DOE issues order aimed at reducing risks to bulk-power system from China-related entities
December 21, 2020
by Paul Ciampoli
APPA News Director
December 21, 2020
U.S. Secretary of Energy Dan Brouillette on Dec. 17 issued an order designed to reduce the risks that entities associated with the People’s Republic of China pose to the U.S. bulk-power system (BPS).
The order only applies to utilities that have been designated as defense critical electric infrastructure (DCEI). The Department of Energy informed a small number of public power utilities that they had been designated as DCEI in 2019.
The order invokes the authority delegated to the Secretary of Energy by Executive Order 13920, “Securing the United States Bulk-Power System” (EO 13920) and takes effect January 16, 2021.
The order prohibits utilities that supply critical defense facilities from procuring from the People’s Republic of China specific BPS electric equipment that poses an undue risk to the BPS, the security or resilience of critical infrastructure, the economy, national security, or safety and security of Americans, the DOE said in a news release related to the order.
President Trump issued EO 13920 on May 1, 2020 and granted implementation authority to the Secretary of Energy.
The DOE order provides a compliance grace period of several weeks to minimize potential procurement and supply chain disruptions.
The order specifically prohibits utilities that supply critical defense facilities at a service voltage of 69-kV or above from acquiring, importing, transferring, or installing BPS electric equipment, and is specific to select equipment manufactured or supplied by persons owned by, controlled by, or subject to the jurisdiction or direction of the People’s Republic of China.
The order applies from the point of electrical interconnection with the critical defense facility up to and including the next “upstream” transmission substation.
Utilities subject to the order will be notified no later than five days from the issuance of the order.
Additional information including a link to the order is available here.
LaGrange, Georgia, negotiating solar power deal with local Walmart store
December 21, 2020
by Peter Maloney
APPA News
December 21, 2020
The city council of LaGrange recently authorized the city’s utility to sign agreements that would allow the Georgia city to offer renewable power to the local Walmart store.
Walmart has a goal to serve at least 50% of their stores nationwide with renewable power by 2025 and 100% by 2035.
Buying renewable solar power through the city allows Walmart to realize better prices and keeps revenues from one of the city’s largest customers in the local economy, Patrick Bowie, the city’s director of utilities, said.
Walmart provides the city with about $1.3 million in annual revenues.
The solar power purchase will require multiple agreements, which are still under negotiation. “We are trying to finalize them by year end,” Bowie said.
As a member of the Municipal Electricity Authority of Georgia, LaGrange relies on MEAG Power for its generation and transmission resources. For actual power sales, the city uses The Energy Authority.
MEAG Power is in the process of wrapping up negotiations with the developer of a large solar power project in southern Georgia. LaGrange, meanwhile, is finalizing a deal with Walmart for sales of solar power that will be matched by a back-to-back purchase agreement for a portion of the output from the solar project with which MEAG is contracting. It would be MEAG Power’s first participation in a solar power project.
Walmart’s electrical load in LaGrange is between 17 million and 18 million kilowatt hours (kWh) per year, which would require between 5.5 megawatts (MW) and 6 MW of capacity.
The deal is complicated by the fact that LaGrange currently has excess power and that Walmart’s load does not synch up with intermittent solar output. To protect itself from purchasing more power than it needs or paying more for solar power than it pays for its conventional power, LaGrange is negotiating a sales agreement with Walmart under which the retailer would be responsible for the difference between the cost of solar and the cost of wholesale power the city buys from The Energy Authority. If solar power is more expensive, Walmart would absorb that cost. If solar power is less expensive, Walmart would benefit from the lower costs.
LaGrange is also signing an agreement with Electric Cities of Georgia, which provides LaGrange and 51 other public power communities with distribution support services. Under the agreement, Electric Cities of Georgia would provide LaGrange with the billing services to balance the books on power sales between LaGrange and Walmart.
To help mitigate the risks associated with the solar sales, Walmart would be able to shift power sales to its other retail locations in Georgia.
One of the details that still needs to be worked in the negotiations is to see what level of participation other cities want in the solar power deal, Bowie said.
LaGrange is an industrial center, but so far none of the city’s other large commercial customers have requested renewable power. It is hard for solar power to compete with the city’s current low power rates, Bowie said.
