First renewable-energy loan guarantee issued by DoE

Duke Energy Florida battery storage will add 22 MW across Trenton, Cape San Blas and Jennings, improving grid reliability, outage resilience, enabling peak shaving and deferring distribution upgrades to increase efficiency and customer value.

Key Points

Three lithium battery projects totaling 22 MW to improve Florida grid reliability, outage resilience and efficiency.

✅ 22 MW across Trenton, Cape San Blas and Jennings sites

✅ Enhances outage resilience and grid reliability

✅ Defers costly distribution upgrades and improves efficiency

Duke Energy Florida (DEF) has announced three battery energy storage projects, totaling 22 megawatts, that will improve overall reliability and support critical services during power outages.

Duke Energy, the nation's largest electric utility, unveils its new logo. (PRNewsFoto/Duke Energy) (PRNewsfoto/Duke Energy)

Collectively, the storage facilities will enhance grid operations, increase efficiencies and improve overall reliability for surrounding communities, with virtual power plant programs offering a model for coordinating distributed resources.

They will also provide important backup generation during power outages, a service that is becoming increasingly important with the number and intensity of storms that have recently impacted the state.

As the grid manager and operator, DEF can maximize the versatility of battery energy storage systems (BESS) to include multiple customer and electric system benefits such as balancing energy demand, managing intermittent resources, increasing energy security and deferring traditional power grid upgrades.

These benefits help reduce costs for customers and increase operational efficiencies.

The 11-megawatt (MW) Trenton lithium-based battery facility will be located 30 miles west of Gainesville in Gilchrist County. The energy storage project will continue to improve power reliability using newer technologies.

The 5.5-MW Cape San Blas lithium-based battery facility will be located approximately 40 miles southeast of Panama City in Gulf County. The project will provide additional power capacity to meet our customers' rising energy demand in the area. This project is an economical alternative to replacing distribution equipment necessary to accommodate local load growth.

The 5.5-MW Jennings lithium-based battery facility will be located 1.5 miles south of the Florida-Georgia border in Hamilton County. The project will continue to improve power reliability through energy storage as an alternative solution to installing new and more costly distribution equipment.

Currently the company plans to complete all three projects by the end of 2020.

"These battery projects provide electric system benefits that will help improve local reliability for our customers and provide significant energy services to the power grid," said Catherine Stempien, Duke Energy Florida state president. "Duke Energy Florida will continue to identify opportunities in battery storage technology which will deliver efficiency improvements to our customers."

Additional renewables projects

As part of DEF's commitment to renewables, the company is investing an estimated $1 billion to construct or acquire a total of 700 MW of cost-effective solar power facilities and 50 MW of battery storage through 2022.

Duke Energy is leading the industry deployment of battery technology, with SDG&E's Emerald Storage project underscoring broader adoption across the sector today. Last fall, the company and University of South Florida St. Petersburg unveiled a Tesla battery storage system that is connected to a 100-kilowatt (kW) solar array – the first of its kind in Florida.

This solar-battery microgrid system manages the energy captured by the solar array, situated on top of the university's parking garage, and similar low-income housing microgrid financing efforts are expanding access. The solar array was constructed three years ago through a $1 million grant from Duke Energy. The microgrid provides a backup power source during a power outage for the parking garage elevator, lights and electric vehicle charging stations. Click here to learn more.

In addition to expanding its battery storage technology and solar investments, DEF is investing in transportation electrification to support the growing U.S. adoption of electric vehicles (EV), including EV charging infrastructure, 530 EV charging stations and a modernized power grid to deliver the diverse and reliable energy solutions customers want and need.

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Foote Creek I Wind Farm Repowering upgrades Wyoming turbines with new nacelles, towers, and blades, cutting 68 units to 12 while sustaining 41.6 MW, under PacifiCorp and Rocky Mountain Power's Energy Vision 2020 plan.

Key Points

Replacement at Foote Creek Rim I, cutting to 12 turbines while sustaining about 41.6 MW using modern 2-4.2 MW units.

