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Ann Arbor, Mich., Council Member To Make Proposal Related To Public Power Feasibility Study
August 24, 2021

August 24, 2021

by Paul Ciampoli
APPA News Director
August 24, 2021

Ann Arbor, Mich., Council Member Elizabeth Nelson plans to introduce a resolution at an upcoming city council meeting that will ask the Ann Arbor Energy Commission to consider and vote on the question of a public power feasibility study for the city.

“The recent multi-day power outage has prompted a lot of conversation in our community about improving the reliability of our electricity and the city’s relationship with DTE, specifically,” wrote Nelson in a recent blog posted on her website.

“For some time now, many local leaders have advocated for a public municipal power utility, similar to what already exists in over forty municipalities in Michigan. Arguments in favor of a public utility include: reliability, sustainability, accountability, and affordability,” she wrote.

The city’s Energy Commission is close to concluding what has been many months of discussion about a public utility. In February, the Commission heard a presentation about public power, as well as advocacy from Michigan State Rep. Yousef Rabhi and State Sen. Jeff Irwin.

In July, the Energy Commission heard another presentation on the topic of a municipal utility, including legal advice about how to achieve it in the state of Michigan. At that meeting, the Commission was asked to recommend funding for a feasibility study.

“Because public utilities exist across Michigan, there is a lot that we know already in terms of how it would function in Ann Arbor,” wrote Nelson. “However, a feasibility study is the appropriate first step in exploring this option. There is significant support in the community for a public power utility, but it is also appropriate that Council receive advice from the Energy Commission regarding this feasibility study.”

Nelson said that she will have a resolution on the agenda for the next city council meeting on Sept. 7, 2021, that asks the Energy Commission to consider and vote on the question of a feasibility study.

She wants the Energy Commission vote to be taken at their next meeting on Sept. 14, so that the Ann Arbor City Council can receive their recommendation in time to vote on it at the council’s next meeting on Sept. 20.

Nelson said that a recommendation for a feasibility study does not bring immediate action, “but does push our efforts in a specific direction: establishing the parameters of the study and identifying the appropriate entity to do that study.”

The American Public Power Association offers a wide range of resources and information related to municipalization on its website.

Special Series: Managing Insurance Risks Takes On Greater Significance With Natural Disasters, Cyber Attacks – Part One

August 23, 2021

by Paul Ciampoli
APPA News Director
and Peter Maloney
August 23, 2021

Per member requests, the American Public Power Association presents this in-depth Public Power Current newsletter series on managing insurance risks. Thank you to the utility systems and industry experts for their contributions about what is happening in the insurance market that is affecting policy coverage and prices (Part 1); types of “best practices” utilities can utilize to minimize their exposure (Part 2); and what potential alternatives may be available to help in a challenging insurance market (Part 3). 

Risks to utility operations are rising and with them the cost of insurance is rising too.

In this environment, it can be difficult for a public power utility to retain essential insurance coverage while containing costs. The fact of the matter is that insurance companies have had to make large payouts to customers who have suffered massive losses.

Losses from natural disaster hit $133 billion in 2017, a historic high, according to the Insurance Information Institute. That year saw a deadly combination of hurricanes – Harvey, Maria and Irma – as well as costly California wildfires. Losses due to natural catastrophe fell in 2018 and 2019, but rose again in 2020, hitting $74.4 billion, an 88 percent increase from $39.6 billion of losses in 2019.

In 2020, the most costly losses came from storms and cyclones, which accounted for about 75 percent of the $119 billion in losses, followed by wildfires, accounting for nearly 20 percent of losses, and flooding, which accounted for 4 percent of losses, according to the Insurance Information Institute.

Insurance company SwissRe ranked 2020 as the fifth costliest year on record since 1970 for the insurance industry with global losses totaling $83 billion. The losses were driven by a record number of severe convective storms (thunderstorms with tornadoes, floods and hail) and wildfires in the United States. Those and other secondary events around the world accounted for 70 percent of the $76 billion of insured losses from natural catastrophes, the institute said.

In order to recapitalize after those losses, insurance companies have a few options that are not necessarily exclusive of each other. They can increase the premiums they charge customers, or they can raise the bar in terms of which entities they will insure.

