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CPS Energy unveils pilot programs that incentivize EV home charging during off-peak hours

April 16, 2021

by Paul Ciampoli
APPA News Director
April 16, 2021

Texas public power utility CPS Energy on April 15 said it is introducing two pilot programs that incentivize electric vehicle home charging during off-peak energy demand hours and that help address drivers’ range anxiety.

CPS Energy said the addition of the two new programs for customers who charge their EV at home is in line with its Flexible Path strategy.

With the introduction of its FlexEV brand, “the utility recognizes the need to improve the environment by being a major supporter of EV adoption. CPS Energy is therefore unveiling new products and services to encourage drivers to consider alternative vehicles,” it said.

Under the FlexEV Smart Rewards program, participants will receive a one-time $250 enrollment credit on their utility bill. The customer will also receive a $5 monthly credit, equivalent to about 120 miles of driving, for allowing CPS Energy to remotely connect and carefully manage the customer’s charging device, as needed.  This would only occur when energy demand is high, between the hours of 2 p.m. and 9 p.m., Monday through Friday.  Specifically, if needed, CPS Energy would manage the flow of energy to the charger to help take pressure off the grid, the utility said.

Under the FlexEV Off-Peak Rewards program, a participant will receive a one-time $125 enrollment credit on their utility bill. The customer will also receive a $10 monthly credit for voluntarily choosing to limit charging to no more than two times a month between the hours of 4 p.m. and 9 p.m., Monday through Friday.

CPS Energy noted that it has 76 local ChargePoint charging stations in its FlexEV Public Charging program. In support of public charging, the utility’s program includes a flat-rate pilot program. This program has an annual fee of $96 for unlimited access to charging stations at any time of day or night.

If customers do not subscribe to the flat rate pilot program, they can still use the charging stations on a pay-as-you-go basis.

Public power utilities recognized for their efforts to shift to modern, carbon-free energy systems

April 15, 2021

by Paul Ciampoli
APPA News Director
April 15, 2021

Five public power utilities have been recognized by the Smart Electric Power Alliance (SEPA) for their efforts to transition to a modern and carbon-free energy system.

SEPA noted on April 14 that it launched the inaugural Utility Transformation Challenge to make a comprehensive, honest assessment of U.S. electric utilities’ progress towards a modern, carbon-free energy system.

SEPA said it conducted and analyzed multiple surveys designed to measure meaningful progress across multiple dimensions of utility infrastructure, programs, strategy and operations. Insights derived from these survey results form the basis for a new report: the 2021 Utility Transformation Profile.

SEPA received survey responses from 135 individual utilities, representing more than 83 million customer accounts, or approximately 63% of all U.S. electric customer accounts.

The report examines the utility industry’s transition to a clean and modern energy system by exploring four dimensions of utility transformation: clean energy resources, corporate leadership, modern grid enablement, and aligned actions and engagement.

With respect to what was learned from evaluating the utilities leading the clean energy transition, SEPA listed the following:

Utility Transformation Leaderboard

SEPA also unveiled the 2021 Utility Transformation Leaderboard, which SEPA said recognizes the ten utilities that have demonstrated the greatest progress in the transition.

Five of the 10 utilities on the leaderboard (in alphabetical order) are public power utilities (bolded):

“I am grateful for this prestigious recognition from the Smart Electric Power Alliance and appreciate the hard work of HG&E employees,” said James Lavelle, Manager of Holyoke Gas & Electric.

“As a municipal public power utility, HG&E is committed to providing innovative and sustainable energy solutions to our community through investments in a diverse power supply portfolio, energy storage, efficiency and conservation programs, as well as development of emerging clean energy technologies,” he said. “The State of Massachusetts has established a road map to net-zero by 2050 and HG&E is well positioned to meet this goal, as well as the incremental targets set for 2030 and 2040.”

“We are honored to be a part of SEPA’s Utility Transformation Challenge,” Seattle City Light General Manager and CEO Debra Smith said. “I think we all recognize the need to transform is a constant in our lives, businesses, and society. Creating a carbon-free energy system is never truly complete. City Light will continue to lead these efforts as our region moves toward a cleaner energy future.”  