✅ 12 turbines replace 68, output steady near 41.6 MW

✅ New nacelles, towers, blades; taller 500 ft turbines

✅ Part of PacifiCorp Energy Vision 2020 and Gateway West

A Wyoming utility company has filed a permit to replace its first wind farm—originally commissioned in 1998, composed of over 65 turbines—amid new gas capacity competing with nuclear in Ohio, located at Foote Creek Rim I. The replacement would downsize the number of turbines to 12, which would still generate roughly the same energy output.

According to the Star Tribune, PacifiCorp’s new installation would involve new nacelles, new towers and new blades. The permit was filed with Carbon County.

New WY Wind Farm

The replacement wind turbines will stand more than twice as tall as the old: Those currently installed stand 200 feet tall, whereas their replacements will tower closer to 500 feet. Though this move is part of the company’s overall plan to expand its state wind fleet as some utilities respond to declining coal returns in the Midwest, the work going into the Foote Creek site is somewhat special, noted David Eskelsen, spokesperson for Rocky Mountain Power, the western arm of PacifiCorp.

“Foote Creek I repowering is somewhat different from the repowering projects announced in the (Energy Vision) 2020 initiative,” he said. “Foote Creek is a complete replacement of the existing 68 foundations, towers, turbine nacelles and rotors (blades).”

Currently, the turbines at Foote Creek have 600 kilowatts capacity each; the replacements’ maximum production ranges from 2 megawatts to 4.2 megawatts each, with the total output remaining steady at 41.4 megawatts, a scale similar to a 30-megawatt wind expansion in Eastern Kings, though there will be a slight capacity increase to 41.6 megawatts, according to the Star Tribune.

As part of the wind farm repowering initiative, PacifiCorp is to become full owner and operator of the Foote Creek site. When the farm was originally built, an Oregon-based water and electric board was 21 percent owner; 37 percent of the project’s output was tied into a contract with the Bonneville Power Administration.

Otherwise, PacifiCorp is moving to further expand its state wind fleet in line with initiatives like doubling renewable electricity by 2030 in Saskatchewan, with the addition of three new wind farms—to be located in Carbon, Albany and Converse counties—which may add up to 1,150 megawatts of power.

According to PacifiCorp, the company has more than 1,000 megawatts of owned wind generation capability, along with long-term purchase agreements for more than 600 megawatts from other wind farms owned by other entities. Energy Vision 2020 refers to a $3.5 billion investment and company move that is looking to upgrade the company's existing wind fleet with newer technology, adding 1,150 megawatts of new wind resources by 2020 and a a new 140-mile Gateway West transmission segment in Wyoming, comparable to a transmission project in Missouri just energized.

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Canada Electrification Costs: report estimates $580B-$1.4T to scale renewable energy, wind, solar, and storage capacity to 2050, shifting from natural gas toward net-zero emissions and raising average household energy spending by $1,300-$3,200 annually.

Key Points

Projected national expense to expand renewables and electrify energy systems by 2050, impacting household energy bills.

✅ $580B-$1.4T forecast for 2020-2050 energy transition

✅ 278-422 GW wind, solar, storage capacity by 2050

✅ Household costs up $1,300-$3,200 per year on average

The Canadian Gas Association says building renewable electricity capacity to replace just half of Canada's current fossil fuel-generated energy, a shift with significant policy implications for grids across provinces, could increase national costs by as much as $1.4 trillion over the next 30 years.

In a report, it contends, echoing an IEA report on net-zero, that growing electricity's contribution to Canada's energy mix from its current 19 per cent to about 60 per cent, a step critical to meeting climate pledges that policymakers emphasize, will require an expansion from 141 gigawatts today to between 278 and 422 GW of renewable wind, solar and storage capacity by 2050.

It says that will increase national energy costs by between $580 billion and $1.4 trillion between 2020 and 2050, a projection consistent with recent reports of higher electricity prices in Alberta amid policy shifts, translating into an average increase in Canadian household spending of $1,300 to $3,200 per year.