“Insurance carriers have been affected by storms and claim payouts for their insureds, social inflation, and record setting verdicts,” Ryan Weber, vice president at Marsh USA, said. Pricing has increased the past 15 consecutive quarters, he noted.

The good news, Weber said, is that there were signs in the second quarter that the market could be adjusting in insureds’ favor for coverage lines such as property and liability. “Cyber liability pricing appears to be heading in the wrong direction, however, due to the severity and frequency of the recent cyber breaches in 2021,” Weber said.

The cyber ransomware attack on Colonial Pipeline in the U.S. earlier this year, as well as other ransomware attacks, has resulted in increased attention to the risk insurance market. Colonial Pipeline is the largest refined products pipeline in the United States, transporting more than 100 million gallons of fuel daily to meet the energy needs of consumers from Houston, Texas to the New York Harbor.

In May 2021, the Government Accountability Office (GAO) issued a report on cyber insurance. It said that key trends in the current market for cyber insurance include the following:

Meanwhile, in a recent podcast, CAC Specialty’s Adam Lantrip addressed the current cyber insurance market, recent ransomware events, and some tips for coordinating insurance and the technology and legal venders who assist companies in responding to attacks.

CAC Specialty is a specialty insurance brokerage firm.

“Where things are going is clients are going to have to demonstrate a much higher baseline level of security in order to qualify for coverage,” said Lantrip on the podcast. Lantrip is CAC’s senior vice president for professional liability and cyber practice leader.

A year and a half ago, “we could have taken just about any company into the marketplace with whatever their controls were and probably been able to get them a pretty good option from somebody in the insurance marketplace,” Lantrip said.

“Today, we’re seeing clients that we would objectively think are generally pretty good risks but they’re answering ‘no’ to one or two or three very specific questions about their security posture and those ‘no’ responses” are resulting in an automatic refusal “from a huge section of the marketplace.” When that happens, “the ability to get coverage starts to shrink.”

A robust cybersecurity insurance market could help reduce the number of successful cyberattacks by: (1) promoting the adoption of preventative measures in return for more coverage; and (2) encouraging the implementation of best practices by basing premiums on an insured’s level of self-protection, notes the U.S Cybersecurity and Infrastructure Security Agency (CISA), which is part of the Department of Homeland Security.

“Many companies forego available policies, however, citing as rationales the perceived high cost of those policies, confusion about what they cover, and uncertainty that their organizations will suffer a cyberattack,” in recent years CISA says. CISA has engaged key stakeholders to address this emerging cyber risk area.

Since 2012, CISA has engaged academia, infrastructure owners and operators, insurers, chief information security officers (CISOs), risk managers, and others to find ways to expand the cybersecurity insurance market’s ability to address this emerging cyber risk area. More broadly, CISA has sought input from these same stakeholders on the market’s potential to encourage businesses to improve their cybersecurity in return for more coverage at more affordable rates. 

CISA is currently facilitating dialogue with CISOs, Chief Security Officers, and insurers about how a cyber incident data repository could foster both the identification of emerging cybersecurity best practices across sectors and the development of new cybersecurity insurance policies that “reward” businesses for adopting and enforcing those best practices.

In Part 2, tomorrow, we will explore some of the “best practices” utilities have undertaken to minimize their exposure to higher insurance rates.

APPA Resources

APPA has numerous member resources available to help risk managers.

Moody’s Says Hydrogen’s Potential As Power Sector Fuel Is Enormous

August 23, 2021

by Paul Ciampoli
APPA News Director
August 23, 2021

Hydrogen’s potential as a fuel in the power sector and the broader economy is enormous, although electric and gas utilities are unlikely to be the primary demand growth driver of the hydrogen market over the next decade, Moody’s Investors Service says in a new report.

“Hydrogen’s growth potential rests in large part on its green appeal – specifically, its potential role in decarbonizing the economy, particularly the transportation, industrial, gas and power sectors,” the rating agency said in the Aug. 11, 2021 report.

Moody’s said that while hydrogen has enormous potential in power and heating applications, electric and gas utilities are unlikely to be the primary demand growth driver of the hydrogen market over the next decade, either in the U.S. or globally.

