Ditto Urges Senate To Retain Direct Pay Energy Tax Credit Provisions
December 1, 2021
by Paul Ciampoli
APPA News Director
December 1, 2021
The U.S. Senate should keep the provisions of the Build Back Better Act that will ensure that all electric utilities and their customers benefit from tax incentives encouraging investments to transition to cleaner energy technologies, investments that are needed to reduce greenhouse gas emissions, Joy Ditto, President and CEO of the American Public Power Association (APPA) said in a Nov. 30 letter to Sen. Ron Wyden, D-Ore.
“Similar to the direct pay provisions of your Clean Energy for America Act (S. 2118), enactment would mean that all utilities, not just for-profit utilities, can directly benefit from these energy tax credits,” wrote Ditto in her letter. “This will make these incentives fairer and more effective.”
Wyden is Chairman of the Senate Committee on Finance.
Ditto noted that federal tax expenditures are the primary tools that Congress uses to incentivize energy-related investments.
However, tax-exempt entities– including public power utilities, rural electric cooperatives, and other not-for-profit entities — cannot directly claim such incentives.
“In effect, not-for-profit utilities serving nearly 30 percent of utility customers in the U.S. are effectively locked out of owning facilities being incentivized by such credits – wind, solar, energy storage, etc. This explains why 80 percent of the nation’s (non-hydropower) renewable energy generating capacity is owned by merchant, for-profit, generators,” Ditto said.
The Build Back Better Act (H.R. 5376) addresses this inequity by allowing the direct payment of energy tax credits – including production, investment, and carbon capture tax credits – to any entity that owns the project, she went on to say in the letter.
“This would remove the financial disincentive for public power utilities to own such facilities, which are needed to transition to cleaner energy technologies needed to address climate change. It would also allow the full value of these credits to pay for additional clean energy investments that will benefit the more than 90 million Americans nationwide served by tax-exempt, not-for-profit electric utilities,” wrote Ditto.
“We strongly encourage Congress to take the steps needed to make these tax credits both more effective and more equitable for public power utilities and the communities they serve.”
The House passed the Build Back Better Act in November, sending it to the Senate for consideration. Senate Majority Leader Charles Schumer, D-N.Y., has indicated that he would like the Senate to take up the reconciliation bill in December.
Planning Is Underway For Project That Will Bring Power To Navajo Nation Residents
November 30, 2021
by Paul Ciampoli
APPA News Director
November 30, 2021
Planning for Light Up Navajo III, which will connect Navajo Nation families to the power grid, is underway. Public power utilities are encouraged to consider participating in Light Up Navajo III, which will start in the spring of next year.
The American Public Power Association (APPA) is working with the Navajo Tribal Utility Authority (NTUA) to help volunteers continue to bring electricity to families in need.
Light Up Navajo III is scheduled to take place from April through June of 2022.
“This project has become a godsend for so many families that are waiting for the day to be able to store fresh food in a refrigerator, to be able to turn on the lights when the sun goes down and the young ones can do their homework without using a flashlight,” said NTUA General Manager Walter Haase. “It is our hope that our sister APPA companies will send their crews to help bring positive change. For every family we connect, there is another one waiting.”
In 2019, NTUA partnered with APPA to create an innovative, pioneer project called Light Up Navajo. The goal was to connect Navajo homes to the electric grid. There were 138 visiting line workers who traveled to Navajo Nation for the six-week pilot project. Electricity was extended to 233 regional families. The success of the pilot project paved a path for future Light Up Navajo projects.
In August 2019, NTUA officials said there would be another year of “Light Up Navajo” based on the outcome of the pilot project. NTUA was preparing for Light Up Navajo II for spring 2020. However, citing growing uncertainty tied to the COVID-19 pandemic, NTUA ipostponed the Light Up Navajo II project in 2020.
In an August 2021 episode of APPA’s Public Power Now podcast, Delaware Municipal Electric Corporation’s Kimberly Schlichting, Gary Johnston of the Lewes Board of Public Works in Delaware, and Joshua Little of the Town of Smyrna, Delaware, discussed the Light Up Navajo project.
Interested public power utilities should contact lightup-navajoproject@ntua.com for more information on this important event.
Wells Fargo, D.E. Shaw Close Tax Equity Deal For Solar-Storage Project
November 30, 2021
by Peter Maloney
APPA News
November 30, 2021
Units of Wells Fargo and D.E. Shaw this week closed on a tax equity financing for a solar-plus-storage project in McKinley County, N.M.