The study, prepared by consulting firm ICF for the association, assumes electrification begins in 2020 and is applied in all feasible applications by 2050, with investments in the electricity system, guided by the implications of decarbonizing the grid for reliability and cost, proceeding as existing natural gas and electric end use equipment reaches normal end of life.

Association CEO Tim Egan says the numbers are "pretty daunting" and support the integration of natural gas with electric, amid Canada's race to net-zero commitments, instead of using an electric-only option as the most cost-efficient way for Canada to reach environmental policy goals.

But Keith Stewart, senior energy strategist with Greenpeace Canada, says scientists are calling for the world to get to net-zero emissions by 2050, and Canada's net-zero by 2050 target underscores that urgency to avoid "catastrophic" levels of warming, so investing in natural gas infrastructure to then shut it down seems a "very expensive option."

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Utility Battery Storage Rankings measure grid-connected capacity, not ownership, highlighting MW, MWh, and watts per customer across PJM, MISO, and California IOUs, featuring Duke Energy, IPL, ancillary services, and frequency regulation benefits.

Key Points

Rankings that track energy storage connected to utility grids, comparing MW, MWh, and W/customer rather than ownership.

✅ Ranks by MW, MWh, and watts per customer, not asset ownership

✅ Highlights PJM, MISO cases and California IOUs' deployments

✅ Examples: Duke Energy, IPL, IID; ancillary services, frequency response

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

Duke ready for next step

Given Duke’s plans, including projects in Florida that are moving ahead, the utility is likely to stay high in the rankings and be more of a driving force in development. “Battery technology has matured, and we are ready to take the next step,” Duke spokesman Randy Wheeless told Utility Dive. “We can go to regulators and say this makes economic sense.”

Duke began exploring energy storage in 2012, and until now most of its energy storage efforts were focused on commercial projects in competitive markets where it was possible to earn revenues. Those included its 36 MW Notrees battery storage project developed in partnership with the Department of Energy in 2012 that provides frequency regulation for the Electric Reliability Council of Texas market and two 2 MW storage projects at its retired W.C. Beckjord plant in New Richmond, Ohio, that sells ancillary services into the PJM Interconnection market.

On the regulated side, most of Duke’s storage projects have had “an R&D slant to them,” Wheeless said, but “we are moving beyond the R&D concept in our regulated territory and are looking at storage more as a regulated asset.”

“We have done the demos, and they have proved out,” Wheeless said. Storage may not be ready for prime time everywhere, he said, but in certain locations, especially where it can it can be used to do more than one thing, it can make sense.

Wheeless said Duke would be making “a number of energy storage announcements in the next few months in our regulated states.” He could not provide details on those projects.

More flexible resources
Location can be a determining factor when building a storage facility. For IPL, serving the wholesale market was a driving factor in the rationale to build its 20 MW, 20 MWh storage facility in Indianapolis.

IPL built the project to address a need for more flexible resources in light of “recent changes in our resource mix,” including decreasing coal-fired generation and increasing renewables and natural gas-fired generation, as other regions plan to rely on battery storage to meet rising demand, Joan Soller, IPL’s director of resource planning, told Utility Dive in an email. The storage facility is used to provide primary frequency response necessary for grid stability.

The Harding Street storage facility in May. It was the first energy storage project in the Midcontinent ISO. But the regulatory path in MISO is not as clear as it is in PJM, whereas initiatives such as Ontario storage framework are clarifying participation. In November, IPL with the Federal Energy Regulatory Commission, asking the regulator to find that MISO’s rules for energy storage are deficient and should be revised.

Soller said IPL has “no imminent plans to install energy storage in the future but will continue to monitor battery costs and capabilities as potential resources in future Integrated Resource Plans.”

California legislative and regulatory push

In California, energy storage did not have to wait for regulations to catch up with technology. With legislative and regulatory mandates, including CEC long-duration storage funding announced recently, as a push, California’s IOUs took high places in SEPA’s rankings.

Southern California Edison and San Diego Gas & Electric were first and fourth (63.2 MW and 17.2 MW), respectively, in terms of capacity. SoCal Ed and SDG&E were first and second (104 MWh and 28.4 MWh), respectively, and Pacific Gas and Electric was fifth (17 MWh) in terms of energy.

