EIA sees more renewable and coal generation this summer as electric sales rise
May 18, 2021
by Peter Maloney
APPA News
May 18, 2021
This summer could see an increase in renewable and coal-fired generation as electricity sales rise relative to last summer’s sales during the COVID-19 pandemic, according to the recently released Short-Term Energy Outlook (STEO) from the Energy Information Administration’s (EIA).
Electricity generation in the United States “will look different this summer compared with last summer as rising natural gas costs drive many electricity generators to switch to renewables and coal, the EIA said in its annual summer STEO, released May 11.
The summer STEO forecasts a 12 percent decline in electricity generation from natural gas, a 21 percent increase in generation from renewable sources, and an 18 percent increase in generation from coal over last summer, with the trend most pronounced in Texas and the Midwest.
“We believe renewable sources will primarily make up for the decrease of natural gas usage in Texas,” Stephen Nalley, acting EIA administrator, said in a statement. “Our forecast is that 28% of Texas’s electricity demand will come from renewables this summer, up from 21% in 2020.”
For total electricity sales, the EIA is forecasting a 1.5 percent increase this summer over last summer, with a 4.5 percent increase in sales to the industrial sector, and a 2.6 percent increase in sales to the commercial sector. The increases are primarily the result of rising COVID-19 vaccinations, fewer pandemic-related restrictions, and an improving economy, the EIA said.
The increased electricity use will be most notable in hotels, restaurants, and other businesses that faced hurdles in 2020 because of stay-at-home orders, Nalley said.
Milder summer weather and fewer travel restrictions, however, should contribute to a forecast 2.5 percent decrease in residential electricity use per customer this summer, according to the EIA report, though the agency noted that estimated household electricity use is still higher than the 2015-2019 average. The EIA expects U.S. households to pay about $446 on average for electricity from June 1 to August 31, a level similar to last year’s.
The STEO forecast relies on the macroeconomic model from IHS Markit, from which the EIA assumes U.S. GDP growth will be 6.2 percent in 2021 and 4.3 percent in 2022.
Origis Energy to develop solar farm in support of renewable energy needs for Knoxville
May 18, 2021
by Paul Ciampoli
APPA News Director
May 18, 2021
The Tennessee Valley Authority (TVA) recently announced the selection of Origis Energy to develop a 200-megawatt solar farm in Clay County, Miss., to support the renewable energy needs of Knoxville, Tenn.
Knoxville Utilities Board’s (KUB) investment in the project will enable 50 megawatts of new battery storage technology that will increase power grid resiliency, TVA said.
KUB provides electric, natural gas, water, and wastewater services to more than 468,000 customers in Knoxville and parts of seven surrounding counties.
Scott Fiedler, a TVA spokesperson, noted that KUB will receive renewable energy credits (RECs) generated from the solar facility.
A REC is a market-based instrument that represents the property rights to the environmental, social and other non-power attributes of renewable electricity generation. RECs are issued when one megawatt-hour of electricity is generated and delivered to the electricity grid from a renewable energy resource.
Last November, KUB announced that 20% of Knoxville’s electricity will be generated from renewable sources. KUB’s investment in more than 500 MW of solar will help Knoxville meet its goal to reduce greenhouse gas emissions by 80% by 2050, compared with 2005 levels.
Origis Energy will supply solar energy through a long-term power purchase agreement through TVA’s Green Invest program. Origis will develop, build, own and operate the plant using industry-leading land stewardship techniques. Origis will complete the facility in late 2023, pending environmental reviews.
Since 2018, Green Invest has attracted nearly $2.7 billion in solar investment and procured over 2,100 MW of solar on behalf of its customers, TVA said.
Jeff Lyash, President and CEO of TVA, discussed the Green Invest program in a recent episode of the American Public Power Association’s Public Power Now podcast.
California ISO says grid better positioned for this summer, but reliability risks remain
May 18, 2021
by Paul Ciampoli
APPA News Director
May 18, 2021
The California Independent System Operator (CAISO) expects electricity supply conditions for the upcoming summer to be in better shape than last year, but the power grid is still susceptible to stress during extreme heat waves that extend across the West, according to the CAISO’s summer outlook released on May 12.
The 2021 Summer Loads and Resources Assessment projects the energy grid will have more capacity to meet demand in 2021 than it did in 2020, “a critical element for averting rotating power outages, such as those that occurred last August,” CAISO noted in a news release.