The Arroyo Solar and Storage project is a 300-megawatt (MW) solar array combined with a 150 MW, 600-megawatt hour (MWh) battery energy storage system that was originally developed by Centaurus Renewable Energy.
Centaurus closed on a $70 million construction bridge loan for the project from Voya Investment Management in late June. D. E. Shaw Renewable Investments (DESRI) acquired the project from Centaurus in September.
The first phase of the Arroyo project is expected to begin commercial operation in June 2022 with full operation expected in the fall of 2022.
Arroyo is currently under construction with efforts being made to hire workers locally and from the Navajo Nation. The project is expected to generate as many as 250 jobs during construction.
D. E. Shaw and Wells Fargo’s Renewable Energy & Environmental Finance group have now closed on the long-term tax equity financing for the project. The value of the deal was not disclosed.
A tax equity financing usually involves a financial entity taking an equity stake in the project company in return for revenue streams and tax credits generated by the project.
At the end of a period of time, the tax equity investment in the project usually reverts or is bought back by the original developer or the project sponsor.
For the Arroyo project, Wells Fargo is the tax equity investor, spokeswoman Trina Shepherd said via email. D.E. Shaw provided the cash equity and is the project sponsor and has an option to buy out the tax equity investor at the end of the deal.
Solar-plus-storage projects are eligible for investment tax credits (ITC) for both the solar and storage portions of a project, if certain criteria are met. The ITC percentage for projects beginning construction in 2021 or 2022 is 26 percent of the value of the project.
The Arroyo project is Wells Fargo’s first tax equity investment in a project with co-located battery storage. It is D.E. Shaw’s first solar project with co-located battery storage to enter construction and financing.
The Arroyo project has two offtake contracts with Public Service Company of New Mexico, one for the solar output and one for the output from the storage system. The combined output of the project will supply a portion of the replacement capacity needed to retire the 847-MW San Juan coal plant in San Juan County, N.M., which is scheduled to retire at the end of 2022.
Sundt Construction is building the Arroyo solar facility. ECI of Billings, Mont., provided the design for the substation and switchyard that will be built by its EPC Services subsidiary. Tesla will supply and commission its Megapack battery units for the facility, and New Mexico-based Affordable Solar Installation will construct the battery energy storage system. SOLV Energy and Tesla will provide ongoing operations and maintenance services to the facility once it is in operation.
Nebraska’s Omaha Public Power District Celebrates 75th Anniversary
November 30, 2021
by Paul Ciampoli
APPA News Director
November 30, 2021
Nebraska public power utility Omaha Public Power District (OPPD) on Dec. 2 will celebrate the 75th anniversary of its creation.
“OPPD has powered the communities it serves through wars, floods and pandemics,” OPPD’s newsletter, The Wire, notes in an article about the anniversary.
The history of OPPD dates back to 1917, when the Nebraska Power Company was incorporated. On June 1 of the same year, the newly formed company acquired the property of the Omaha Electric Light and Power Company. In 1946, its customers numbered 83,507, gross revenues totaled $10,828,000, kilowatt-hour sales were 552,000,000 and generating capability had reached 119,000 kilowatts.
On Dec. 2, 1946, the state legislature created OPPD as a political subdivision of the state of Nebraska, which acquired the properties operated by the Nebraska Power Company.
In January 1965, the Eastern Nebraska Public Power District merged with OPPD, doubling the size of our service area to 5,000 square miles. With the merger, four counties were added to OPPD’s service area, which now covers all or part of 13 counties in southeastern Nebraska.
Click here for milestone and anniversary-related content posted on The Wire’s webpage.
A 75th anniversary video OPPD created for an employee celebration is posted here,
EPA And Department of Army Issue New Proposed WOTUS Definition
November 30, 2021
by APPA News
November 30, 2021
The U.S. Environmental Protection Agency (EPA) and the U.S. Department of the Army have proposed to reestablish the pre-2015 definition of “waters of the United States” (WOTUS).
The proposed rule is updated to reflect U.S. Supreme Court precedent, the agencies said.
The American Public Power Association (APPA) in September 2021 submitted comments in response to a request for recommendations to revise and refine the regulatory definition of WOTUS. In those comments, APPA advocated that a new definition must draw clear jurisdictional lines, provide needed predictability for the regulated community, and be consistent with the Clean Water Act and Supreme Court precedent.