But a public power utility, the Imperial Irrigation District (IID), ended up high in the rankings – second in capacity (30 MW) and third  in energy (20 MWh) – even though as a public power entity it is not subject to the state’s energy storage mandates.

But while IID was not under state mandate, it had a compelling regulatory reason to build the storage project. It was part of a settlement reached with FERC over a September 2011 outage, IID spokeswoman Marion Champion said.

IID agreed to a $12 million fine as part of the settlement, of which $9 million was applied to physical improvements of IID’s system.

IID ended up building a 30 MW, 20 MWh lithium-ion battery storage system at its El Centro generating station. The system went into service in October 2016 and in May, IID used the system’s 44 MW combined-cycle natural gas turbine at the generating station.

Passing savings to customers
The cost of the storage system was about $31 million, and based on its experience with the El Centro project, Champion said IID plans to add to the existing batteries. “We are continuing to see real savings and are passing those savings on to our customers,” she said.

Champion said the battery system gives IID the ability to provide ancillary services without having to run its larger generation units, such as El Centro Unit 4, at its minimum output. With gas prices at $3.59 per million British thermal units, it costs about $26,880 a day to run Unit 4, she said.

IID’s territory is in southeastern California, an area with a lot of renewable resources. IID is also not part of the California ISO and acts as its own balancing authority. The battery system gives the utility greater operational flexibility, in addition to the ability to use more of the surrounding renewable resources, Champion said.

In May, IID’s board gave the utility’s staff approval to enter into contract negotiations for a 7 MW, 4 MWh expansion of its El Centro storage facility. The negotiations are ongoing, but approval could come in the next couple months, Champion said.

The heart of the issue, though, is “the ability of the battery system to lower costs for our ratepayers,” Champion said. “Our planning section will continue to utilize the battery, and we are looking forward to its expansion,” she said.” I expect it will play an even more important role as we continue to increase our percentage of renewables.”

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Coinmint Plattsburgh Dispute spotlights cryptocurrency mining, hydropower electricity rates, a $1M security deposit, Public Service Commission rulings, municipal utility policies, and seasonal migration to Massena data centers as Bitcoin price volatility pressures operations.

Key Points

Legal and energy-cost dispute over crypto mining, a $1,019,503 deposit, and operations in Plattsburgh and Massena.

✅ PSC allows higher rates and requires large security deposits.

✅ Winter electricity spikes drove a $1M deposit calculation.

✅ Coinmint shifted capacity to Massena data centers.

A few years ago, there was a lot of buzz about the North Country becoming the next Silicon Valley of cryptocurrency, even as Maine debated a 145-mile line that could reshape regional power flows. One of the companies to flock here was Coinmint. The cryptomining company set up shop in Plattsburgh in 2017 and declared its intentions to be a good citizen.

Today, Coinmint is fighting a legal battle to avoid paying the city’s electric utility more than $1 million owed for a security deposit. In addition to that dispute, a local property manager says the firm was evicted from one of its Plattsburgh locations.

Companies like Coinmint chose to come to the North Country because of the relatively low electricity prices here, thanks in large part to the hydropower dam on the St. Lawrence River in Massena, and regionally, projects such as the disputed electricity corridor have drawn attention to transmission costs and access. Coinmint operates its North Country Data Center facilities in Plattsburgh and Massena. In both locations, racks of computer servers perform complex calculations to generate cryptocurrency, such as bitcoin.

When cryptomining began to take off in Plattsburgh, the cost of one bitcoin was skyrocketing. That brought hype around the possibility of big business and job creation in the North Country. But cryptomininers like Coinmint were using massive amounts of energy in the winter of 2017-2018, and that season, electric bills of everyday Plattsburgh residents spiked.

Many cryptomining firms operate in a state of flux, beholden to the price of Bitcoin and other cryptocurrencies, even as the end to the 'war on coal' declaration did little to change utilities' choices. When the price of one bitcoin hit $20,000 in 2017, it fell by 30% just days later. That’s one reason why the price of electricity is so critical for companies like Coinmint to turn a profit. 