CAISO’s annual summer assessment evaluates expected supply and demand to help prepare for the hot weather months of June through September.
CAISO said the additional capacity is the result of resource procurement ordered by the state. A series of market redesigns and policy changes in CAISO’s system taken since September 2020 along with improved communication and coordination protocols has improved overall preparedness for this summer, it said. “However, if heat events similar to those that gripped the western states region last summer occur, imported energy from other states could be limited, and the power grid will be at risk of supply shortages and possible emergency conditions,” the grid operator said.
This year’s outlook includes roughly 2,000 megawatts (MW) of additional, readily available resources coming online to serve ISO net peak demand compared to this time last year, including battery storage that is expected to absorb excess renewable energy in the middle of the day, and inject it back into the grid after sunset when solar generation goes offline, the grid operator said.
The state and CAISO are continuing to pursue other opportunities to add an additional 1,000 to 1,500 MW of new resources to the system by summer.
The 2021 forecasted peak demands are about the same as last year under normal weather conditions.
However, extreme heat events are becoming more likely.
By incorporating last August’s historical heat wave into the assessment, it pushes weather previously regarded as extreme into what is now considered more normal ranges, CAISO noted.
The grid operator reported that California’s hydroelectric energy supplies will also be significantly lower than normal, with the state weathering a second consecutive year of below normal precipitation. Snowpack water content peaked at 60 percent of normal, similar to last year’s conditions, and reservoir levels have decreased to 70 percent of normal.
Meanwhile, imports will play a substantial role in this summer’s power grid reliability.
The assessment measured the likelihood of energy deficiencies and system emergencies, finding that at typical import levels based on historical data, there is a low probability of grid stress. But results based on analyses of more limited import levels associated with a widespread heat event showed that the probability of having to rely on measures to reduce load during emergency conditions, including rotating power outages, increases significantly during high demand conditions.
“Conservation will be pivotal to cushioning the grid when it needs it the most, typically during hot summer evenings when demand remains high for air conditioning use and solar production is going offline,” CAISO said.
In coordination with the California Public Utilities Commission, CAISO will issue Flex Alerts when system conditions are forecast to be tight, as it has done in prior years. Flex Alerts are voluntary calls to consumers to cut down on electricity use from 4–9 p.m. The state and CAISO are planning to launch a refreshed Flex Alert campaign in June to alert residents earlier of a potential supply shortage and spread the conservation message more widely.
Grid stability will also be improved through expanded communications and coordination among utilities and stakeholders in the state and across the West, CAISO said. The CAISO and its partners will continue to seek out and use extraordinary measures during emergencies, in an effort to avoid rotating outages, it added.
Elliot Mainzer, President and CEO of CAISO, discussed the state power grid’s summer outlook in an episode of the American Public Power Association’s Public Power Now podcast.
LADWP joins effort to bring down green hydrogen costs via commercialization
May 18, 2021
by Peter Maloney
APPA News
May 18, 2021
The Los Angeles Department of Water and Power (LADWP) this week joined a coalition that aims to bring down the cost of green hydrogen.
LADWP, along with the Green Hydrogen Coalition and other partners, launched HyDeal LA, a collaboration of developers, green hydrogen off-takers, integrators, equipment manufacturers, investors, and advisors.
The group aims to work together to bring the cost of green hydrogen down to $1.50 per kilogram (kg) in the Los Angeles Basin by 2030 by creating a commercial green hydrogen cluster at scale.
Hydrogen created by electrolysis powered by generation sources such as wind, solar or hydro power is considered “green” from an environmental standpoint.
Green hydrogen can enable deep reductions in carbon dioxide emissions and can be used in a variety of applications, such as a fuel for a power plant or for a steel mill or for a hydrogen fuel cell vehicle. Green hydrogen also can provide long-duration seasonal energy storage.
In addition to LADWP, participants in HyDeal LA include 174 Power Global, Mitsubishi Power, and Southern California Gas. Implementation partners include Clifford Chance, Marathon Capital, and Strategen.
In its first phase, HyDeal LA participants will design the competitive supply chain necessary to achieve $1.50/kg delivered green hydrogen in the LA Basin. They also will work toward achieving in-principle agreement on the necessary terms and conditions to achieve production, storage, transport and delivery of green hydrogen at scale.
“Green hydrogen is the key to reliably achieving 100% renewable energy,” Martin Adams, LADWP’s general manager and chief engineer, said in a statement. “We are pleased to join the HyDeal LA effort, which includes an innovative and expanding vendor and development community, to support and help catalyze the supply chain needed to achieve large-scale, low-cost green hydrogen power supply for our local in basin plants.”