In 2021, U.S. district courts in Arizona and New Mexico vacated the prior administrations Navigable Waters Protection Rule (NWPR). In light of the court actions, the agencies have been implementing the pre-2015 regulatory regime nationwide since early September 2021.
The agencies have indicated their intention to continue to consult with stakeholders to refine the definition of WOTUS in both implementation and future regulatory actions.
EPA and the Army are interpreting WOTUS to mean the waters defined by the longstanding 1986 regulations.
Therefore, in the proposed rule, the agencies interpret the term WOTUS to include:
- Traditional navigable waters, interstate waters, and the territorial seas, and their adjacent wetlands;
- Most impoundments of WOTUS;
- Tributaries to traditional navigable waters, interstate waters, the territorial seas, and impoundments that meet either the Army relatively permanent standard or the significant nexus standard; wetlands adjacent to impoundments and tributaries, that meet either the relatively permanent standard or the significant nexus standard; and
- “Other waters” that meet either the relatively permanent standard or the significant nexus standard.
The agencies interpret the significant nexus standard to mean “waters that either alone or in combination with similarly situated waters in the region, significantly affect the chemical, physical, or biological integrity of traditional navigable waters, interstate waters, or the territorial seas.”
Another amendment to the older regulations is to the term “relatively permanent standard,” which has been updated to mean waters that are “relatively permanent, standing, or continuously flowing and waters with a continuous surface connection to such waters.”
The proposal maintains the waste treatment system exclusion, returning to the 1986 regulatory version of that exclusion with ministerial changes made in the NWPR. The proposal would remove the favorable definition of waste treatment system that was codified in the NWPR.
For more information on the proposed rule and registering for the virtual public hearings, click here.
NERC Winter Report Says Extreme Cold Weather Could Cause Reliability Shortfalls
November 29, 2021
by APPA News
November 29, 2021
Certain regions of the country, particularly those vulnerable to extreme weather, natural gas supply disruptions and low hydro conditions, are at risk for electricity supply disruptions this winter, according to the North American Electric Reliability Corp. (NERC).
In its 2021–2022 Winter Reliability Assessment, NERC advises the industry to prepare by taking steps for generator readiness, fuel availability and sustained operations in extreme conditions.
Although anticipated reserve margins meet or surpass the NERC’s margin levels in all areas, the organization warned that “extreme or prolonged cold temperatures over a large area could create “unique challenges in maintaining grid reliability in many parts of North America.”
Responses NERC solicited from grid stakeholders indicate that they have taken preparations to enhance reliability during cold weather events, but “some plant vulnerabilities can be anticipated for the upcoming winter.”
To reduce the risk of shortfalls, NERC is recommending:
- Grid operators and generator operators review NERC’s Level 2 cold weather alert and take the recommended steps prior to winter;
- Grid operators should prepare their operating plans to manage potential supply shortfalls and take steps for generator readiness, fuel availability, and sustained operations in extreme conditions. And balancing authorities should poll their generating units in advance of approaching severe weather to assess their readiness for normal and extreme conditions;
- Balancing authorities and reliability coordinators should conduct drills on alert protocols, and balancing authorities and generator operators should verify protocols and operator training for communications and dispatch;
- Distribution providers and load-serving entities should review non-firm customer inventories and rolling black out procedures to ensure that no critical infrastructure loads such as natural gas or telecommunications would be affected and rehearse protocols that prepare customers for the impacts of severe weather.
“To be resilient in extreme weather, we are counting on our grid operators to proactively monitor the generation fleet, adjust operating plans and keep the lines of communication open,” Mark Olson, manager of reliability assessments at NERC, said in a statement.
NERC referenced last February’s cold weather that caused outages in Texas and other states, and said that peak demand or generator outages that exceed forecasts, such as have occurred in previous winters, “can be expected to cause energy emergencies” in the Midcontinent Independent System Operator (MISO), Southwest Power Pool (SPP), and Electric Reliability Council of Texas (ERCOT) regions.
While both New England and the Southwest have sufficient planning reserves, NERC warned that fuel supplies to generators in those areas can be vulnerable during cold weather conditions. NERC also highlighted New England and California for their vulnerability to weather related natural gas supply disruptions. Specifically, Southern California and the Southwest have limited natural gas storage and lack redundancy in supply infrastructure, so generators there also could face fuel supply curtailment or disruption from extreme winter weather.
In New England, the capacity of natural gas transportation infrastructure can be constrained when cold temperatures cause peak demand for both electricity generation and consumer space heating needs, exacerbating the risks for fuel-based generator outages and reductions, NERC noted.
