
Platte River Power Authority Seeks Solar Supply, Encourages Storage Proposals
December 16, 2021
by Paul Ciampoli
APPA News Director
December 16, 2021
Colorado-based Platte River Power Authority recently issued a request for proposals (RFP) for up to 250 megawatts (MW) of new photovoltaic solar generating capacity that could begin producing energy by 2025.
Platte River encourages any proposed project to include a battery energy storage component. The RFP also enables bidders to propose installations that could interconnect anywhere on Platte River’s transmission system, including the distribution systems in the owner communities of Estes Park, Fort Collins, Longmont and Loveland.
“As we continue to work toward achieving the resource diversification policy goal, our ongoing challenge will be to maintain Platte River’s core pillars to safely provide reliable, environmentally responsible and financially sustainable energy and services during a time of rapidly improving technology and resource costs,” said Jason Frisbie, general manager and CEO of Platte River.
The resource diversification policy was adopted by Platte River’s Board of Directors in 2018. The policy calls for leadership to pursue a 100% noncarbon energy mix by 2030, provided the organization’s core pillars are upheld.
In 2020, Platte River maintained 100% transmission system reliability and provided power to its owner communities at the lowest wholesale rates in Colorado.
With an additional 250 MW of solar generating capacity, Platte River estimates its overall annual energy production will be approximately 54% noncarbon.
Developers are encouraged to consider proposing projects that could interconnect with Platte River’s transmission system, including regions in northwest Colorado and the northern Front Range.
Particular consideration may also be granted to smaller projects (25 megawatts or less) that could connect to the distribution systems of one or all of Platte River’s owner communities.
Within each project proposed, developers are encouraged to include a battery energy storage component capable of providing 100% of the project’s nameplate capacity for at least four hours and be dispatchable by Platte River when needed.
Proposals are due Feb. 18, 2022, after which Platte River will develop a short list of potential projects that add up to approximately 250 megawatts and sign power purchase agreements later in the year.
The RFP is available here.
California PUC Proposes Net Metering Reforms To Support Storage, Social Equity
December 15, 2021
by Peter Maloney
APPA News
December 15, 2021
The California Public Utilities Commission (CPUC) this week issued a proposal that would reform the state’s net metering rules for investor-owned utilities and encourage their residential customers to combine energy storage with solar power systems.
The “Proposed Decision determines that NEM [Net Energy Metering] rules must be modernized to incentivize customers to install storage paired with rooftop solar to help California meet its net peak shortfall and ensure grid reliability,” the commission said in an announcement on the proposed decision.
The proposed decision also includes a grid participation charge and provisions aimed at making access to renewable energy more equitable.
While CPUC decisions apply only to investor owned electric and natural gas utilities and not public power utilities, the commission’s effort has a broad impact on the state’s electric grid.
According to the commission, its NEM policies have “enabled 1.3 million customers to install roughly 10,000 megawatts of customer-sited renewable generation, almost all of which is rooftop solar” and have resulted in a reduction of midday demand on the grid by as much as 25 percent. With a total of 25 gigawatts (GW) of installed solar power, needs have shifted. “It is now essential to address grid reliability shortfalls during ‘net peak’ hours,” the commission said.
With its high penetration of solar power, California typically has a surfeit of renewable energy in the middle of the day that falls off as the sun sets and peak demand rises in the evening, requiring sources such as gas-fired power plants to ramp up quickly to fill the peak demand shortfall.
The proposed decision would be the third reform of California’s net metering regime since it was mandated by a 2013 state law, Assembly Bill 327. The CPUC revised the original program in 2016, creating NEM 2.0.
The proposed decision would revise the CPUC’s current NEM rules and create a Net Billing Tariff that the commission says would provide more accurate price signals that would promote greater adoption of customer-sited storage with the aim of helping the state decrease its dependency on fossil fuels during the early evening hours.
Under the new system, a customer would be allowed to “oversize” their solar system to cover 150 percent of their historical load in order to enable future electrification.