Separately, LADWP is leading the effort to turn the Intermountain Power Project in Delta, Utah, to the world’s first gas turbine designed and built to operate on entirely on green hydrogen by 2035.
HyDeal LA is part of HyDeal North America, a commercialization platform launched by the Green Hydrogen Coalition that is dedicated to deploying green hydrogen at scale for multi-sectoral decarbonization.
HyDeal LA is modeled after HyDeal Ambition, a similar project in Europe committed to producing and purchasing 3.6 million tons of green hydrogen annually for the energy, industry, and mobility sectors at about $1.83 per kilogram before 2030.
In a November report, S&P Global Ratings said the cost of producing hydrogen from renewable resources would need to fall by over 50 percent, to $2.00 or $2.50 per kilogram, by 2030 to make it a viable alternative to conventional fuels.
The levelized cost of renewable power accounts for about 60% of cost of green hydrogen, S&P said, adding that a $10 per megawatt hour decline in the power price reduces the cost of hydrogen by $0.4 to $0.5 per kilogram.
Other factors in the cost of green hydrogen are the capital costs of electrolyzers and capacity utilization factors. Increasing utilization to 50 percent from 40 percent would reduce the cost of hydrogen by $0.2 to $0.3 per kilogram.
Policy actions on EVs rose quarter to quarter, report says
May 18, 2021
by Peter Maloney
APPA News
May 18, 2021
Forty-eight states and the District of Columbia took a total of 521 actions related to electric vehicles during the first quarter, an increase from the 461 actions taken by 47 states and D.C. in first-quarter 2020, according to a new report by the NC Clean Energy Technology Center.
Of the actions catalogued in the first quarter of this year, most, 133, were related to regulation, followed by 125 actions related to financial incentives, and 101 actions related to market developments.
Among the most notable actions taken, the report cited the New Jersey Board of Public Utilities’ approval of electric vehicle programs proposed by Atlantic City Electric and PSE&G New Jersey during the quarter. Atlantic City Electric’s program has a budget of $20.7 million. and PSE&G’s program has a budget of $166.2 million. Both programs include make-ready incentives for different customer types and demand charge alternatives for fast charging stations.
In Virginia, lawmakers passed two bills in March, one establishes an electric vehicle rebate program and an electric vehicle grant program, the other establishes an electric vehicle grant program. The rebate program begins in 2022 and provide rebates of at least $2,500 for the purchase of electric vehicles. Income-qualified residents will be eligible for an additional $2,000 rebate. The grant program provides awards on a competitive basis to school boards and non-profits to assist with the replacement of diesel school buses and vehicles with electric buses and vehicles.
The report also cited Colorado where the state’s Public Utilities Commission issued a decision in January approving Xcel Energy’s proposed transportation electrification plan that provides electric vehicle rebates program for low-income customers, residential home wiring rebates, a school bus electrification program, the development of utility-owned fast charging stations in underserved areas, utility deployment of charging stations for multi-family housing, and commercial charging rates, among other elements.
In Oklahoma, the report cited the state legislature’s bill adopting a tax of $0.03 per kilowatt hour (kWh) on the sale of electricity used to charge electric and hybrid vehicles. The tax begins in 2024 but will not apply to charging stations in service before November 2021, those with less than 50 kilowatts of capacity, or those that supply electricity free of charge, including private residential stations. The bill establishes a registration fee for electric vehicles and provides a tax credit for the amount of charging taxes paid.
In Kansas and North Dakota, the report noted that legislatures in those states passed bills allowing electric vehicle charging stations to resell electricity to the public without being classified as a public utility as long as the electricity used for vehicle charging is purchased from a retail electric supplier.
The actions in Oklahoma Kansas and North Dakota fit into a wider trend identified by the NC Clean Energy Technology Center. State lawmakers across the country have been considering fees on electric vehicles, primarily road usage fees based on miles traveled and taxes on electricity used for vehicle charging.
Legislatures in Georgia, Minnesota, and Nevada also considered taxes on electricity used for vehicle charging, while lawmakers in California, Minnesota, Missouri, and Washington introduced bills adopting road usage fees for electric vehicles. A bill under consideration in Montana would institute a trip-based fee for electric motor trucks and truck tractors licensed in another state. In addition, several states are considering registration fees for electric vehicles with Oklahoma and South Dakota recently adopting new fees.