“We’re proud to be leading the way in decarbonizing our economy,” said SMUD CEO and General Manager Paul Lau. “We’re at a point where we must commit to ambitious goals in order to achieve meaningful carbon reductions that benefit our community and the world.  Creating an inclusive, clean, green economy will improve economic, health and environmental outcomes, as well as drive a new, clean workforce and that’s something everyone can be excited about,” said Lau.

“We are honored to be on SEPA’s 2021 Utility Transformation Leaderboard,” said Jackie Sargent, Austin Energy General Manager. “Austin Energy is committed to grid modernization and affordable, carbon-free energy as approved by the Austin City Council. Inclusion on this list reinforces how important it is for the utility to continue these efforts and remain an industry leader.”

SEPA offers recommendations

SEPA provided recommendations for utilities of all sizes, types and geographies as they pursue their own path of transformation.

SEPA recommended utilities strengthen carbon reduction commitments by setting ambitious, science-based targets with interim goals and detailed plans to achieve them.

It also recommended that utilities address the transformation comprehensively across the organization through changes to processes, programs and structures that will accelerate clean energy adoption. 

Examples include pursuing integrated distribution planning, interconnection processes, evaluating non-wires alternatives (energy efficiency, demand flexibility, storage, etc.) to meet demands, developing a transportation electrification strategy and efficiently integrating and leveraging distributed energy resources.

Utilities should also embrace the clean energy transformation as a core element of the utility mission and culture. “This will require changes, such as linking executive compensation to reduced carbon emissions, establishing transparent emissions tracking and reporting programs and pursuing internal sustainability and carbon reduction programs (e.g., fleet electrification and supply chain programs),” SEPA said.

SEPA also recommended that utilities engage customers, technology partners, peer utilities and regulators early and often. “Common understanding and shared vision of new initiatives and technology deployments is critical to facilitate innovation,” it said.

In addition, SEPA said that utilities should integrate equity considerations and goals into efforts and programs to ensure all community members are able to participate in and benefit from the clean energy transformation.

The 2021 Utility Transformation Profile report and Utility Transformation Leaderboard are available here. Download the executive summary here.

DEED research in Texas studies how to mitigate EVs’ deterioration of transformer life

April 14, 2021

by Peter Maloney
APPA News
April 14, 2021

The Bryan Texas Utilities (BTU) used a Demonstration of Energy & Efficiency Developments (DEED) student research grant from the American Public Power Association to support a student to analyze mitigation strategies for the potential deleterious effect electric vehicles could have on utility transformers.

With the adoption of electric vehicles expected to rise rapidly in the future, BTU wanted to look at the use of rooftop solar power and battery storage to offset potential degradation of transformers caused by the expected increase in electric vehicle adoption and charging.

Studies showing average electric vehicle adoption rates can be misleading, Mladen Kezunovic, a professor of electrical engineering at Texas A&M University and the education advisor overseeing the DEED project, said. It is more likely that electric vehicle adoption will not occur evenly and will be concentrated in certain neighborhoods. In those neighborhoods, utilities could see much higher loads on their distribution transformers, possibly even a doubling of loads, Kezunovic said. And higher loads lead to higher heat in a transformer, which can shorten the expected useful life of the equipment.

Using the DEED grant, which took the form of a $5,000 scholarship, Milad Soleimani, a doctoral student at Texas A&M, developed a series of calculations to study the effect of overloading on transformers and mitigation strategies to offset those effects. The DEED study ran from December 2019 to December 2020.

The case study considered a residential area with a transformer with a nominal power of 63 kilovolt amps (kVa) and a total solar generation capacity of all the buildings of 10 kilowatts (kW). The rated power of the battery storage inverters was 5 kW, and it was assumed that the electric vehicles only operate in grid-to-vehicle mode.

For the study, Soleimani used load data available from the National Renewable Energy Laboratory (NREL) on OpenEI. Solar generation was calculated using NREL’s PVWatts Calculator. Weather data was extracted from the Iowa State University’s Environmental Mesonet archive. And electricity price data came from the Electric Reliability Council of Texas records.

The case study looked at seven different scenarios, ranging from a baseline with no electric vehicles, solar generation or battery storage to a scenario with a high penetration of electric vehicles with no solar or battery storage to a scenario in which there is solar generation, a high penetration of electric vehicles and battery storage is optimized by considering both electricity prices and transformer loss of life estimates.