FERC issues NOPR proposing incentive rate treatment for voluntary cybersecurity investments
December 21, 2020
by APPA News
December 21, 2020
The Federal Energy Regulatory Commission on Dec. 17 issued a notice of proposed rulemaking (NOPR) proposing incentive rate treatment for certain voluntary cybersecurity investments that go above and beyond the requirements of the North American Electric Reliability Corporation’s (NERC) mandatory Critical Infrastructure Protection (CIP) reliability standards.
The NOPR (Docket No. RM21-3-000) was issued by the Commission at its monthly open meeting. It was the first FERC open meeting for Commissioner Allison Clements, who was sworn in on December 8, 2020. Clements did not vote on any of the agenda items.
FERC white paper
In June, FERC staff sought comments on a white paper that proposed “a new framework for providing transmission incentives to utilities for cybersecurity investments.” FERC staff cited “the evolving and increasing threats to the cybersecurity of the electric grid” as the impetus for the Cybersecurity Incentives Policy white paper (Docket No. AD20-19-000).
In response to the white paper, the American Public Power Association in August said that an incentive program for cybersecurity investments is not needed to encourage investment in cybersecurity measures and could lead to investment that raises transmission costs for customers without providing meaningful cybersecurity benefits in return.
Details of NOPR
Reflecting many of the features included in the FERC Staff white paper, the new NOPR would allow FERC-jurisdictional utilities to seek Commission approval, pursuant to section 205 of the Federal Power Act, of two types of incentives for cybersecurity investments: a rate of return adder of 200 basis points or deferred cost recovery for certain cybersecurity-related expenses.
Qualifying expenditures would be eligible for either, but not both, incentives. The total cybersecurity incentives requested would be capped at the top of the return on equity “zone of reasonableness” used by FERC to establish allowed equity returns for public utilities.
The incentives would be available for certain investments that voluntarily apply specific CIP reliability standards to facilities that are not subject to those requirements and/or implement standards and guidelines from the National Institute of Standards and Technology’s (NIST) voluntary framework for improving critical infrastructure cybersecurity.
Deferred cost recovery would be allowed for three categories of expenses: (1) expenses associated with third-party provision of hardware, software and computing networking services; (2) expenses for training to implement new cybersecurity enhancements undertaken pursuant to this rule; and (3) other implementation expenses, such as risk assessments by third parties or internal system reviews and initial responses to findings of such assessments.
Prior or continuing costs would not be eligible for incentives. Deferred regulatory assets whose costs are typically expensed would be amortized over a five-year period.
Utilities seeking to implement the proposed incentives must obtain prior Commission approval, and the proposed rule would impose initial and annual reporting requirements.
Comments on the NOPR are due 60 days after publication in the Federal Register, with reply comments due 30 days later.
NAESB report addresses need for digital technologies standards
December 18, 2020
by Peter Maloney
APPA News
December 18, 2020
The North American Energy Standards Board (NAESB) has adopted a report by its digital committee concerning the development of standards for the digital transformation taking place in the energy industry.
The report summarizes a series of conference calls and surveys conducted by NAESB’s board of directors and digital committee and is intended to aid NAESB as it considers new standards to support digital technologies.
Included among the digital committee members is Valerie Crockett, senior program manager for environment and energy policy at the Tennessee Valley Authority.
The report said that industry sectors ranging from energy, finance, manufacturing to healthcare are taking advantage of digital technologies that have lowered the cost of data collection, storage and processing and are enabling advanced analytics to drive better performance, increase productivity and support better strategic decision making.
The report paid particular attention to technologies, such as the use of distributed ledgers or the implementation of 5G networks, that have the potential “to alter the manner in which the transactions governed by NAESB standards take place.”
The NAESB report reviewed nearly a dozen technologies: distributed ledger technology (also known as blockchain technology), data governance requirements, cybersecurity, distributed energy resources, cloud computing, renewable energy certificate/credit tracking, deployable shareware, Internet of Things (IoT), 5G technologies and implementation, data analytics, and energy usage data.
Many of those technologies are already being deployed and are increasing efficiencies, and the development of supportive standards could accelerate their adoption and reduce the likelihood of “developing solutions that must be retrofitted to support interoperability with other technologies,” the report said.
In a 2018 meeting, NAESB’s board recommended that the organization begin looking at the impact digital technology could have on the energy sector.