Net billing customers would be required to sign up for electric rates with high differentials between peak and off-peak prices in order to incentivize energy conservation or the use of stored solar energy during the net peak window of 6 p.m. to 9 p.m.
The proposal would also move residential customers from annual billing to monthly billing in an effort to help them avoid unexpectedly large bills at the end of their 12-month billing period.
The proposed decision would also establish a Storage Evolution Fund to provide storage rebates to existing NEM 2.0 customers who transition to the Net Billing Tariff in the next four years.
And the proposal would transition residential NEM 1.0 and 2.0 customers, except for low-income customers, to the Net Billing Tariff after 15 years of being interconnected to the electric grid. The aim, the commission said, is to incentivize the adoption of energy storage and “reduce the costs paid by other ratepayers by billions of dollars.”
The proposed decision also includes a bill credit for net billing customers to ensure they can pay for a solar-plus-storage energy system in 10 years or less through electric bill savings. The monthly market transition credit would start at up to $5.25 per kilowatt (kW) for residential solar-plus-storage and solar-only systems and would step down by 25 percent a year for four years. Once locked in, the credit lasts for 10 years.
In its proposed decision, the CPUC also aims to address disparities that have come about because of earlier iterations of its NEM policies. The new net metering regime would adopt a monthly residential Grid Participation Charge of $8 per kW of installed solar in an effort to capture residential adopters’ fair share of costs to maintain the grid and fund public programs.
“An independent third-party evaluation of NEM 2.0 found that its costs substantially exceed its benefits as residential NEM 2.0 participants only pay 9 to 18 percent of what it costs their utilities to serve them, even considering the value of the energy produced by their NEM systems,” according to the CPUC. Meanwhile, ratepayers without net metered solar systems, many of whom are low income, pay “significantly higher electricity rates due to NEM.”
Households without NEM solar systems are estimated to pay $67 to $128 more per year due to the costs of the NEM programs and those costs are likely to increase without reforms, according to a report from the Public Advocates Office,
Under the new NEM regime, California’s investor-owned utilities could expect more revenue to cover grid access and maintenance costs. The commission estimates the grid participation charge less the market transition credit would net a monthly fixed charge in 2023 of $6.38 per kilowatt for customers of Pacific Gas and Electric (PG&E), $8/kW for San Diego Gas and Electric (SDG&E) customers, and $4.41/kW for Southern California Edison (SCE) customers. For a 5kW solar system that would translate into fixed monthly charges of $31.90 for PG&E residential customers, $40 for SDG&E customers, and $22.05 for SCE customers.
In further support of social equity, the proposed decision creates an equity fund with up to $600 million to improve low-income customer access to distributed clean energy programs. A stakeholder process will determine the allocation of funds, which could go toward incentives for distributed storage, community solar in low-income and disadvantaged communities, or other low-income clean energy programs with strong consumer protections. Additional measures aim to provide incentives for distributed solar-plus-storage for low-income and tribal households, including an exemption from the Grid Participation Charge.
The proposed decision will be on the CPUC’s Jan. 27, 2022, voting meeting agenda.
TVA Executives Detail Efforts To Create Visibility Tied To EVs, Renewable Energy
December 15, 2021
by Paul Ciampoli
APPA News Director
December 15, 2021
Executives with the Tennessee Valley Authority (TVA) recently detailed how TVA is taking steps to create visibility tied to the impact of electric vehicles (EVs) on the power system and EV needs for electricity consumption, as well as where renewable energy resources are being developed.
Laura Duncan, TVA’s Manager for Commercial Energy Solutions, and Drew Frye, TVA’s Manager for Commercial Energy Services, made their comments on Dec. 2 during the American Public Power Association’s Public Power Forward Virtual Summit.
The TVA officials participated in a panel that detailed how utilities locate resources — from customers with EVs to industrial customers with a solar farm — and account for new load from charging stations.
“We have seen an uptick over the last year or so in EV adoption,” Frye said. EV sales in the TVA region have grown by a compound average of 49% annually over the past three years.