The report also said several utilities filed proposals in the first quarter related to transportation electrification programs. In Kansas and Missouri, Evergy requested approval for transportation electrification portfolios including charging station rebates and new rates designed for business and transit charging.
Jersey Central Power & Light filed an EV Drive Program proposal that includes make-ready incentives, off-peak usage credits, and utility deployment of fast chargers.
Indianapolis Power & Light filed a petition for an electric vehicle portfolio involving a managed charging program and off-peak charging incentive.
And in Washington State, Avista Utilities filed an application for a series of programs, including utility deployment of residential and commercial charging stations, DC fast charger deployment, and new commercial charging rates.
The NC Clean Energy Technology Center is a chartered Public Service Center administered by the College of Engineering at North Carolina State University.
Rhode Island’s Pascoag Utility District turns to batteries to avoid a transmission upgrade
May 18, 2021
by Peter Maloney
APPA News
May 18, 2021
The Pascoag Utility District in Rhode Island plans to use an energy storage project as an alternative to upgrading transmission lines.
The 3-megawatt (MW), 9-megawatt hour (MWh) lithium-ion battery array is being developed by Agilitas Energy, which is beginning the pre-construction phase of the project. The battery system is expected to enter service in the second quarter of 2022.
Pascoag Utility District is contracting for all the battery system’s capacity, both storage and generation. The contract also includes a sharing arrangement on the lowering of the public power utility’s capacity and transmission costs, which vary depending on the utility’s load at times of peak demand on the ISO-New England system.
The batteries will cycle on Pascoag Utility District’s system, charging and discharging and shifting load between peak and off-peak periods and will provide peak shaving services to the utility and ancillary services to ISO-New England.
“The battery storage system will allow us to modernize our infrastructure and avoid the more costly re-construction of existing transmission lines,” Mike Kirkwood, general manager of Pascoag Utility District, said in a statement. “The battery energy storage systems help fulfill our goal to control costs while we assure reliable power.”
The battery storage project was attractive to the Pascoag Utility District because the utility was starting to reach the thermal limits on its existing connection to the grid. The project “avoids $6 million to $12 million in costs that would have been needed to completely rebuild the two National Grid 5-mile, 13.8-kilovolt (kV) feeder lines that connect us to the outside world,” Kirkwood said via email. “Some work is still needed on those lines, but much less than was initially anticipated because of our substation work and the battery project.”
National Grid’s system impact study put “the cost of rebuilding the transmission lines at $6 million with a confidence level of -50%/+200%, meaning the actual costs could have escalated to twice the original estimate,” Kirkwood said. “We had to rebuild our substation no matter what alternative we chose,” he said, “so the battery part of the project is helping us avoid the $6-12 million in the complete rebuilding of the lines.”
Pascoag Utility District is paying about $200,000 in interconnection costs associated with the storage project with funds from a grant allocated by the Rhode Island Office of Energy Resources for unique energy efficiency projects.
Pascoag Utility District qualified for the grant because the battery project, together with the work it is doing on the substation connecting the utility’s system to the New England grid, qualifies as a non-wires alternative. The utility also received $1.4 million in financing for the substation project through Rhode Island’s Efficient Building Funds program, which allowed Pascoag Utility District to receive low cost financing from the Rhode Island Infrastructure Bank, a quasi-state agency that finances public infrastructure.
“The operation of this system will obviate the need for adding costly transmission infrastructure and create a win-win for all parties including Pascoag’s customers,” Barrett Bilotta, president of Agilitas Energy, said in a statement.
Last year, then-Governor Gina Raimondo signed an executive order that committed Rhode Island to meeting 100 percent of its electricity demand with renewable and non-fossil fuel resources by 2030. Many energy experts see energy storage playing a key role in that transition with its ability to store electricity generated by renewable energy resources and discharge it at times when demand is high or renewable resources are not available.
The American Public Power Association offers a Public Power Energy Storage Tracker for association members that summarizes energy storage projects undertaken by members that are currently online.
Groups press for access to direct payment refundable energy tax credits
May 17, 2021
by Paul Ciampoli
APPA News Director
May 17, 2021
Public power utilities and rural electric cooperatives should be allowed to receive direct payment refundable energy tax credits, leaders of the American Public Power Association (APPA), National Rural Electric Cooperative Association (NRECA) and Large Public Power Council (LPPC) told congressional leaders in a May 14 letter.