In the Pacific Northwest, resources are sufficient but higher demand from extreme temperatures could cause shortfalls, particularly if the region’s drought continues and causes low hydro conditions, reducing electricity supply for transfer throughout the area, NERC warned.
MMWEC Taps APPA Grants To Study Emission Reduction Strategies, Undergrounding
November 29, 2021
by Peter Maloney
APPA News
November 29, 2021
Massachusetts Municipal Wholesale Electric Co. (MMWEC) has won Demonstration of Energy & Efficiency Development (DEED) grants totaling $148,248 from the American Public Power Association, one to help the joint action agency optimize its carbon dioxide (CO2) emission reduction strategies and the other to study the potential benefits of co-deploying undergrounding electric cables with optical fiber.
The more recent grant, for $25,050, aims to help MMWEC fulfill its mission to provide the most efficient, innovative and equitable path to greenhouse gas (GHG) emissions reductions for its member municipal light plant (MLP) communities.
For the grant, Incorporating Carbon as the Driver of MMWEC’s Energy Efficiency Program, MMWEC will work with the Center for EcoTechnology, which will conduct a study on how MMWEC and its member MLPs can assess the emissions reduction benefits of energy efficiency, building electrification, transportation electrification, renewable energy, demand response and energy storage. The study is expected to be completed in 2022.
“This project will undertake the critical steps necessary to develop the underlying assumptions, calculations and tools for quantifying carbon emissions associated with the evolving energy portfolios of MMWEC’s members, and the measures that MLPs incentivize,” Bill Bullock, sustainable energy policy and program senior manager at MMWEC, said in a statement.
The project aligns with commitments by MMWEC’s member MLPs to reach net zero carbon dioxide emissions in energy sales by 2050, in support of a Massachusetts strategy to reach net zero emissions by 2050.
But it is important to note that the value of this research will extend beyond Massachusetts to provide public power utilities across the country with valuable tools and knowledge to assist in making more informed, actionable steps towards a lower carbon future.
The first grant, for $123,198 was awarded in the spring and is being used to support Project Groundwork, a research initiative that will evaluate the potential benefits to public power utilities of deploying optical fiber broadband networks in combination with underground electric cabling to help bridge the digital divide.
MMWEC is working with the University of Massachusetts Amherst’s (UMass) Energy Transition Institute and Groundwork Data, a non-profit research initiative focused on public infrastructure, on the project.
“We’ve found that much of the existing research on undergrounding is concerned with the costs of trenching, and that there is little disagreement on the overall resiliency benefits,” Mike Bloomberg, head of Groundwork Data, said in a statement.
“We aim to pick up where these studies have left off by taking into account a greater number of costs and benefits associated with undergrounding. Cities are complex systems and there are dozens, if not hundreds, of other factors that must be taken into account with projects of this scale and importance.”
The wider strategies Project Groundwork is exploring include:
- Sharing utility infrastructure between electricity and broadband;
- Shifting underground utility infrastructure out of the road and into the public rights-of-way;
- Laying cable on existing surfaces and covering with cycling paths;
- Micro-trenching, horizontal drilling, and innovative wireless technologies to connect the network to individual homes and businesses.
“Project Groundwork is gathering and analyzing a substantial amount of infrastructure data relating to age, investment costs and synergies with other utility services such as broadband and water,” Christopher Roy, DEED director for region 8 and general manager of Shrewsbury Electric & Cable Operations, said via email.
The data generated by Project Groundwork should be applicable beyond MMWEC and its member utilities. “Having this information will allow more informed decision making with respect to not only electric system upgrades but also how to best support upgrades of other critical community infrastructure such as telecommunications and water, even if these are not currently services provided by the public power authority,” Roy said.
“My hope is that the results of Project Groundwork will reveal opportunities for legislative action supporting the creation of new public power entities,” Roy said. “Our business model has resulted in some of the most efficient and effective infrastructure investments that stretch each dollar to the fullest. This approach is what will enable the necessary infrastructure upgrades across the country to happen and serve as the foundation for technological advancements.”
MMWEC is a non-profit, public corporation that provides a variety of electric power supply, financial, risk management and other services to consumer-owned municipal utilities in Massachusetts.
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.