“In addition to high costs, there are significant efficiency losses associated with its production, which can range anywhere from around 30% to over 70% based on the technology used, making its production more expensive than the electricity or natural gas used to produce it. However, hydrogen is likely to play an important role in US efforts to eliminate carbon emissions from the power sector by 2035,” the report said.

While the U.S. consumes more than 11 million metric tons of hydrogen per year, its use is practically nonexistent in the power sector, Moody’s said.

At the same time, Moody’s said that hydrogen’s potential as a fuel in the power sector and the broader economy is huge.

The report notes that the National Renewable Energy Laboratory (NREL) expects U.S. demand for hydrogen to surge two- to fourfold by 2050, to around 1% to 14% of energy demand. Over the same period, the Department of Energy (DOE) estimates that the hydrogen economy could grow to $750 billion in annual revenue from an estimated $17.5 billion today.

Most of this demand growth is likely to come from the transportation sector, followed by industrial uses (refining, chemical, iron and steel and other), with building heat and power and power generation expected to account for around 19% of the demand by 2050, according to a report coordinated by the Fuel Cell and Hydrogen Energy Association, the rating agency went on to note.

Moody’s points out that hydrogen can already be blended with natural gas for use as a fuel for power generation, albeit with some limitations. Power equipment manufacturers are developing a new generation of gas turbines that can run on 100% hydrogen and there are several pilot projects and at least two larger power plants being developed in the U.S. that will initially burn blends of hydrogen and natural gas, before transitioning to 100% hydrogen, Moody’s said.

“Hydrogen can also be used as an energy carrier for long-term seasonal storage, reducing the need to curtail excess renewable energy production or using nuclear power and providing dispatch flexibility to the grid to help manage peak demand,” the report said.

Moody’s also said that national and state policies and regulations could help increase hydrogen use. It noted that DOE this year unveiled $160 million in federal funding for projects to develop technologies for the production, transport, storage and use of hydrogen. “Wider implementation of carbon instruments, such as allowances and taxes, could help make hydrogen more cost-competitive,” the report said.

Federal and state incentives are also available for the development of carbon capture, utilization and storage technology, an essential component in the production of “blue” hydrogen, which is produced from natural gas, according to Moody’s.

The American Public Power Association (APPA) recently issued a report that provides a perspective on where the emerging hydrogen market is in the U.S. and globally, what is driving the growing interest in hydrogen and what obstacles are preventing hydrogen technology from being able to scale-up.

In a recent blog, Patricia Taylor, Senior Manager, Regulatory Policy and Business Programs at APPA, notes that there are different motivations for the interest in hydrogen in the energy sector these days.

SRP, BPA Meteorologists Detail Steps Smaller Utilities Can Take To Fill Forecasting Gaps

August 18, 2021

by Paul Ciampoli
APPA News Director
August 18, 2021

Arizona’s Salt River Project (SRP) and Oregon-based Bonneville Power Administration (BPA) both have teams that focus on forecasts of temperature and precipitation, among other things.

But what about smaller public power utilities that don’t have a meteorologist on staff? What steps are available to them to help fill the gap in terms of weather forecasting without their having to hire a full-time meteorologist?

“That is a great question because public power utilities vary so much, not only in the number and type of customers, but in the geography they are concerned about,” said Erik Pytlak, who has served as BPA’s Manager of Weather and Streamflow Forecasting since November 2010. “So my advice for a Snohomish PUD is going to be very different than Minidoka, ID, which will be different than the Confederated Salish-Kootenai Tribe.”

He said it may come down to what weather issues the utility is most concerned about and going from there. “Fortunately, there are many weather apps, websites and whole companies that share weather information – some of it for free or at low cost, for utilities of any size and scale to use,” Pytlak said.

“The other suggestion is for the power utilities to talk to each other,” he said. “Even a power marketing agency like BPA gains quite a bit from networking, coordinating and even collaborating with hydropower utilities in the region and even globally, both large and small, on best practices we are finding and developing.”