Among the results, Soleimani found that the loss of energy in the charging and discharging of battery systems increases total energy consumption and presents challenges to the sole use of battery storage to mitigate transformer loss of life.

The study found that using battery storage, both with and without solar generation, optimized based on electricity prices, but did not mitigate transformer loss of life and had a negative impact on utility profits. The most successful approaches in the study were those that modeled the optimization of solar and storage based on prices and transformer loss of life calculations.

“Utilities as the owners of the distribution transformers benefit from the transformer loss of life mitigation strategy,” Soleimani wrote in the DEED report. “In the long term, the lower expenses for the utility will lead to cheaper electricity delivery to the end consumer. Thus, utility and consumers are both benefitting.” There should be incentives from utilities for consumers to make the investment viable, he said.

Broadly speaking, Kezunovic said the DEED study looked at three broad strategies: staggering electric vehicle charging times to minimize load, using solar photovoltaic panels and battery energy storage to minimize increased loads on transformers, and a combination of the first two options that uses algorithms to reduce the loads on transformers. The third option proved to be the most realistic, but it requires an algorithm for optimization that is not available today, Kezunovic said.

Today, “there is a disconnect between utilities and customer owned resources,” Kezunovic said. Utilities need to gain a better understanding of what customer resources, such as solar panels and electric vehicles, can do to their systems, he said, “and customers need to get on board with what utilities want them to do” and maybe utilities could incentivize them to do that.

CMPAS board announces hiring of Jay Anderson as agency’s new CEO

April 14, 2021

by Paul Ciampoli
APPA News Director
April 14, 2021

The Central Municipal Power Agency Services (CMPAS) Board of Directors announced the hiring of Jay Anderson as the agency’s new CEO.

Anderson, who will join CMPAS on May 3, 2021, comes to CMPAS from Bay City Municipal Electric Utility in Bay City, Mich., where he most recently served as Director of the Electric Utility.

Prior to working at Bay City, Anderson served for thirty years in various capacities with the Omaha Public Power District in Omaha, Nebraska, including as Project Director of the Power Forward Initiative. 

Anderson has spent his professional career in the Upper Midwest. CMPAS noted he is a tireless advocate for public power, most recently serving as at large member of the Executive Committee of the Michigan Public Power Association. 

In the past, he led the Large Public Power Association Rates Committee and spearheaded a sub-category of the LB901 “Condition Certain” legislation relating to what extent retail rates had been unbundled in Nebraska.

CMPAS conducted an extensive national search over the last eight months working with a search team consisting of CMPAS Board members and its General Counsel; Preferred Consulting LLC; and R. Bauman & Associates of Wisconsin.

CMPAS is a public power joint action agency providing power management and utility services for its electric utility members and affiliates.

CMPAS operates as a project-oriented, partial or full-requirements agency. CMPAS provides a wide range of services including strategic management, long-term power supply planning and procurement, energy market scheduling services, transmission ownership, project development and administration, utility accounting and finance support, and distribution mapping and modeling.

NCPA is exploring a hydrogen production facility with help from a DEED grant

April 13, 2021

by Peter Maloney
APPA News
April 13, 2021

The Northern California Power Agency (NCPA) is exploring the possibility of building a “green” hydrogen project, thanks in part, to the support of a Demonstration of Energy & Efficiency Developments (DEED) grant from the American Public Power Association.

The aim of the proposed project would be to build a hydrogen production and storage facility that could use over-generation associated with renewable energy resources to produce green hydrogen via electrolysis.

“We have been looking at the emerging technologies that can provide storage for renewable generation and hydrogen seems to check all the boxes,” Joel Ledesma, assistant general manager, generation services, at NCPA, said. “Producing hydrogen is not new but producing it at scale for the electric power grid is what is emerging.” The state of California, and the whole nation, is struggling with storage and generation that can be used to phase out fossil fuel generation, he added.

NCPA has evaluated other storage technologies but has found that lithium-ion battery storage is expensive for long term storage, pumped hydro storage is capital intensive and heavily regulated, and flywheel storage is difficult to scale up to meet commercial needs. NCPA has also evaluated technologies such as flow batteries, thermal salt storage, and compressed air energy storage and thus far deemed them not beneficial to its objectives.