While refundable credits have for several years been one option under consideration for providing comparable incentives to energy tax credits, the letter is the first joint statement specifically citing them as the preferred approach.
The letter, which was sent to House Speaker Nancy Pelosi, D-Calif., Minority Leader Kevin McCarthy, R-Calif., Senate Majority Leader Charles Schumer, D-N.Y., and Senate Minority Leader Mitch McConnell. R-Kentucky, was signed by APPA President and CEO Joy Ditto, NRECA CEO Jim Matheson and LPPC President John Di Stasio.
The letter notes that earlier this year, President Biden set ambitious targets for reducing greenhouse gas emissions from power generation, transportation, and other sources. “Reaching these goals will be a daunting challenge, but our members have been and continue to be committed to reduce greenhouse gas emissions,” wrote Ditto, Matheson and Di Stasio.
“However, for community-owned electric utilities, all the increased costs associated with drastically reshaping our generation profile will be borne by our customers and consumer-owners. As such, we cannot afford inefficient or ineffective policies. If the goal is to move toward a cleaner energy grid by providing tax incentives for developing clean energy generation, storage, transmission, and electric vehicle (EV) recharging infrastructure, federal incentives must be made available to all electricity providers,” the three association leaders said.
They argued that one of the most significant shortcomings of federal energy tax policy is that not-for-profit and tax-exempt community-owned electric utilities have been excluded from being able to directly claim these credits. “The result is that our utilities only indirectly benefit from energy-related tax incentives.”
This is typically done through long-term power purchase agreements (PPAs) with taxable project developers and their tax equity partners, which claim these credits. “PPAs are complex and expensive, and much of the value of the credits flow to the project developers and their investors rather than to the not-for-profit utilities and their customers,” wrote Ditto, Matheson and Di Stasio.
“Further, to qualify for the credit, the project developer and tax-equity investors must retain ownership of the facility and our utilities may only later purchase the facilities by paying the owner the fair market value of the facility. This increases the cost and inefficiency of the present system and means that the purchasing utility is denied the substantial operational benefits that flow from direct ownership.”
Allowing public power utilities and rural electric cooperatives to receive these tax credits in the form of direct payments for building clean energy infrastructure “would ensure that all utilities serving all Americans would have equal access to these federal resources. The direct payments would be used to help offset project costs — increasing the incentive for further investments — and would enable public power utilities and rural electric cooperatives to own these facilities directly. It would also mean more local projects, with local jobs, under local control. Having direct ownership as an option will help our members develop a generation mix that best suits the needs of the customers.”
The President and Congress “have ambitious climate goals that cannot be met by leaving nearly 30 percent of the nation’s electric utility customers without access to incentives and support,” the letter said. To that end, Ditto, Matheson and Di Stasio urged Congress to provide direct pay for credits to public power utilities and rural electric cooperatives.
City Water, Light and Power plant chosen as site for carbon capture technology pilot testing
May 13, 2021
by Peter Maloney
APPA News
May 13, 2021
The U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) has chosen the University of Illinois’ Prairie Research Institute (PRI) to conduct large-scale pilot testing of a carbon dioxide (CO2) capture technology at Springfield, Ill., public power utility City Water, Light and Power’s (CWLP) Dallman Unit 4.
The DOE has allocated $47 million for the final phase of the project that will see the construction of a 10-megawatt (MW) Linde-BASF advanced post-combustion CO2 capture system to process the power plant’s flue gas. Illinois committed an additional $20 million to cost of the final phase of the project.
Dallman 4 is a 200-MW pulverized coal power plant.
In making the award, the DOE said the successful construction and operation of the Dallman Unit 4 plant would demonstrate economic carbon capture technology and help enable commercialization of the technology.
The PRI projects the construction and operation of the Dallman Unit 4 carbon capture facility will have a regional economic impact of $47.1 million and generate tax revenue of $5.6 million.
“As a publicly-owned utility, this new construction and innovative initiative will be a boost to our local economy while the energy industry as a whole will also be watching CWLP to see how this technology performs,” Springfield Mayor Jim Langfelder said in a statement.
The third phase of the Dallman carbon capture test project, final design and construction, is scheduled to begin in June and includes finalizing a detailed engineering plan and acquiring equipment and modules needed for the new system. Building the system is slated to begin in June 2022 with testing expected to take place from March 2024 through to May 2026.
“The success of this project would be a model and foundation for more accessible, attainable carbon capture systems at facilities around the world,” Kevin OBrien, principal investigator for the project and director of the PRI’s Illinois Sustainable Technology Center (ISTC), said in a statement.