BPA
BPA’s Erik Pytlak (photo courtesy of BPA)

Bo Svoma, who has been a meteorologist at SRP for over four years, said that staff in a smaller utility company can become familiar with the products issued by the National Weather Service, Climate Prediction Center, and River Basin Forecast Centers. There are also many private companies that offer weather forecast services, he noted.

“At SRP, management has determined a staff of meteorologists and hydrologists is necessary to plan for the dry and wet years that Arizona has always experienced and will continue to see,” he said.

Bo
SRP’s Bo Svoma (photo courtesy of SRP)

Unique geographic challenges

Svoma noted that SRP meteorologists are responsible for producing both short-term (same day/weather advisory) and longer term (7-10 day to seasonal) forecasts of temperature and precipitation to support both power delivery and water delivery.

They are also responsible for quality control of Salt-Verde watershed precipitation records, monitoring the Salt-Verde watershed to inform streamflow forecasts (flood cameras, snow surveys, etc.) and offering expertise both externally and internally for research projects that help achieve SRP’s short-term and long-term goals (snow hydrology, climate change, etc.).

SRP is the largest provider of electricity in the greater Phoenix metropolitan area, serving more than 1 million customers. SRP is also the metropolitan area’s largest supplier of water, delivering about 800,000 acre-feet annually to municipal, urban and agricultural water users.

When asked to detail some of the unique challenges he faces as a meteorologist at SRP in terms of the utility’s geographic location, Svoma said that the two wet seasons in Arizona pose unique forecasting challenges that are not present in other parts of the country.

During the summer months, the Phoenix metropolitan area experiences a combination of high temperatures and humidity during the North American Monsoon Season that leads to frequent threats of excessive heat, severe thunderstorms, flash flooding and haboobs, which are intense dust storms.

Svoma said that during the winter, high volumes of inflow into the reservoir system from the Salt-Verde rivers can be generated by rainfall, rain-on-snow, and snowmelt, posing forecast challenges that are absent in many higher latitude basins. Currently, the SRP watershed is in its 26th year of drought, he noted. “Thanks to continuous and efficient planning, SRP has remained resilient and will be able to continue to provide water to its more than 2 million customers,” he said.

Pytlak also addressed the question of some of the unique challenges that he faces as a meteorologist at BPA in terms of the utility’s geographic location.

“I am not sure if this is unique among utilities, but the sheer size of our service territory and river basins feeding our hydroelectric projects means we also have very diverse geography,” he said. “Our forecasting area ranges from deserts in southeast Oregon, to rainforests on the Oregon and Washington coasts, to subarctic mountains in southern British Columbia. The Columbia Basin is also right along the path of the jet stream for much of the year, which also drives quite a bit of weather variability.”

BPA earlier this year profiled the work of Pytlak and his team on its website.

BPA is a nonprofit federal power marketing administration based in the Pacific Northwest. BPA markets wholesale electrical power from 31 federal hydroelectric projects in the Northwest, one nonfederal nuclear plant and several small nonfederal power plants.

The dams are operated by the U.S. Army Corps of Engineers and the Bureau of Reclamation. The nonfederal nuclear plant, Columbia Generating Station, is owned and operated by Energy Northwest, a joint operating agency of the state of Washington. BPA provides about 28 percent of the electric power used in the Northwest and its resources — primarily hydroelectric — make BPA power nearly carbon free.

BPA’s territory includes Idaho, Oregon, Washington, western Montana and small parts of eastern Montana, California, Nevada, Utah and Wyoming.

Scorching temperatures this summer

Meanwhile, much of the West has experienced scorching temperatures this summer including Arizona. Svoma was asked whether there have been any surprises in terms of weather patterns so far this summer.

“The early start to the North American Monsoon season, while not entirely surprising given the dry winter in the western U.S., was a little unexpected given that many of the long-range weather models did not indicate an early onset,” he said. The Salt River observed a steady increase in streamflow beginning in early July, earlier than normal and suggesting abundant rainfall in the mountains.

Pytlak said that the June 2021 heat wave “was certainly unprecedented for many of us. Perhaps the biggest surprise is that the weather models that we use from U.S., Canadian, and European weather agencies all handled the extreme event quite well, which gave us and the region valuable time to prepare. The fact we came through the event with virtually no service interruptions was testament to the preparations we always make for extreme events, and how everyone in the region worked together to not only keep the lights on, but also keeping life-saving cooling systems running.”