Research and a series of discussions found that global investment in digital technologies by energy companies has risen over 20% annually since 2014 and that in 2016 an estimated $47 billion was invested in digital electricity infrastructure alone, a level 40% higher than worldwide investment in gas-fired power generation.
NAESB’s research also found that other standards organizations, such as the International Organization for Standardization, SAE International and ANSI, are pursuing digital transformation standards and have created groups within their organizations or held meetings to focus on exploring how new digital technology is transforming their industry sectors.
The report recommended that NAESB’s board continue “standards development efforts” for two technologies in particular – distributed ledger technology and cybersecurity – and monitor the other technologies identified in the report as “strongly relevant to the processes/transactions that NAESB standards currently address or may address in the future.”
The report noted that NAESB is currently developing standards to support distributed ledger technology in the wholesale and retail electric and gas markets.
NAESB’s Wholesale Gas Quadrant is working to conclude development of a standard to support conversion of the NAESB Base Contract for Sale and Purchase of Natural Gas into a digital “smart” contract that can be used with distributed ledger technology. And NAESB’s Wholesale Electric Quadrant and Retail Market Quadrants are jointly developing a standard contract to improve and automate the current voluntary renewable energy certificate processes.
NAESB’s Wholesale Electric Quadrant is also considering developing standards related to distributed ledger technology to support the accounting-close cycle for power trading.
The report also recommended that NAESB should continue to develop standards that support cybersecurity for the transactions the standards address and develop standards to support specific digital technologies, as well as review the finding of reports from Sandia National Laboratories and recommend any modifications that “may be necessary to support a new model for the implementation of NAESB cybersecurity standards.”
With respect to other technologies, the report identified the Internet of Things technology as an “emerging high interest and high value area for standards development.” The adoption of IoT technologies “will drive the need for new standards that support both privacy and cybersecurity, especially when used within operational or control environments,” the report said.
The report also identified data analytics as a technology that is relevant to the processes and transactions that the NAESB standards will address in the future, but noted that one-third of respondents to a NAESB survey said data analytics is not an area relevant to NAESB and that NAESB standards are not needed.
As with other emerging technologies, such as renewable energy credit contracts, the report recommended that NAESB should continue to monitor the development and adoption of the technology to determine if standards development is necessary.
The report also identified 5G technology as an area that received strong support as being relevant, but 50% of survey respondents said standards are not needed or that adequate standards are already in place.
The report is available here.
Public power utilities and blockchain
Several public power utilities are exploring blockchain technology.
A Sacramento Municipal Utility District project that is being funded in part through an award from the American Public Power Association’s Demonstration of Energy & Efficiency Development program will utilize blockchain-enabled tokens as part of an effort to encourage EV owners to charge their vehicles at workplaces when local renewables peak during the day.
In 2018, the Burlington Electric Department in Vermont won a grant from the DEED program to use blockchain technology to facilitate the integration and distribution of energy from multiple sources in real time.
Meanwhile, another California public power utility, Silicon Valley Power, and Power Ledger successfully completed the first stage of a program to test the use of blockchain technology for tracking and monetizing carbon dioxide reduction credits for electric vehicle charging and now plan to proceed to the second phase of the project.
In 2018, Silicon Valley Power used Power Ledger’s blockchain-backed platform to track and manage Low Carbon Fuel Standard (LCFS) credits at the Tasman Drive parking garage in Santa Clara, Calif., which has a 370 kW solar system and 49 electric vehicle charging stations.
Danville Utilities in Virginia has plans for a 10.6-MW battery storage system
December 18, 2020
by Peter Maloney
APPA News
December 18, 2020
Public power utility Danville Utilities in Virginia is moving forward with a battery energy storage project designed to shave its peak charges and save the utility and its customers money.
The Danville Utility Commission at its Nov. 30 meeting voted unanimously in favor of the 10.6-megawatt (MW), 23.3 megawatt hour (MWh) project.
The proposal is scheduled to be discussed at a work session of the Danville city council on Jan. 5. If it moves forward, the proposed project will be on the agenda for a vote on final approval at the council’s Jan. 19 meeting.
If approved, Danville Utilities is targeting Dec. 1, 2021 for operation of the battery system. It would be the public power utility’s first energy storage system.