NCPA would store the hydrogen produced at an electrolyzer and then blend with natural gas to be used as fuel at its Lodi Energy Center (LEC), a fast-start 300-megawatt (MW) combined-cycle plant the joint action agency uses to provide power during times of high demand.

NCPA’s current generation portfolio includes geothermal, hydropower, and natural gas-fired power plants with about half of the portfolio being emission free.

NCPA commissioned Black & Veatch to study the feasibility of a hydrogen production and storage facility. About half of the $96,600 study cost was covered by the DEED grant, which ran from December 2020 to February 2021.

Based on preliminary analysis and input from the turbine equipment manufacturer, NCPA believes its Lodi plant could co-fire up to 45 percent of hydrogen by volume.

“The blended fuel would provide about a 20 percent reduction in emissions from the Lodi plant and would be a step toward transitioning the facility to be fueled 100 percent by hydrogen,” Scott Tomashefsky, regulatory affairs manager at NCPA, said.

NCPA is considering siting the electrolysis facility near the Lodi plant, which would provide the dual benefit of being able to provide hydrogen for the transportation sector as well as using it for power generation. “To make hydrogen viable for the electric grid, it needs to be produced at a large scale,” so adding transportation could help make the project economics work, Ledesma said.

Among the primary conclusions of the study were that producing hydrogen using water electrolysis is technically feasible using commercially available technology and several vendors with commercial experience are available.

But even though there are several electrolyzer facilities operating around the world, the hydrogen energy storage facilities on the scale considered in the study are a relatively new phenomenon. The study also found that capital costs for hydrogen production and storage equipment is high and that electricity pricing contributes significantly to overall levelized costs. Nonetheless, projected pricing through the life of such a facility would appear to be “reasonable,” according to the DEED report.

In the study, Black & Veatch said it sees the potential for levelized cost of energy (LCOE) parity for a hydrogen facility that is used for co-firing a generator, as long as capital costs are reduced as much as possible, recovery and sales of oxygen from the facility are pursued, and renewable energy credit (REC) revenues can be shared with the renewable energy providers.

“Hydrogen may be feasible and practicable with the right incentives,” Ledesma said. The areas that need more study or follow-up, according to the DEED report, include:

The study marks another step toward our goal of eventually being able to fire the Lodi plant entirely with hydrogen, Ledesma said. NCPA plans to present the idea to its governing commission in order to adopt it as an emerging technology to track.

“California is seriously looking at whether natural gas remains in the future configuration of the power grid.” Tomashefsky said. “This study provides more context and helps move the conversation forward on what to do with the existing natural gas infrastructure.”

The study also does double duty, Ledesma said. It not only provides NCPA with valuable input as it negotiates a future with lower carbon dioxide emissions, but it helps inform other utilities and the public as a whole, so “we look at it as a dual benefit.”

APPA will host a webinar related to the project on May 4, 2021 from 2:00 pm to 3:00 pm EDT.

Additional details about the webinar are available here and DEED members can access the full project report here.

APPA says FERC cybersecurity incentive proposals are not needed to promote investments

April 13, 2021

by Paul Ciampoli
APPA News Director
April 13, 2021

Cybersecurity incentive proposals included in a Notice of Proposed Rulemaking (NOPR) issued by the Federal Energy Regulatory Commission (FERC) are neither necessary nor appropriate to promote effective cybersecurity investment, the American Public Power Association (APPA) said in April 6 comments submitted to FERC.

Moreover, the proposals outlined by FERC do not satisfy the requirements for incentive rate mechanisms under the Federal Power Act (FPA), APPA said in urging the Commission not to adopt the NOPR’s incentive rate proposals. 

The NOPR follows a FERC staff white paper issued in June 2020 that outlined an incentive framework for cybersecurity investments similar to the proposals included in the NOPR. 

APPA filed comments and reply comments in response to the white paper opposing the proposed incentives, while also making a number of recommendations regarding the structure and implementation of any cybersecurity incentive program the Commission chose to adopt.

The NOPR proposes an incentive rate framework intended to encourage voluntary cybersecurity investments that “go above and beyond” the current requirements of the Critical Infrastructure Protection (CIP) reliability standards established by the North American Electric Reliability Corporation (NERC), APPA noted.