EIA Reports That Per Capita U.S. Residential Electricity Use Was Flat In 2020

August 18, 2021

by Paul Ciampoli
APPA News Director
August 18, 2021

Although many people spent more time at home last year in response to the COVID-19 pandemic, retail sales of electricity to the residential sector in the United States, calculated per capita (per person), averaged 4,437 kilowatt hours (kWh) per person, only 1% more than in 2019, the U.S. Energy Information Administration (EIA) recently reported.

Warmer weather in 2020 — including a significantly warmer winter — increased electricity consumption for air conditioning during the summer but reduced U.S. home electricity consumption for space heating during the winter, EIA said on Aug. 6.

From 1960 to 2010, per capita U.S. residential electricity use increased by an average of 3% per year. However, that trend reversed over the past decade because of warmer weather and energy efficiency improvements, EIA noted. Per capita residential electricity use has fallen 5% in the United States since 2010.

EIA said that per capita U.S. residential electricity use varied widely across the states in 2020, from 2,018 kWh per person in Hawaii to 6,663 kWh per person in Louisiana. Nearly all of the states with the highest residential electricity sales per capita, such as Louisiana, Alabama, and Mississippi, are in the South census region, where air conditioning and electric space heating are most prevalent. About 64% of southern homes heat primarily with electricity, compared with about 25% of homes outside of the South.

The only state with relatively high per capita residential electricity use outside of the South is North Dakota, which has the coldest average annual temperature in the Lower 48 states. About 41% of homes in North Dakota heat with electricity, EIA said.

“In 2020, per capita residential electricity use decreased in many of the states where electricity is widely used for home heating, including many states in the South. In 2020, the District of Columbia’s per capita residential electricity use fell 4% compared with 2019, a larger decrease than for any of the states, followed by Arkansas (-4%) and North Dakota, Indiana, North Carolina, South Dakota, and Missouri (-3% each),” EIA reported.

But per capita residential electricity use rose significantly in the West census region. According to EIA, many states in this region experienced their warmest summers on record in 2020. Arizona’s per capita residential electricity use increased 10% compared with 2019, the largest increase of any state, followed by Nevada, Alaska, and California (9% each).

NYPA Launches Study to Assess Potential Impact Of Climate Change On Its Operations

August 17, 2021

by Paul Ciampoli
APPA News Director
August 17, 2021

The New York Power Authority (NYPA) will study the long-term effects of climate change on its physical power generation and transmission assets and system operations, NYPA said on Aug. 5.

The research, in collaboration with Argonne National Laboratory, a U.S. Department of Energy science and engineering research center, the Electric Power Research Institute (EPRI) and Columbia University’s Center on Global Energy Policy (CGEP), aims to inform NYPA’s risk and expenditure planning and strengthen its resilience against all hazards, including major weather events.

The study will be conducted by Argonne. NYPA noted that Argonne is known as a world leader in creating hyperlocal climate model simulation datasets and as having the most detailed climate projections available in the U.S.

For the study, an interdisciplinary team of scientists and engineers will use state-of-the-art climate and infrastructure system modeling techniques, and one of the world’s fastest supercomputers, to determine the risks an ever-changing climate may pose to NYPA’s infrastructure and operating systems.

Researchers will identify and quantify the potential impacts of climate change on NYPA’s critical facilities, assets and equipment, and produce a system-wide assessment of location-specific climate risks overlaid onto NYPA’s energy system infrastructure. Argonne’s experts will also develop a climate resiliency plan that will inform how NYPA mitigates any climate-related potential risks. The study’s planned simulations will use three different global climate models and two different greenhouse gas emission scenarios which are designed to capture much of the modeling and planning uncertainties associated with climate change projections.

Study results are expected in the spring.

The analysis is part of a multi-year sustainability plan outlining steps NYPA needs to take to enhance its long-term environmental, social and governance performance across the authority. The study is the first phase of a four-year climate adaptation and resilience assessment.