“We are looking to take advantage of the battery storage system to reduce our exposure during generation and transmission peaks,” Jason Grey, director of Danville Utilities, said.
Not being an all-requirements utility, Danville gets is electrical power and transmission services from a variety of sources, including the PJM Interconnection. Danville, which is on the Virginia-North Carolina border, is just a couple of miles within the limits of PJM’s territory.
Danville Utilities has been looking at a battery system for well over a year but didn’t pursue one. “We kept an eye on battery prices and revisited the idea when prices came down,” Grey said.
If the project is approved, Danville Utilities would enter into a 20-year capacity agreement with Delorean Power, the Arlington, Va., company that would build, own and operate the storage system. The project is sited on an unused plot of land, about 100 feet by 70 feet, outside a utility warehouse in Danville.
Under the agreement, Danville Utilities would pay $4.25 per kilowatt per month, or about $541,000 in the first year with the costs declining slightly thereafter to reflect the 1.5% annual decline in battery capacity.
The utility would charge the batteries during off-peak hours when energy prices are lower and discharge the batteries during on-peak hours to offset or avoid transmission and energy capacity costs.
By the utility’s estimates, Danville would save $1.2 million in transmission and capacity costs in the first year of the agreement. And, over the 20-year life of the agreement, the utility would spend about $9.6 million in capacity payments to Delorean but save about $48.3 million in generation and transmission capacity charges.
Because so many transmission owners are implementing upgrades, transmission charges have been rising about 15% every year, Grey said.
By using the batteries to shave the peaks off its capacity charges, Danville Utilities expects to also be able to reduce its power cost adjustment, the sum that the utility charges customers to cover the over- or under- payment customers make through their monthly base rate. “When we can lower our power cost adjustment, it helps ratepayers,” Grey said.
The proposed battery storage project is kind of a trial, Grey said. “We hope to learn about the technology” and decide if it is a viable solution. “If it performs as anticipated, we could do another project in two or three years.”
Starbucks enters into first-ever ‘virtual’ storage PPA
December 17, 2020
by Ethan Howland
APPA News
December 17, 2020
Starbucks Corp. is entering into solar and solar-plus-storage virtual power purchase agreements to support its corporate sustainability goals.
One of the contracts is tied to a 1,200-megawatt solar project that is combined with energy storage that can deliver 2,165 megawatt-hours before needing to be recharged, according to LevelTen Energy, which runs a marketplace for renewable energy.
Under the deal with Terra-Gen, Starbucks is contracting for 24 MW of solar and 5.5 MW of battery storage from the Edwards and Sanborn project in Kern County, California. The project is expected to be fully online before 2023, according to Terra-Gen, a renewable energy developer owned by Equity Capital Partners, a private equity firm.
Other offtakers from the Edwards and Sanborn project include San Jose Clean Energy, which is buying 162 MW from Terra-Gen.
Starbucks is the first corporation to execute a virtual PPA for utility-scale storage, according to LevelTen, which helped arrange the transaction.
A virtual PPA is a financial deal under which the buyer pays a set price but doesn’t directly buy electricity from the project. Power from the project is sold into the wholesale market. If the wholesale price is higher than the price in the virtual PPA, the offtaker receives the difference. If the price is lower, the offtaker pays the facility owner to make up the difference.
“This new contract not only provides corporate buyers the economic benefits of storage, but also delivers developers a guaranteed revenue stream, enabling a more practical method for storage project financing,” LevelTen said Dec. 9 when Starbucks announced its deals.
Until now, contracting with utility-scale storage project developers was impractical for most corporations, according to LevelTen.
Stored renewable energy can be sold during the highest-priced hours of the day, often displacing coal- or natural gas-fired generation, the Seattle-based company said.
Also when organizations add storage to their wind and solar power purchase agreements, it can add value and smooth pricing variability by extending the hours of the day the energy is sold, LevelTen said.
“By providing a more practical way to contract with storage developers, this type of financial agreement opens the door to billions of dollars of investment in large-scale energy storage projects, in much the same way virtual power purchase agreements … ushered in a wave of wind and solar project development in the U.S. and beyond,” LevelTen said.
Starbucks also entered into a virtual PPA with an undisclosed solar farm in Virginia. The contract will offset half of its company run roasting and beverage production sites’ electricity use in the United States by 2022.