Plattsburgh puts the brakes on “cryptocurrency mining”
In early 2018, Plattsburgh passed a moratorium on cryptocurrency mining operations, after residents complained of higher-than-usual electric bills.

“Your electric bill’s $100, then it’s at $130. Why? It’s because these guys that are mining the bitcoins are riding into town, taking advantage of a situation,” said resident Andrew Golt during a 2018 public hearing.

Coinmint aimed to assuage the worries of residents and other businesses. “At the end of the day we want to be a good citizen in whatever communities we’re in,” Coinmint spokesman Kyle Carlton told NCPR at that 2018 meeting.

“We’re open to working with those communities to figure out whatever solutions are going to work.”

The ban was lifted in Feb. 2019. However, since it didn’t apply to companies that were already mining cryptocurrency in Plattsburgh, Coinmint has operated in the city all along.

Coinmint challenges attempt to protect ratepayers
New rules passed by the New York Public Service Commission in March 2018 allow municipal power authorities including Plattsburgh’s to charge big energy users such as Coinmint higher electricity rates, amid customer backlash in other utility deals. The new rules also require them to put down a security deposit to ensure their bills get paid.

But Coinmint disputes that deposit charge. The company has been embroiled in a legal fight for nearly a year against Plattsburgh Municipal Lighting Department (PMLD) in an attempt to avoid paying the electric utility’s security deposit bill of $1,019,503. That bill is based on an estimate of what would cover two months of electricity use if a company were to leave town without paying its electric bills.

Coinmint would not discuss the dispute on the record with NCPR. Legal documents show the firm argues the deposit charge is inflated, based on a flawed calculation resulting in a charge hundreds of thousands of dollars higher than what it should be.

“Essentially they’re arguing that they should only have to put up some average of their monthly bills without accounting for the fact that winter bills are significantly higher than the average,” said Ken Podolny, an attorney representing the Plattsburgh utility.

The company took legal action in February 2019 against PMLD in the hopes New York’s energy regulator, the Public Service Commission, would agree with Coinmint that the deposit charge was too high. An informal commission hearing officer disagreed, and ruled in October the charge was calculated correctly.

Coinmint appealed the ruling in November and a hearing on the appeal could come as soon as February.

Less than a week after Coinmint lost its initial challenge of the deposit charge, the company made a splashy announcement trumpeting its plans to “migrate its Plattsburgh, New York infrastructure to its Massena, New York location for the 2019-2020 winter season.”

The announcement made no mention of the appeal or the recent ruling against Coinmint. The company attributed its new plan to “exceptionally-high” electricity rates in Plattsburgh, as hydropower transmission projects elsewhere in New England faced their own controversies. 

"We recognize some in the Plattsburgh community have blamed our operation for pushing rates higher for everyone so, while we disagree with that assessment, we hope this seasonal migration will have a positive impact on rates for all our neighbors,” said Coinmint cofounder Prieur Leary in the press statement.

“In the event that doesn't happen, we trust the community will look for the real answers for these high costs." Prieur Leary has since been removed from the corporate team page on the company’s website.

The company still operates in Plattsburgh at one of its locations in the city. As for staff, while at least two Coinmint employees have moved from Plattsburgh to Massena, where the company operates a data center inside a former Alcoa aluminum plant, it is unclear how many people in total have made the move.

Coinmint left its second Plattsburgh location in 2019. The company would not discuss that move on the record, yet the circumstances of the departure are murky.

The local property manager of the industrial park site told NCPR, “I have no comment on our evicted tenant Coinmint.” The property owner, California’s Karex Property Management Services, also would not comment regarding the situation, noting that “all staff have been told to not discuss anything regarding our past tenant Coinmint.”

Today, Bitcoin and other cryptocurrencies are worth a fraction of what they were back in 2017 when Coinmint came to the North Country, and now, amid a debate over Bitcoin's electricity use shaping market sentiment, the future of the entire industry here remains uncertain.