A second phase in 2023 will assess the social and economic impacts of climate change on NYPA’s customers, communities and other stakeholders, and identify strategies to support regional and community adaptation and resilience planning efforts.

NYPA as a power system infrastructure owner and operator will conduct quantitative climate-informed risk assessments to identify vulnerabilities. The study will also inform the appropriate design and operational standards and specifications of NYPA’s customer solutions projects such as energy efficiency, solar, storage and electric vehicle charging stations.

In the early stages of the project, CGEP will provide input on the proposed approach from Argonne for applying climate and energy infrastructure models in the research. In this part of the process, CGEP will contribute its expertise in integrating global energy systems and climate models. CGEP will also contribute expertise in scenario design for energy systems analysis under uncertainty during the modeling planning phase. After the initial analysis is complete, CGEP will serve on the results review panel, providing feedback on the outputs, insights, and any corresponding recommendations.

U.S. Large-Scale Battery Storage Power Capacity Increased 35% In 2020

August 17, 2021

by Paul Ciampoli
APPA News Director
August 17, 2021

The U.S. continued a trend of significant growth in large-scale battery capacity, with U.S. battery power capacity reaching 1,650 megawatts (MW) by the end of 2020, the U.S. Energy Information Administration (EIA) reported on Aug. 16.

According to EIA’s report, Battery Storage in the United States: An Update on Market Trends, U.S. battery power capacity grew by 35% in 2020 and has tripled in the last five years.

EIA expects that most large-scale battery energy storage systems to come online over the next three years will be built at power plants that also produce electricity from solar photovoltaics, a change in trend from recent years.

As of December 2020, the majority of U.S. large-scale battery storage systems were built as standalone facilities. Only 38% of the total capacity to generate power from large-scale battery storage sites was co-located with other generators: 30% was co-located specifically with generation from renewable resources, such as wind or solar PV, and 8% was co-located with fossil fuel generators.

“We expect the relationship between solar energy and battery storage to change in the United States over the next three years because most planned upcoming projects will be co-located with generation, in particular with solar facilities,” EIA said in the report.

storage
EIA TABLE

If all currently announced projects from 2021 to 2023 become operational, then the share of U.S. battery storage that is co-located with generation would increase from 30% to 60%.

Based on planning data collected by EIA, an additional 10,000 MW of large-scale battery storage’s ability to contribute electricity to the grid is likely to be installed between 2021 and 2023 in the United States, which is10 times the total amount of maximum generation capacity by all systems in 2019.

Almost one-third of U.S. large-scale battery storage additions will come from states outside of the PJM Interconnection and the California ISO, which led in initial development of large-scale battery capacity.

Five states account for more than 70% of U.S. battery storage power capacity as of December 2020, with California alone accounting for 31% of the U.S. total (506 MW). Texas, Illinois, Massachusetts, and Hawaii each have more than 50 MW of power capacity.

More than 400 MW of small-scale total battery storage power capacity also existed in the United States as of 2019, with California accounting for 83% of the capacity. Small-scale batteries have a nameplate power capacity of 1 MW or less.

U.S. battery system energy capacity also continued to increase, reaching 1,688 megawatt hours at the end of 2019, a 30% increase from 2018.

The entire report is available on the EIA website.

DEMEC Establishing First In-State Training Yard For Apprentice Lineworkers

August 17, 2021

by Paul Ciampoli
APPA News Director
August 17, 2021

The Delaware Municipal Electric Corporation (DEMEC) is establishing its first in-state training yard for eight municipalities to train apprentice lineworkers in best practices and servicing unique systems, DEMEC reported on August 10.

DEMEC bought five acres of land next to ShureLine Electrical in Delaware’s Smyrna Industrial Park in April. With a target opening of spring 2022, the wholesale power supplier is planning to install a series of utility poles, transformers and substation infrastructure on site to host classes for its membership.

DEMEC is a joint action agency that represents eight power-producing Delaware towns and cities that serve 99,200 people. Members include Clayton, Dover, Lewes, Middletown, Newark, New Castle, Seaford and Smyrna.