The coffee company said it is investing about $97 million in up to 23 new community solar projects in New York, which will supply solar energy to more than 24,000 homes, small businesses, nonprofits, churches, universities and Starbucks stores.
Starbucks aims to cut in half by 2030 the greenhouse gas emissions from its direct operations and supply chains.
NERC: Long-term resources are sufficient, except in Ontario and MISO
December 17, 2020
by Peter Maloney
APPA News
December 17, 2020
There should be sufficient resources to meet electric power demand over the next 10 years, except in two areas, according to a new report from the North American Electric Reliability Corp. (NERC).
NERC’s 2020 Long-Term Reliability Assessment estimated there would be adequate resources except in Ontario and the Midcontinent Independent System Operator (MISO) regions where projected reserve margins could fall below reference margin levels.
And while bulk power system capacity is sufficient in the other areas of North America, some areas demonstrate the potential for insufficient resources. Specifically, NERC identified “nearly all parts of the Western Interconnection,” the Electric Reliability Council of Texas (ERCOT) area and MISO as areas that “show levels of increased risk over the next five years.”
Overall, NERC’s long-term assessment noted that “the addition of variable energy resources, primarily wind and solar, the continued growth of distributed energy resources (DER) and the retirement of conventional generation are fundamentally changing how the grid is planned and operated.”
“As the system becomes more reliant on wind and solar generation, resource and energy adequacy must be assured,” Mark Olson, manager of reliability assessments at NERC, said in a statement. “The changing resource mix introduces greater variability, making long-term planning more complex. To meet this challenge, we need to create the necessary models, technology, and strategies to properly support future grid operators.”
The report also noted that throughout the 2021-2030 assessment period and particularly in the years between 2021 and 2025 there is “heightened uncertainty in demand projections” stemming from the ongoing COVID-19 pandemic.
The pandemic does not present a specific threat to the reliability, but it does lead to uncertainty in electricity demand projections and presents cyber security and operating risks that could exacerbate planning reserve shortfalls in areas that are below or near NERC’s reference margin levels, the report found.
With respect to the two areas of highlighted concern, reserve margins in Ontario could dip below recommended levels as soon as 2022, driven largely by refurbishments of nuclear power plants, demand forecast uncertainty, and the expiration of several generation contracts, NERC said in the assessment, which was released Tuesday. Ontario’s Independent Electric System Operator expects to acquire the required electricity resources through capacity auctions or other tools.
In MISO, NERC said there are adequate reserves in the short term, but there could be shortfalls in 2025. MISO and stakeholders will need to take action to ensure future resource adequacy by “achieving certainty of prospective resources beginning in 2025,” NERC said.
One of the challenges posed by the increasing level of intermittent resources on the grid is that it introduces a risk of inaccuracy into demand forecasts, NERC said. The output from those units can be inaccurate, but in areas with “embedded solar PV” demand forecasts can also be inaccurate. The result, according to NERC, is “operators must increasingly balance uncertain loads with uncertain generation.”
Additionally, as more flexible resources, mostly natural gas-fired generation, are added to the system to make up for the intermittent nature of wind and solar power, NERC noted the potential for an increase in “vulnerabilities associated with natural gas delivery to generators” that could potentially result in generator outages due to both insufficient natural gas infrastructure or alternate fuel delivery and/or disruption to natural gas or alternate fuel deliveries.” Those risks are most notable in New England, the desert Southwest, and California, where there is increased reliance on natural gas generation and limited back-up fuel, the report said.
To address the emerging risks and prevent the possibility of threats similar to those posed in Ontario and MISO occurring elsewhere, NERC recommended that regulators and policymakers “coordinate with electric industry planning and operating entities to develop policies that prioritize reliability, such as promoting the development and use of additional flexible resources, energy-assured generation, and resource diversity.”
NERC also recommended that regulators and policy makers consider revising their resource adequacy requirements to consider new risks that emerge during non-peak hours, limitations from neighboring systems during system-wide events, and the reduced resource diversity and/or increased reliance on a single fuel source or delivery mode.
Industry should also “identify and commit flexible resources to meet increasing ramping and load-following requirements” that result from increased variable energy resources and not solely to meet peak load capacity requirements, the report said.