“It’s something we’re tracking and understanding what the impacts could be to TVA and the 153 local power companies, munis and cooperatives that distribute TVA’s electricity,” he said.
TVA plans for the future “understanding that there’s a lot of investment going into making electrified vehicles. Pretty much every automaker has committed” to some kind of electrification strategy,” Frye said.
TVA is forecasting more than 200,000 EVs in its service territory by 2028 and 780,000 by 2035, which would add 2% to TVA’s total energy demand.
Smart Charge Nashville Project
Frye offered details on a project called Smart Charge Nashville in an effort to understand the impact of EVs on the power system and their needs for electricity consumption. TVA partnered with public power utility Nashville Electric System (NES), among others.
Under the project, EV drivers were incentived to plug in data loggers into their cars. “That really gave us all of the information off of the vehicle,” he noted.
“We used this project to do kind of a baseline EV load shape for the first year,” Frye said. The second year involved testing out different EV charging load management strategies “to see if we could change charging behaviors and therefore potentially change the impacts for the local distribution system or for TVA for charging requirements.”
As far as what the project discovered in terms of charging patterns, “we learned that almost all charging happens at home – in a garage or in a parking lot. Upwards of eighty percent, depending on what electric vehicle type that they had. And when they had access to charging at work and at home, close to ninety percent of charging happened at those two locations.”
He said that relatively speaking, there was a small amount of charging occurring over the public charging network and even smaller amounts of that charging happening at fast chargers along highways.
As to the time of the day that the electric vehicles charged, Frye said it was “all over the map.” He said that some EVs “were going three days before they charged up again,” while others were charging up every night using a 120-volt charger “which was basically one kilowatt for the whole night.”
Frye said that “what we found out is diversification of charging is really our friend and the peaks of when most electric vehicles are charging simultaneously really start to pop up on high driving days like the day before holidays.”
Meanwhile, Duncan provided details about TVA’s renewable energy efforts. She noted that today, the power that TVA delivers is nearly 60 percent carbon free, which includes nuclear power, “and in the last 20 years we’ve facilitated over 4,000 solar installations and we’ve brought over $2 billion to the Valley through our renewable investments and provided nearly 1.5 million people access to community solar.” These efforts are being done in partnership with local power companies.
“We are planning to add 10,000 megawatts of solar by 2035,” Duncan said.
“One of our key lessons learned in developing and offering renewable programs in a dynamic market is there’s really not a one size fits all solution for customers that are interested in renewable energy,” she noted. “We’ve developed a suite of flexible solutions that will best meet the needs of a wide range of customers.”
TVA’s customers “all of have unique sustainability and carbon goals,” Duncan said. Solutions can include rooftop solar, renewable energy certificate purchase programs, and new solar projects.
“These solutions really facilitate partnerships that help us to further develop future solutions” and help to ensure visibility and coordination on where this renewable energy is being developed “on our system – both for TVA and at the distribution scale for the local power companies.”
Peninsula Clean Energy Signs Wind Farm Power Purchase Agreement
December 11, 2021
by Paul Ciampoli
APPA News Director
December 11, 2021
Scout Clean Energy and California community choice aggregator (CCA) Peninsula Clean Energy have signed a 15-year Power Purchase Agreement (PPA) that will provide San Mateo County and City of Los Banos customers with 76.35 megawatts (MW) from the repowering of the Pacheco Pass Wind Farm in Merced County, Calif.
Construction will begin in late 2023 and the project will replace the existing 162-turbine wind farm in Pacheco State Park, originally built nearly four decades ago, with a much-smaller fleet of far more powerful state-of-the-art turbines that are expected to be operational by around the end of October 2024.
While the existing 162 turbines produce 16.5 MW, Scout is planning a total capacity of 147.5 MW of wind energy and a 50-MW four-hour Battery Energy Storage System. The completed project upgrades would be one of the first repower projects on state land in California.