In addition to the carbon capture project at the Dallman plant, CWLP is working with ISTC on projects involving the use CO2 as feedstock for algae; scrubber wastewater treatment technology; beneficial reuse of coal fly ash in plastics, and a project advancing the design of a hybrid power plant and energy storage system.
“A proven and cost-effective carbon capture solution is what plants need to be able to demonstrate and transition to if a balanced, resilient and reliable energy grid is the goal,” Doug Brown, CWLP’s chief utility engineer, said in a statement. “Further, I’m pleased the University is planning spinoff projects from this work,” he added.
California community choice aggregator’s board approves 15-year geothermal energy contract
May 13, 2021
by Paul Ciampoli
APPA News Director
May 13, 2021
The Board of Directors for California’s Clean Power Alliance (CPA) recently approved a 15-year contract with Ormat Technologies Inc.’s Heber South Geothermal facility located in Imperial Valley, Calif.
Once the long-term contract takes effect January 1, 2022, the facility will add 14 megawatts of renewable energy to CPA’s energy portfolio. With an expected average annual generation of 116,508 MWh, the project will also allow CPA to further comply with the state of California’s aggressive renewable energy mandates.
CPA will pay for the output of the geothermal generation of the project at a fixed-price rate per megawatt hour for the full term of the 15-year contract. Under the contract, CPA will receive all product attributes from the facility, including energy and renewable energy credits (RECs).
In addition, the contract brings CPA closer to meeting its regulatory obligations under California’s SB 100 and SB 350, which require that 65% of Renewables Portfolio Standard (RPS) compliance related renewable energy supply be sourced from long-term contracts beginning in the 2021-2024 compliance period.
The Heber South project has a firm transmission agreement with California public power utility Imperial Irrigation District to deliver power to the California Independent System Operator at the Coachella Valley substation.
CPA, a community choice aggregator (CCA), serves approximately three million customers and one million customer accounts across 32 communities throughout Southern California.
According to CAISO’s website, geothermal energy accounts for 1,389 MW of the ISO’s grid as of April 11, 2021.
In January 2020, Ormat Technologies announced the signing of two power purchase agreements with Silicon Valley Clean Energy and Monterey Bay Community Power, two California CCAs.
The American Public Power Association has a category of membership for community choice aggregation programs.
Platte River Power Authority begins permitting for 150-MW solar project
May 13, 2021
by Peter Maloney
APPA News
May 13, 2021
Platte River Power Authority has initiated permitting for a 150 megawatt (MW) solar power project in Weld County, Colo.
Platte River Power Authority is undertaking the Black Hollow Solar project with BHS Solar, a subsidiary 174 Power Global. The public power utility intends to use the electrical output from the solar project to replace its share of the output from the coal-fired Craig Unit 1, which is scheduled to retire in 2025.
The solar project, if approved by Weld County planners and commissioners, would be located northeast of Black Hollow Reservoir and span between 1,000 and 1,400 acres, with the final location and layout determined through a review of physical, environmental and land-use constraints and feedback from numerous stakeholders, including neighbors, state agencies, and county leaders.
The solar project would provide work for an estimated 320 full-time workers during construction and up to 450 workers during the peak of construction and then require eight to 10 permanent positions to manage the solar farm after it enters service.
Under the agreement with Platte River, 174 Power Global will build, own and operate the Black Hollow Solar project and sell the electricity under a long-term power purchase agreement to Platte River beginning in 2023. Energy would be delivered to Platte River’s owner communities in Colorado’s north Front Range through a substation to be built adjacent to existing Platte River transmission lines.
Platte River Power Authority serves Estes Park, Fort Collins, Longmont and Loveland, Colo.
“The addition of the Black Hollow Solar project will take us approximately halfway toward our goal of providing 100% noncarbon energy,” Jason Frisbie, general manager and CEO of Platte River Authority, said in a statement. “This is one of many significant steps we’re taking to achieve our Resource Diversification Policy, and we’re excited to move forward with construction.”
When the Black Sparrow Solar project is completed, it will give Platte River Power Authority more than 200 MW of solar capacity when combined with its 30-MW Rawhide Flats solar project, which entered service in 2016, and its 22-MW Rawhide Prairie Solar installation, which began operation – along with 2 megawatt hours of battery storage –in March.
Platte River also receives about 230 MW of wind energy under long-term power contracts.