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.”

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.

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.

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.

Banning Electric Utility Power Transformer Relocation Project Will Yield A Number Of Key Benefits

August 16, 2021

by Paul Ciampoli
APPA News Director
August 16, 2021

A project by the City of Banning Electric Utility (BEU) in California that involves moving and relocating a power transformer will result in a number of benefits including saving BEU ratepayers an estimated $500,000 compared to the cost of purchasing a new transformer.

The project began with a 10-year study and recommendation in 2004. The study recommended a distribution system voltage upgrade as well as an upgrade and expansion of BEU’s Airport Substation from 3.75 megawatts (MW) to 10 MW of capacity. These system upgrades would still allow for planned residential growth in the northwest side of town as well as industrial growth around the vicinity of the Banning Municipal Airport on Banning’s southeastern border. 

There are three main components to this transformer relocation project.

First, in 2019, was the relocation of the Airport substation to a newly acquired property within the vicinity of the Banning Municipal Airport. The new substation was renamed Ivy, as a special tribute to the granddaughter of the project manager who relocated from Iowa. Second, the new substation will exceed the recommended 10 MW of capacity with 25 MW and the ability to expand up to 50 MW of capacity as needed for industrial growth anticipated in the area. The third component is the downsizing of the Sunset substation from 50 MW capacity to 25 MW with the move of one power transformer from Sunset to Ivy. 

Project completion is scheduled for September 1, 2021.

BEU noted that its staff is excited to transition from 1950 mechanical/analog technology to digital distribution automation (1950s technology to 2020) and bring new technology to this former stagecoach town.

Along with ratepayer savings, the project helps better utilize existing transformation equipment and balances transformation capacity across load and system, and provides needed transformation capacity in industrial and airport zoned properties. 

While this project has been years in the making, the timing has been perfect as Banning was recently labeled by The Sacramento Bee newspaper as the fastest growing city in California.

Renewables Were the Number Two Generation Source in 2020: EIA

August 11, 2021

by Peter Maloney
APPA News
August 11, 2021

Renewable energy surpassed coal and nuclear generation, becoming the number two generation source in 2020, according to the Energy Information Administration (EIA).

Electric power generated by wind, hydroelectric, solar, biomass, and geothermal sources reached a record 834 billion kilowatt hours (kWh), or about 21 percent of the electricity generated in the United States last year, according to the EIA.

Renewable energy’s record level of generation surpassed nuclear energy, which generated 790 billion kWh, and coal-fired power, which generated 774 billion kWh, for the first time on record, according to EIA data. The top generation source in 2020 was natural gas-fired power, which produced 1,617 billion kWh.

The changes in the 2020 generation profile were due mostly to significantly less coal use in the U.S. and the steady increase of wind and solar power, the EIA said.

Coal generation last year declined 20 percent from 2019, while renewables, including small-scale solar, increased 9 percent. Power generated from wind, currently the most prevalent source of renewable energy in the United States, grew 14 percent in 2020 from 2019. Utility-scale solar generation (projects greater than 1 megawatt) increased 26 percent, and small-scale solar, such as grid-connected rooftop solar panels, increased 19 percent.

Nuclear power declined 2 percent from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages, the EIA said.

U.S. coal-fired generation peaked at 2,016 billion kWh in 2007. Much of that capacity has been replaced by or converted to natural gas-fired generation since then, the EIA said. Until 2016, coal-fired generation was the largest source of electricity in the United States, Last year was the first year that more electricity was generated by renewables and by nuclear power than by coal, according to EIA’s data, which dates to 1949.

Despite coal’s decline relative to natural gas and other sources of energy, the EIA expects the share of electrical output from coal-fired generation to rise this year because rising natural gas prices will make coal more economically attractive.

The EIA sees natural gas prices rising because consumption and exports of the fuel are outpacing production and imports. The agency forecasts the 2021 Henry Hub natural gas spot price to average $3.07 per million British thermal units (MMBtu), an increase of $1.04/MMBtu from the record lows of 2020.

EIA’s Short-Term Energy Outlook (STEO) forecasts an 18 percent increase in coal-fired generation in 2021, compared with 2020. The agency then sees coal-fired generation falling again, by 2 percent, in 2022.

Meanwhile, the EIA is forecasting a 7 percent rise in renewable generation in 2021 and a 10 percent increase in 2022 and sees nuclear power declining 2 percent in 2021 and 3 percent in 2022 as nuclear plant retirements continue.

NYPA Board Approves Additional Funding To Support Purchase Of Electric Vehicles

August 11, 2021

by Paul Ciampoli
APPA News Director
August 11, 2021

The New York Power Authority (NYPA) Board of Trustees recently approved $1.1 million in additional funding to help New York’s municipal and rural electric cooperative systems bring more hybrid and electric vehicles into their fleets.

The additional financial assistance, available through the Municipal and Rural Cooperative Electric Utilities Electric-Drive Vehicle Program, will expand a long-running clean energy partnership that encourages electric vehicle use and reduces greenhouse gas emissions across New York State, NYPA said in late July.

NYPA began the Municipal and Rural Cooperative Electric Utilities Electric-Drive Vehicle Program in 2003. In total, 86 vehicles have been placed with 25 cities, towns and villages across the state. The additional funding brings the current total allocated for the program to $12 million.

The NYPA funding provides zero-interest loans to NYPA’s municipal and rural electric cooperative system customers for the purchase of electric and hybrid-electric vehicles for use in their fleets, as well as associated battery charging equipment. Purchases often include passenger vehicles, pickup trucks, off-road specialty vehicles and heavy-duty utility bucket trucks. The funds are then recovered from customers over a period of up to three years through a surcharge on their NYPA electric bills.

The 51 municipal electric and rural electric cooperative utility systems have been NYPA customers since the Niagara Power Project began generating power in 1961, when approximately 765 megawatts (MW) of Niagara hydropower were legislatively mandated for their use.

NYPA reserves 54 MW of that hydropower to promote economic development within those municipal and cooperative service territories. Power from the reserve is allocated by the NYPA Board of Trustees to individual systems to meet the increased electric load resulting from eligible new or expanding businesses in their service area.

NYPA provides these communities with an array of energy-efficiency services and has helped install electric vehicle charging infrastructure for the public in support of New York Governor Andrew Cuomo’s Charge NY 2.0 initiative, an effort aimed at installing 10,000 charging stations by the end of the year.

Through NYPA’s EVolve NY program, NYPA is creating a fast-charging network across the state to help accelerate the adoption of electric vehicles. More than 150 chargers, open to the public, are being installed along major interstate corridors, in five major cities and at New York City airports by the end of 2021.