PNNL transactive energy projects aim to improve DER integration
December 17, 2020
by Ethan Howland
APPA News
December 17, 2020
The Pacific Northwest National Laboratory (PNNL) is working on two projects designed to show how “transactive energy” can help efficiently manage distributed energy resources (DERs) such as rooftop solar.
Using market-based constructs, transactive energy provides a framework for the grid, buildings, electric vehicles, appliances and DERs to communicate with each other to balance real-time electricity supply and demand, according to the PNNL, a Department of Energy laboratory.
A more transactive energy system can improve efficiency, cost, and delivery while providing environmental benefits through the expanded use of intermittent renewable resources, according to PNNL. The approach could “substantially” reduce the amount of money spent updating and maintaining the nation’s energy infrastructure, the DOE lab said Nov. 23 in announcing the projects.
“Getting to the future transactive system will require advanced and automated control and coordination methods to enable the participation of flexible electrical loads,” Hayden Reeve, PNNL program manager, said.
The separate PNNL projects focus on technology deployment in Spokane, Washington, and on simulations of Texas’ primary power grid, operated by the Electric Reliability Council of Texas (ERCOT). The efforts are supported by the DOE Building Technologies Office and Office of Electricity, respectively.
PNNL tests transactive systems in Spokane
One project centers on Avista Utilities’ Eco-District, two buildings designed to test a shared-energy model where a centralized heating, cooling and electrical system can serve the energy needs of a group of buildings.
The buildings include solar panels, battery storage, thermal storage and sensors that track ambient conditions, air quality, occupancy and other attributes in real-time, according to Avista, an investor-owned utility.
In a multi-year, $7 million project, Avista plans to see how incentives can be used to manage the buildings’ energy loads and balance on-site energy demand, generation and storage in real-time, in a way that benefits the grid and provides flexibility for the building operators and the utility.
PNNL will bring to Avista’s project transactive energy management techniques developed at the laboratory-led Clean Energy and Transactive Campus.
The techniques include: intelligent load control, transactive coordination and control, a market-clearing mechanism, and automated fault detection and diagnostics, according to PNNL.
By being part of Avista’s project, PNNL said it will be able to refine the transactive energy management techniques and help develop a “shared-energy” model that other building owners and communities can use.
“Early on, our goal in CETC was to eventually conduct a broad field test to apply and evaluate some of the transactive and other energy-efficiency technologies we developed and demonstrated,” Srinivas Katipamula, a PNNL scientist, said. “Avista’s Eco-District aligned with DOE and PNNL objectives.”
Besides Avista’s two buildings, the project will include nearby retail and institutional buildings, according to Katipamula.
PNNL studies DER integration based on ERCOT model
Meanwhile, to see how transactive energy can help integrate DERs, PNNL researchers are conducting large-scale modeling, simulation and analysis based on ERCOT’s footprint, with the results extrapolated to reflect the U.S. grid.
“We are looking at participation of DERs from two perspectives: What we would see with an amount of renewable generation similar to that currently found in the Western U.S., as well as much higher levels, which would provide an idea of what’s possible if trends toward higher levels continue,” Rob Pratt, a PNNL engineer, said.
In addition to DERs, the project models a distribution system operator, the entity that conducts planning and operational functions associated with an electricity distribution system, including DER coordination, and a transactive network to realize the coordination, PNNL said.
Using the sophisticated modeling, PNNL researchers are studying the engineering and economic performance and identifying ways to provide economic benefits to grid operators and customers, according to the laboratory.
The researchers expect the study will affect two key products: a distribution system operations business framework and a compatible, field-ready transactive network design for coordinating DERs. The products will enable expanded testing of the concepts by industry and research institutions in simulations and the field, PNNL said.
Utility in deal for development of 100-MW battery storage project on NYPA-owned land
December 16, 2020
by Paul Ciampoli
APPA News Director
December 16, 2020
Solar and energy storage company 174 Power Global and investor-owned New York utility Con Edison on Dec. 16 announced the signing of a seven-year dispatch rights agreement for the development of a 100-megawatt battery storage project, the East River Energy Storage System, in Astoria, Queens.
The facility will be located on land owned by the New York Power Authority (NYPA) and leased under a long-term contract to 174 Power Global.