GRWF will be located about 10 miles from the groundbreaking 200-MW Wright Solar Project, which in January 2020 became the largest renewable energy installation at the time ever built for a CCA to officially go online.
Wright Solar was Peninsula Clean Energy’s first project located in Merced County and California’s Central Valley.
Peninsula Clean Energy is the official electricity provider for San Mateo County and, beginning in 2022, for the City of Los Banos.
Founded in 2016, the agency serves 295,000 customers by providing more than 3,500 gigawatt hours annually of electricity.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
New River Light and Power Green Power Program Nominated for Cleantech Innovation Award
December 1, 2021
by Vanessa Nikolic
APPA News
December 1, 2021
North Carolina public power utility New River Light and Power’s (NRLP) Green Power Program has been nominated for a 2021 Cleantech Innovation Award from the Research Triangle Cleantech Cluster (RTCC).
RTCC is an initiative of business, government, and nonprofit leaders focused on advancing the growth of the regional and statewide clean technology (cleantech) economy.
With its Third Annual Cleantech Innovation Awards, RTCC aims to recognize the contributions of the companies, organizations, and individuals that have advanced cleantech solutions across North Carolina. The awards are judged by leaders from the cleantech industry and public sectors.
NRLP’s Green Power Program is nominated under the Cleantech Impact: Energy category which recognizes an energy project that applies cleantech to create positive impacts for the environment, economy, and residents. Projects may include innovations to existing grid infrastructure to enhance resiliency, renewable energy installations, microgrid deployments, or innovative energy efficiency programs.
The Green Power Program provides residential and commercial customers with the opportunity to purchase clean energy. NRLP customers can choose to purchase blocks of hydroelectric power to offset their monthly carbon-based electric use. Each block costs $5 and represents 250 kilowatt-hours (kWh) of clean energy.
NRLP launched the program and made it available to customers at the beginning of August 2021. Prior to its launch, plans to offer the program were in the works for a number of years as customers became more interested in renewable energy.
The utility conducts customer surveys every three years through ElectriCities of North Carolina. NRLP’s 2020 customer survey found that 65% of its residential customers indicated they would be willing to pay an additional $5 on their monthly bill to obtain 30% of their electricity from renewable sources.
NRLP public communications specialist Chris Nault said the nomination recognizes and supports the utility’s commitments to providing clean energy and outstanding service to its customers and the community.
“This nomination for a 2021 Cleantech Innovation Award is an honor for NRLP and App State,” Nault said. “It is great to know that our hard work and service to our customers is being recognized by an organization like the Research Triangle Cleantech Cluster.”
The winners in each category will be announced at an awards ceremony on Wednesday, December 8 in Raleigh, North Carolina.
For a complete list of nominees, visit https://www.researchtrianglecleantech.org/cleantechawards2021.
NRLP was previously nominated for a 2019 Cleantech Innovation Award for Grid Innovation related to the deployment of technology on its electric grid. Additional details on the 2019 nomination can be found here.
NRLP is an electric utility, owned by Appalachian State University, that serves nearly 9,000 residential and commercial customers in Boone, North Carolina and the surrounding community. The Green Power Program is made possible through NRLP’s new wholesale power agreement with Carolina Power Partners, effective January 2022.
The NRLP Green Power Program is a component of Appalachian State University’s commitment to reduce its use of fossil fuels and provide an option for NRLP customers to do the same.
Interior Approves Second Major Offshore Wind Project
November 29, 2021
by Peter Maloney
APPA News
November 29, 2021
The Department of the Interior (DOI) last week said it approved a 132-megawatt (MW) wind farm off the coast of Rhode Island.
It is the second commercial scale offshore wind farm approved by the DOI.
In July, the federal agency approved Vineyard Wind I, an 800-MW project being jointly developed by Copenhagen Infrastructure Partners and Avangrid Renewables, about 15 miles south of Martha’s Vineyard and 35 miles from the Massachusetts coast. The project is scheduled to come online in mid-2024.