The NOPR suggests that such investments could “materially enhance the cybersecurity posture of the Bulk-Power System by enhancing the applicants’ cybersecurity posture substantially above levels required by CIP reliability standards, to the benefit of ratepayers.”

The incentives would be available to public utilities, as well as “to non-public utilities to the extent that they have Commission-jurisdictional rates.”

In the context of FERC regulations, public utilities are defined as those that are Commission-jurisdictional (e.g., investor-owned utilities).

NOPR proposes two approaches

The NOPR proposes two cybersecurity investment approaches that may be eligible for incentives: the NERC CIP incentives approach and the National Institute of Standards and Technology (NIST) framework approach.

The NERC CIP incentives approach would award incentives for investments associated with voluntarily applying the CIP reliability standards to facilities that are not currently subject to the CIP requirements.

The NIST framework approach would award incentives for implementing certain security controls in the cybersecurity framework developed by NIST relating to automated and continuous monitoring.

Qualifying investments would be eligible for either a 200-basis point return on equity (ROE Adder) or a “Regulatory Asset Incentive” that would permit deferred cost recovery — with a return — for several categories of costs that have traditionally been treated as expenses.

Public utilities would not be eligible to receive the ROE Adder and the Regulatory Asset Incentive for the same expenditures.

APPA said that it recognizes that today’s electric grid faces increasing cybersecurity risks, and it appreciates the Commission’s efforts to assess how its policies might be best shaped to allow the industry to respond to these threats. 

“APPA respectfully submits, however, that the incentive program outlined in the NOPR is neither necessary nor appropriate to promote prudent public utility investment in cybersecurity measures. On the contrary if adopted, the White Paper framework could result in investment that raises transmission costs for customers without providing meaningful cybersecurity benefits in return,” the trade group said in the comments.

As an initial matter, the NOPR does not establish that the Commission has the authority to grant incentives to promote cybersecurity under its general ratemaking authority, APPA argued.

“Even if the Commission possesses such authority under the FPA, the incentive framework proposed in the NOPR fails to meet the longstanding requirements for just and reasonable incentive rates, including quantified benefits to consumers,” it said.

Neither generic application of CIP reliability standard requirements to lower impact Bulk Electric System (BES) cyber systems that are not currently subject to those requirements, nor broad adoption of NIST Framework security controls would necessarily result in a meaningful increase in cybersecurity, as the NOPR appears to assume, APPA said.

“This is not to say that use of these approaches in certain circumstances would not have cybersecurity benefits, but APPA disputes the assumption that widespread adoption of these approaches as contemplated in the NOPR would be a cost-effective way of achieving meaningful cybersecurity outcomes.”

APPA went on to say that even in circumstances where more robust cybersecurity investment might be beneficial, new incentives would not be just and reasonable because they are not needed to promote such investment. 

It said that the record from a March 28, 2019 technical conference convened by the Commission and the Department of Energy strongly supports this conclusion, and existing cost recovery mechanisms are sufficient to accommodate prudent cybersecurity investment. 

If the Commission proceeds with the NOPR, APPA said that it should preserve the features of the proposed rule that will help protect customers and ensure transparency, including:

Moreover, APPA said that FERC should adopt a number of clarifications or modifications to the proposed rule, including the following:

APPA earns extension of accreditation for education programs

April 13, 2021

by Paul Ciampoli
APPA News Director
April 13, 2021

The American Public Power Association (APPA) has received the International Association for Continuing Education and Training’s (IACET) Accredited Provider reaccreditation for an additional five years.

IACET accredited providers are the only organizations approved to offer IACET continuing education units, IACET noted in a news release. The accreditation period includes all programs offered or created during the additional five years.

APPA’s Academy encompasses all APPA education programs under one umbrella. The Academy offers the public power community a complete resource for professional education and certification, conducting over 150 yearly events (in-person, online, and in-house), which attract over 10,000 attendees.

Training formats include in-person education courses and conferences, in-house training, webinars and online training, and co-sponsored educational opportunities.

“We aim to provide educational resources for a variety of skill levels within key operational areas within the electric utility industry so that our members can maintain relevancy in today’s world,” said Joy Ditto, President and CEO of APPA.