DEMEC noted in a news release that lineworkers are typically sent to out-of-state programs that may last up to two weeks for training that is required for the field. Delaware has no facility of its own to send lineworkers, and DEMEC has three utility poles behind its Smyrna headquarters for small training sessions.

The new facility will open up more possibilities for larger classes.

“In-state training will allow for greater member participation and cost savings. Additionally, it keeps lineworkers closer to home should services be required at a moment’s notice,” DEMEC Chief Operating Officer Kimberly Schlichting said in a statement. “Best practices and safety training for lineworkers is never-ending and is paramount for this line of work.”

Site improvements will include utility poles for climbing and bucket truck use, shorter poles for group demonstrations, meter panels, an underground training area, a substation training area as well as a sidewalk and a parking lot.

The training yard and program will be open to DEMEC members’ apprentice lineworker (levels 1 to 4), journey lineworkers, foremen and others. Outdoor hands-on training may range between 10 to 20 students, but apprentice training classes are expected to be small for a stronger instructor-to-student ratio, DEMEC said.

“It really comes down to the needs of our members at any point in time,” said Schlichting, who will become DEMEC CEO in October.

DEMEC’s training yard will give lineworkers more hands-on exercises, specifically in each Delaware town’s own distribution systems. Utility managers from DEMEC-associated towns each weighed in on the future training yard to ensure the tools available will help meet town-specific standards.

DEMEC officials see the training yard as a long-term investment, and if the program grows larger, then the hope would be to relocate to another site but keep the property for other uses.

“It’s conveniently located and provides convenient access to our members which span from the northern to southern municipalities in Delaware,” Schlichting said. “As technology continues to advance and change, so will best practices change. This program will allow our members to stay on top of those changes and even ahead of anticipated innovative practices.”

In a recent episode of the American Public Power Association’s Public Power Now podcast, Schlichting, Gary Johnston of the Lewes Board of Public Works in Delaware and Joshua Little of the Town of Smyrna, Delaware, discussed the Light Up Navajo project, an initiative to connect Navajo homes to the grid.

Click here for access to that episode as well as other Public Power Now podcast episodes.

Facebook Will Be Salt River Project’s Largest Off Taker For New Solar Energy Plants

August 16, 2021

by Paul Ciampoli
APPA News Director
August 16, 2021

Following its recent announcement to expand utility-scale solar resources to 2,025 megawatts (MW) by 2025, Arizona’s Salt River Project (SRP), based in Tempe, on August 12 announced three new solar energy plants that will deliver a total of 500 megawatts (MW).

Facebook announced that it will be SRP’s largest off taker of these new resources, utilizing 450 MW of the combined solar capacity to support Facebook’s newly announced data center in Mesa, Ariz., and help meet the company’s 100 percent renewable energy commitments.

The three projects include two 200-MW solar plants and one 100-MW solar plant. SRP is contracting with subsidiaries of solar developers AES, EDP and NextEra Energy Resources to construct and operate the three new plants. The first project is expected to come online in fall 2022 and the start of construction for all the new solar plants, which will all be located in Pinal County, Ariz., will begin at different points in time throughout 2022.

“Doubling our solar resources to over 2,000 MW and having one of the largest storage commitments in the West is among the strategic ways SRP is enhancing access to sustainable solutions for customers,” said SRP’s CEO and General Manager Mike Hummel in a statement. “Facebook’s approach aligns well with SRP’s carbon reduction commitments and working together on this project helped accelerate SRP’s plans to add more solar generation to our energy mix,” he said.

The Facebook data center in Mesa will receive water credits for its operations from an agreement with Gila River Water Storage, LLC (GRWS), SRP’s joint venture with the Gila River Indian Community which provides renewable water in the form of long term storage credits to entities seeking additional supplies. The data center will procure these credits from GRWS water storage, which means that it will not use any water rights from Mesa’s municipal supply for operations.

Adding 500 MW of solar energy to SRP’s power grid to support the energy needs of Facebook’s data center in Mesa, as well as SRP small business customers, will save hundreds of millions of gallons of water per year than if the same amount of energy were generated by fossil fuel-burning resources, SRP said.