Northern Wasco PUD’s APPA-Funded Project Will Support Rural EV Adoption
November 29, 2021
by Peter Maloney
APPA News
November 29, 2021
Northern Wasco County Public Utility District in Oregon, along with several other Northwest utilities, has won a Demonstration of Energy & Efficiency Developments (DEED) grant from the American Public Power Association to expand electric vehicle adoption in rural areas.
Northern Wasco PUD, the sponsoring utility, is sharing the $125,000 DEED grant for the Self-Service Ride & Drive and Rural EV Sharing programs with several other utilities.
They are Ashland Electric Department, Central Electric Coop, Consumers Power, Emerald People’s Utility District, Eugene Water and Electric Board, Midstate Electric Coop, all in Oregon, and Peninsula Light cooperative in Gig Harbor, Wash. Other utilities could also join the program.
Both DEED sponsored projects are alternatives to traditional, utility-sponsored ride and drive events and rural car-sharing programs and are intended to serve as a more cost-effective, accessible, and sustainable path for utilities that want to introduce their customers to electric vehicles.
“It is one program with two use cases,” Connor Herman, program manager at Portland. Ore. Based Forth Mobility, said. Northern Wasco PUD is partnering on the DEED project with Forth, which designed and is implementing the program.
Both aspects of the program are an opportunity for people to test drive electric vehicles, either as a short-term test drive or as a car share similar to the way Zipcar and other services work. “It is the best way to break down misconceptions about EVs,” Herman said. “Typically, rural areas do not have a lot of electric vehicles. Essentially the idea is to use car-sharing technology to provide access to EVs.”
Forth is providing the electric vehicles for the program and handles the insurance and cleaning for the vehicles, as well as marketing and third-party software. Right now, there are 12 cars in the program, mostly Chevy Volts with prospects for Nisan Leafs and BMW i3s vehicles in the works.
Rates for using the electric vehicles are not yet finalized but will likely be by the hour or the day, perhaps in the range of $4 an hour or $40 per day and two free hours for a first test drive, Herman said.
Participating utilities are responsible for finding and providing sites for the vehicles. Unlike Zipcar and other similar services, the electric vehicles in the utility programs would have to be returned to the starting location, typically a location with an available charging port.
Emerald People’s Utility District has “a really good spot in mind,” Rob Currier, the utility’s power resources supervisor, said. Emerald is looking at a rural location in Veneta, Ore., west of Eugene and near low-income housing and an existing charging station installed as part of the West Coast Electric Highway initiative.
That charging station is being revamped to a Level 3 charger and a couple of Level 2 chargers. Emerald is providing about $17,000 in funding to help revamp the station.
“We are hoping to have a vehicle hosted there and a public parking spot. We are hoping to get it finalized pretty soon,” Currier said. “We feel rural areas are underserved with EV structure and programs.”
“Ride and drive is a really powerful way to demo EVs,” Currier said. “This is a way to have one of these events constantly on and ready go.”
Emerald’s board is also in favor of the project. “It is a benefit to all of our customers because, if done well, it provides an incentive to charge EVs off peak,” and that brings in revenues and helps improve the utility’s load factor, which can push down rates for everyone, Currier said.
The rural EV sharing project is not Emerald’s first DEED grant. Last year, the utility won a grant that it used to analyze data streams from its Advanced Metering Infrastructure (AMI) system. That program was very useful and resulted in an ongoing relationship with the participating vendor, The Energy Authority, Currier said.
And even though Emerald already has a relationship with Forth, the utility didn’t have the “bandwidth” to take on another DEED project, but fortunately Northern Wasco stepped in, Currier said. Without the DEED grant and Northern Wasco’s sponsorship, “I don’t think we would have been able to do the EV demonstration project,” Currier said.
The program also has many of the attributes that make for a successful DEED application, Currier said, specifically, “it is a unique application of technology, and it is replicable and shareable.
For Northern Wasco, the EV car share program is a first. Forth had been discussing the project with the Bonneville Environmental Foundation for about two years and, after talking with about half a dozen utilities in the region, the DEED opportunity came up.
As a DEED member, “Northern Wasco PUD was excited to be the leading applicant to move this project forward,” Justin Brock, customer service and key accounts manager at Northern Wasco, said via email.
“Getting behind the wheel of an EV is a huge catalyst for getting folks interested in buying one themselves,” Brock said. In a smaller community, he added, “there aren’t a lot of choices in the car market here yet. So, we hope to use this program to get our customers experienced with EVs and test this new technology out in a no-pressure environment.” In addition, he said, “The learnings and lessons of this project will ideally be replicated by public power utilities around the country.”
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%.