Ditto added, “Our reaccreditation with IACET is a demonstration of our commitment to quality adult education and high standards for all of our programs. We are very pleased to be recognized by such a prestigious organization and be a part of an elite group of organizations that offer excellent continuing education and training programs.”

IACET said that in order to achieve the reaccreditation, APPA completed a rigorous application process and successfully demonstrated adherence to the ANSI/IACET 2018-1 Standard for Continuing Education and Training by addressing the design, development, administration, and evaluation of its programs.

APPA has pledged its continued compliance with the standard and is authorized to use the IACET name and Accredited Provider logo on promotional course material.

In addition, APPA is linked to the IACET web site and is recognized as offering the highest quality continuing education and training programs.

Public power utilities begin participating in CAISO’s Western Energy Imbalance Market

April 13, 2021

by Paul Ciampoli
APPA News Director
April 13, 2021

A number of public power utilities recently began participating in the California Independent System Operator’s (CAISO) Western Energy Imbalance Market (EIM).

The Turlock Irrigation District (TID) and the Balancing Area of Northern California (BANC) Phase 2, comprised of the Modesto Irrigation District (MID), the City of Redding, the City of Roseville, and the Western Area Power Administration (WAPA) Sierra Nevada Region, began participating in the West’s first real-time energy market on March 25.

“Joining the EIM provides MID continued access to the market’s diverse, readily-available power resource mix. Access to this low-cost, growing pool of resources will also further ensure and enhance service reliability to our customers,” Melissa Williams, Public Affairs Manager at MID, told Public Power Current.

“In addition, the EIM offers participants an increased ability to integrate renewable energy needed to meet California’s aggressive environmental goals, provides additional sources of real-time supply to augment reliability resources and, because it’s a voluntary market, allows participants to demonstrate support for regional markets while retaining local control,” she said.

“As participants in the EIM, we have the opportunity to further capitalize on the generation infrastructure TID has developed over the years,” said TID General Manager Michelle Reimers.

TID said its participation in the Western EIM will enable it to economically balance supply and demand within the market area in real-time by scheduling power deliveries every five minutes.

“The Western EIM will provide TID with access to a wider market and allow us to optimize our resources on a more granular scale,” said Dan Severson, TID Assistant General Manager, Power Supply.

“We’re excited that our leadership in the Western EIM successfully demonstrated enough success for our partners to join and expand participation,” said BANC General Manager Jim Shetler in a statement.  “This means greater reliability, lower costs and improved renewable generation for our customers.”

This move affects only WAPA’s Sierra Nevada Region in northern California and Nevada, which operates a sub-balancing authority within BANC.

WAPA is a power marketing administration within the Department of Energy responsible for selling and delivering federal hydropower across high-voltage transmission lines to customers in 15 Midwest and Western states. It is organized in five regions and a management center. 

The Western EIM will help the Sierra Nevada Region “better manage real-time supply and demand on a more frequent basis, harness market efficiencies, improve cost-effectiveness and mitigate the loss of bilateral trading partners in real-time energy transactions,” said Senior Vice President and Sierra Nevada Regional Manager Sonja Anderson.

Having a sub-balancing authority puts “us in a unique position to join the Western EIM; our status required innovative coordination and solutions for market economics, generator dispatch and grid reliability.”

BANC is a Joint Powers Authority consisting of the Sacramento Municipal Utility District (SMUD), MID, Roseville Electric, Redding Electric Utility, Trinity Public Utility District and the City of Shasta Lake as its founding members. SMUD became the first BANC member to join the Western EIM on April 3, 2019.

LADWP

Meanwhile, Los Angeles Department of Water and Power (LADWP) and the Public Service Company of New Mexico, an investor-owned utility, began participating in the EIM on April 1.

Participating in the Western EIM will be “a win-win proposition for the City of Los Angeles and the Western grid in terms of fostering the integration of renewable energy while maintaining power reliability, as the City of Los Angeles moves ahead with our goal of 100% renewables as well as assisting all California utilities in meeting the state target of 60% renewables by 2030,” said Reiko Kerr, LADWP Senior Assistant General Manager-Power System Engineering, Planning, and Technical Services, in a statement.

Among other benefits, LADWP said that participating in the Western EIM will help both LADWP and the state address the challenge of maintaining power reliability and reducing greenhouse gas emissions while optimizing the use of renewable energy, such as solar and wind power.