The battery system, which is expected to be one of the biggest in New York State, will be built and owned by 174 Power Global.
The new energy storage system represents a redevelopment of the Charles Poletti Power Plant property, repowering New York City’s grid with a clean energy resource.
“The New York Power Authority is committed to moving clean energy technologies forward and supporting initiatives that reduce greenhouse gas emissions and contribute to a healthier environment,” Gil Quinones, NYPA president and CEO, said in a statement.
“Additional energy storage development, especially in long duration storage, is key for the continued growth of renewable energy, such as hydro, wind and solar, to help us meet our peak energy demands and bring greater flexibility and resiliency to the New York State electric grid,” he said.
“This adaptive reuse of this land will help realize yet another clean energy project that moves us another step forward in meeting our aggressive climate leadership goals.”
The East River Energy Storage System is designed to balance peak electricity demands and provide grid reliability by delivering reactive power, voltage support and frequency stability to the New York region.
The energy storage system is expected to achieve commercial operation on Jan. 1, 2023.
Ames Electric, with Iowa State University, is hosting a ‘mobile microgrid’
December 16, 2020
by Peter Maloney
APPA News
December 16, 2020
Ames Electric Services in Iowa is providing support for a mobile microgrid project initiated by the Iowa National Guard.
The mobile microgrid comprises solar panels with a total capacity of about 15 kilowatts (kW) and six Tesla Powerwall lithium-ion batteries with a combined capacity of 60 kW, 78 kilowatt hours, all packed into a 20-foot shipping container.
The “microgrid in a case” can be readily shipped anywhere via truck or train or ship, unpacked and set up and be ready for service in two hours, Donald Kom, electric services director at Ames Electric, said. The equipment can generate single phase or three phase power at either 110 volts or 220 volts.
The mobile microgrid also includes a 6.5 kW diesel generator in case “all else fails,” Kom said, and Ames Electric Services is also looking at adding a small wind turbine to the equipment.
The project was developed by the Electric Power Research Center (EPRC) at Iowa State University and its partners, SunCrate and PowerFilm Solar for the Iowa Army National Guard.
Funding came from the National Guard and the Iowa Economic Development Authority.
The National Guard was interested in finding a way to have power at remote locations.
Even though the mobile microgrid was designed for uses such as emergency outages, in its current location it can be used by the public to charge electric vehicles. It is sited and in operation on a utility lot at the end of Main St. in Ames.
Kom said Ames Electric intends to add an electric vehicle charger to the box and begin offering electricity to EV owners.
“We want to use it as much as possible otherwise it is bad for the batteries,” Kom said. The mobile microgrid will provide a valuable test site for the performance and operation of the equipment and will also provide visibility for the microgrid and the renewable energy technology. “We are hoping that the public will come and check it out and plug stuff in,” Kom said. “This is a win-win for the both the project creators and the public. The site offers great visibility and opportunity for public education.”
“One of things we are trying to do is see how long the batteries last,” Kom said. “We are going to load it up as much as we can. We are going to put it through its paces.” The mobile microgrid is expected to stay on its current site for six to nine months. Ames Electric intends to collect data from the unit and share it with the EPRC, which can use it to make improvements and produce a second generation of the unit.
Kom said he also sees a potential benefit for the utility having a mobile microgrid. In August, Ames Electric was hit by a derecho that left some customers without power for up to a week. It would have been “a huge benefit” to have a mobile unit that could have provided power for customers to charge cell phones and other essential equipment, as well as providing a focal point from which the utility could disseminate information for customers, Kom said.
Separately, Ames Electric is preparing to go live with its first community solar project just before Christmas. Ames Electric is selling shares – what it calls Power Packs – in the 2.2 megawatt (MW) solar farm to its customers. Each share requires a $300 one-time investment and represents 175 watts of capacity.
Share owners will receive monthly credits on their utility bill, expected to be about $1 per month, based on the electrical output of the solar farm. Ames estimates customers could earn back their investment in 16 or 18 years, depending on how much the sun shines. About one-third of the shares will likely go to Iowa State University. Ames Electric would use the solar output not taken up by share owners to feed into its grid.
Ames Electric is also a recipient of an award stemming from a settlement with Volkswagen and is using the money to install at least two level-three electric vehicle chargers on Interstate 35.