The newly approved South Fork Wind project, being jointly developed by Ørsted and Eversource, is sited about 19 miles southeast of Block Island, Rhode Island, and 35 miles east of Montauk Point, New York.
The DOI’s Bureau of Ocean Energy Management (BOEM) approved the construction and operation of 12 or fewer turbines off Rhode Island. The project is on track to be fully permitted by early 2022, according to the developers, who say they will soon ramp up construction activities. Prior to construction, South Fork Wind must submit a facility design report and a fabrication and installation report, providing details for how the facility will be fabricated and installed. The project is expected to come online in late 2023.
In March, a group including the New York State Public Service Commission and the Long Island Power Authority (LIPA), agreed to and adopted a plan to build a 7.6-mile transmission line to link the South Fork Wind project to New York State’s power grid via a substation in the Town of East Hampton in Suffolk County on the east end of Long Island. The transmission line is due online by 2023.
In 2017, LIPA’s board of trustees approved a power purchase agreement with the developers of the South Fork Wind project.
The approvals help New York State move closer to its goal of economy-wide carbon dioxide neutrality and a zero-carbon dioxide emissions electricity sector by 2040. The state’s energy plan includes a commitment to develop over 1,800 MW of offshore wind by 2024.
In a wider framework, the approval of the South Fork Wind project helps support the goal set by the administration of President Joe Biden to deploy 30 gigawatts (GW) of offshore wind energy by 2030.
As part of that effort, the administration is looking at the potential sale of up to seven new offshore leases for wind power projects by 2025.
BOEM said it expects to review at least 16 construction and operations plans of commercial offshore wind energy facilities by 2025, representing more than 19 GW of clean energy.
NREL Reports Continuing PV And PV-Plus-Storage Cost Declines
November 29, 2021
by Peter Maloney
APPA News
November 29, 2021
A new report from the National Renewable Energy Laboratory (NREL) finds continued cost declines across residential, commercial, and industrial photovoltaic (PV)-plus-storage systems, with the greatest cost declines for utility-scale systems. Standalone storage systems also saw cost declines.
The findings were included in NREL’s U.S. Solar Photovoltaic System and Energy Storage Cost Benchmark: Q1 2021, which was released this month. Starting with NREL’s 2020 PV benchmark report, NREL began including PV-plus-storage and standalone energy storage costs in its annual reports.
Meanwhile, NREL’s new report also finds that costs continued to fall for residential, commercial rooftop, and utility-scale PV systems—by 3%, 11%, and 12%, respectively, compared to last year.
In a change from previous years’ reports, balance of systems costs have increased or remained flat across sectors this year. However, this increase in balance of systems cost was offset by a 19% reduction in module cost, causing overall costs to continue their decade-long decline.
NREL said that the report’s authors used a bottom-up cost modeling approach that accounts for all system and project development costs incurred during installation to model the costs for residential, commercial, and utility-scale PV systems, with and without energy storage.
They also modeled typical installation techniques and business operations from an installed-cost perspective. NREL said this strategy ensures that hardware costs reflect the actual purchase price of components as well as the sales price paid to the installer, including profits. The benchmarks assume a business environment unaffected by the novel coronavirus pandemic and represent national averages.
“As the costs of construction-related raw materials have increased during the pandemic, the total balance of systems material cost has either stayed relatively the same, or, in some cases, increased by a marginal percentage compared to the balance of systems cost reported in the Q1 2020 benchmark report,” said NREL’s solar and storage techno-economic analyst Vignesh Ramasamy.
“The major cost drivers that helped reduce the system installation costs of PV and energy storage systems in Q1 2021 were lower module cost, increased module efficiency, and lower battery pack cost,” he said.
In a second report, Photovoltaic Module Technologies: 2020 Benchmark Costs and Technology Evolution Framework Results, NREL researchers calculate a minimum sustainable price (MSP) — the price necessary to support a sustainable business over the long term — for modules.
Specifically, the report calculates that price by using bottom-up manufacturing cost analysis and applying a gross margin of 15%.