LADWP received approval in 2016 from Los Angeles Mayor Eric Garcetti, the City Council and the Board of Water and Power Commissioners to begin work to join the Western EIM.

LADWP said that the process has involved modifying LADWP’s transmission and generation systems with new grid-level information technology, new systems for billing and tracking energy transactions, improving bulk power metering, and other work to integrate the LADWP system with the ISO’s other Western EIM participants.

Arizona public power utility Salt River Project and Seattle City Light are also active participants of the Western EIM.

By 2023, 22 active Western EIM participants will represent over 83 percent of the load within the Western Electricity Coordinating Council.

Heartland develops web-based renewable energy calculator with DEED internships

April 12, 2021

by Peter Maloney
APPA News
April 12, 2021

Heartland Consumers Power District in South Dakota has developed a web-based renewable energy calculator using Demonstration of Energy & Efficiency Developments (DEED) internships from the American Public Power Association.

Heartland customers can use the calculator to determine the costs and benefits of installing a renewable energy facility, particularly a solar power array.

In 2019, Heartland initially developed this solar power calculator using a prior DEED internship for funding. Then, in 2020, the utility applied for and won another DEED internship that was used to make a more user friendly version of the original calculator.

Though it was functional and ran well, the original calculator ran on an Excel spreadsheet and used custom macros. Instead, Heartland wanted a version of the calculator that could run with a modern programming language like C# and could be used on any device with a browser such as a tablet or smart phone.

Heartland used its DEED internship to help fund a summer intern, John Kirkvold, a computer science major at South Dakota State University, who wrote the code for the new calculator.

The updated calculator uses data on solar power production from behind-the-meter installations while taking into account weather conditions as well as changing market prices. The calculator also takes into account state regulations that allow customers to sell solar output back to a utility, i.e., net metering. In states without net metering, the calculator uses avoided cost values to determine sale-back values.

After factoring in those variables, the calculator shows the user annual savings in payback time in years it would take a customer to recoup the cost of installing a solar array on their property.

The calculator has assumptions built into it based on the user’s location, which need to be updated periodically. Using a web interface ensures that the latest data is always available to the user.

The aim in designing the calculator was to allow customers to calculate the savings on their annual electric bill, as well as the annual cost to the utility and to the wholesale power entity.

The project also included making data displayed in Heartland’s lobby web functional and able to update automatically, particularly information on Heartland’s resources and generation.

NYPA signs agreement for planned deployment of zinc-air storage system

April 11, 2021

by Paul Ciampoli
APPA News Director
April 11, 2021

The New York Power Authority (NYPA) has signed an agreement with Zinc8 Energy Solutions Inc. and the University at Buffalo for the planned deployment of the company’s zinc-air energy storage system, marking a first demonstration of a long-duration use in New York State and a development that could support further integration of renewable power sources into the electric grid.

“NYPA continues to place a priority on fighting climate change and promoting a clean energy economy, and this first-of-its-kind long-duration solution has the potential to be deployed into a range of scalable applications,” said Gil Quiniones, NYPA president and CEO, in a statement. “The collaboration with Zinc8 and the University at Buffalo bodes well for a successful demonstration project that addresses the need for reliability of renewable energy resources and will help New York State help achieve its targets for energy storage.”

Selection of the site will allow for the demonstration of a 100 kilowatt/1 megawatt-hour zinc-air battery energy storage system in Buffalo to facilitate the wider use of renewable resources.

Zinc8 won a contract to accelerate the new technology in the Innovation Challenge, a partnership between NYPA and the Urban Future Lab at New York University’s Tandon School of Engineering.

The deployment will provide peak shaving capability by leveling out peaks in electricity consumption, increase campus resiliency and assist in educating campus utility staff with new energy storage technology, NYPA said.

The project will also validate the performance reliability of the system and help determine the O&M and estimated life cycle costs.

Zinc8’s zinc-air energy storage system will be located less than a few hundred feet from the award-winning UB Solar Strand, a project that NYPA and University at Buffalo completed nearly a decade ago, and the newly relocated GRoW Clean Energy Center.

Under the agreement with Zinc8, NYPA will contribute to the installation costs of the energy storage system at University at Buffalo and share in the data generated during the demonstration period.