Here are additional details on the new projects:

West Line Solar

The first of the new solar plants scheduled to be commercially operational is “West Line Solar.” The 100 MW plant will come online in October 2022. SRP is partnering with AES Corporation to develop this solar resource, which will be located in the city of Eloy, part of Pinal County, Ariz.

West Line Solar will be 650 acres in size and construction is set to begin in spring of 2022. Facebook will receive 50 MW of solar energy from this solar plant, leaving 50 MW of available renewable energy that SRP will offer to residential and small business customers as part of its new solar offerings available later this year.

SRP and AES have worked together to bring online another 100-MW solar system, East Line Solar, as well as a 10 MW, 40 megawatt-hours (MWh) standalone battery-based energy storage system that helps inject power into the grid during times of high customer demand.

Randolph Solar Park

The next new solar plant to become commercially operational will be Randolph Solar Park, which is slated to come online in 2023. SRP is partnering with EDP Renewables to develop and operate this 200 MW solar park located in the city of Coolidge, Ariz., part of Pinal County, adjacent to SRP’s Randolph 230-kilovolt substation. Randolph Solar will span across 1,346 acres, and construction is anticipated to begin in the fall of 2022. Facebook will receive the full 200 MW of energy from this solar plant.

Valley Farms Solar

The third project, Valley Farms Solar, is expected to become commercially operational by December 2023. SRP has contracted with a subsidiary of NextEra Energy Resources to develop this 200 MW solar plant located in Coolidge, Ariz.

The two companies previously worked together to develop and contract a 20 MW solar generation facility and battery storage system, the Pinal Central Solar Energy Center, and a 100 MW solar plant, Saint Solar, which began operations in 2018 and 2020, respectively. Additionally, SRP and NextEra have plans to develop two solar-charged battery projects totaling nearly 350 MW, Sonoran Energy Center and Storey Energy Center.

Valley Farms Solar will be 1,900 acres in size and construction will begin in the winter of 2022. Facebook will receive the full 200 MW of solar energy from this solar plant.

The remaining 50 MW of solar energy will be dedicated to small business and residential SRP customers, SRP spokesperson Erica Sturwold told Public Power Current.

OUC Board Approves Possible Purchase of Plant To Enable Large-Scale Solar Production

August 16, 2021

by Paul Ciampoli
APPA News Director
August 16, 2021

The Orlando Utilities Commission’s (OUC) Board on August 10 approved a proposal that will allow OUC’s general manager and CEO to enter into an agreement to purchase the Osceola Generating Station, an idle 20-year-old 510-megawatt (MW) single-cycle natural gas-fired power plant located in Osceola County, Fla.

OUC noted that it was approached in May 2021 with an opportunity that would enable large-scale solar farms, mitigating the intermittency of solar power, which is the utility’s most viable source of renewable energy. The move also allows OUC to retire its oldest coal-fired power plant, Stanton Unit 1 located in East Orange County, Fla., at the utility’s Stanton Energy Center. In addition, the purchase further provides the utility an extra layer of resiliency because the Osceola site includes emergency backup fuel.

OUC said that the nearly $100 million deal to purchase and upgrade the inactive plant from Genova, a Texas-based private ownership group, will not change OUC’s commitment to its Electric Integrated Resource Plan (EIRP), the utility’s 30-year energy roadmap, to move away from all coal-fired generation by 2027. However, it would allow OUC to retire Unit 1, built in 1987, as opposed to the conversion to natural gas OUC previously announced in its EIRP in 2020.

The Osceola plant is comprised of three separate turbines – peakers that can turn on and off quickly, as opposed to the larger, older Stanton Unit 1 turbine that requires more fuel and takes many hours to turn on. The Osceola site can power up in just minutes.

OUC said it remains committed to meeting the EIRP’s objectives, which includes increasing solar energy and other renewable resources for electric generation and reducing carbon dioxide emissions by 50% by 2030 and 75% in 2040 before reaching net zero emissions by 2050.

OUC is aggressively increasing its reliance on solar energy, with plans to boost capacity to 270.5 megawatts by 2024.

Meanwhile, the utility is exploring back-up storage solutions and the use of other clean energy assets in addition to investing in electrification programs that would result in further carbon dioxide reductions and cleaner air for the community, it said.