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Spring Storm Grid Risks highlight tornado outbreaks, flooding, power outages, and transmission disruptions, with NOAA flood outlooks, coal and barge delays, vulnerable nuclear sites, and distribution line damage demanding resilience, reliability, and emergency preparedness.

Key Points

Spring Storm Grid Risks show how tornadoes and floods disrupt power systems, fuel transport, and plants guide resilience.

✅ Tornado outbreaks and derechos damage distribution and transmission

✅ Flooding drives outages via treefall, substation and plant inundation

✅ Fuel logistics disrupted: rail coal, river barges, road access

The storm and tornado outbreak that recently barreled through the US Midwest, South and Mid-Atlantic was a devastating reminder of how much danger spring can deliver, despite it being the “milder” season compared to summer and winter.  

Danger season is approaching, and the country is starting to see the impacts. 

The event killed at least 32 people across seven states. The National Weather Service is still tallying up the number of confirmed tornadoes, which has already passed 100. Communities coping with tragedy are assessing the damage, which so far includes at least 72 destroyed homes in one Tennessee county alone, and dozens more homes elsewhere. 

On Saturday, April 1–the day after the storm struck–there were 1.1 million US utility customers without power, even as EIA reported a January power generation surge earlier in the year. On Monday morning, April 3, there were still more than 80,000 customers in the dark, according to PowerOutage.us. The storm system brought disruptions to both distribution grids–those networks of local power lines you generally see running overhead to buildings–as well as the larger transmission grid in the Midwest, which is far less common than distribution-level issues. 

While we don’t yet have a lot of granular details about this latest storm’s grid impacts, recent shifts in demand like New York City's pandemic power patterns show how operating conditions evolve, and it’s worth going through what else the country might be in for this spring, as well as in future springs. Moreover, there are steps policymakers can take to prepare for these spring weather phenomena and bolster the reliability and resilience of the US power system. 

Heightened flood risk 
The National Oceanic Atmospheric Administration (NOAA) said in a recent outlook that about 44 percent of the United States is at risk of floods this spring, equating to about 146 million people. This includes most of the eastern half of the country, the federal agency said. 

The agency also sees “major” flood risk potential in some parts of the Upper Mississippi River Basin, and relatively higher risk in the Sierra Nevada region, due in part to a historic snowpack in California.  

Multiple components of the power system can be affected by spring floods. 

Power lines – Floods can saturate soil and make trees more likely to uproot and fall onto power lines. This has been contributing to power outages during California’s recent heavy storms–called atmospheric rivers–that started over the winter. In other regions, soil moisture has even been used as a predictor of where power outages will occur due to hurricanes, so that utility companies are better prepared to send line repair crews to the right areas. Hurricanes are primarily a summer and fall phenomenon, and summer also brings grid stress from air conditioning demand in many states, so for now, during spring, they are less of a concern.  

Fuel transport – Spring floods can hinder the transportation of fuels like coal. While it is a heavily polluting fossil fuel that is set to continue declining as a fuel source for US electricity generation, with the EIA summer outlook for wind and solar pointing to further shifts, coal still accounted for roughly 20 percent of the country’s generation in 2022.   

About 70 percent of US coal is transported at least part of the way by trains. The rail infrastructure to transport coal from the Powder River Basin in Montana and Wyoming–the country’s primary coal source–was proven to be vulnerable to extreme floods in the spring of 2011, and even more extreme floods in the spring of 2019. The 2019 floods’ disruptions of coal shipments to power plants via rail persisted for months and into the summertime, also affecting river shipments of coal by barge. In June 2019, hundreds of barges were stalled in the Mississippi River, through which millions of tons of the fossil fuel are normally transported. 

Power plants – Power plants themselves can also be at risk of flooding, since most of them are sited near a source of water that is used to create steam to spin the plants’ turbines, and conversely, low water levels can constrain hydropower as seen in Western Canada hydropower drought during recent reservoir shortfalls. Most US fossil fuel generating capacity from sources like methane gas, which recently set natural gas power records across the grid, and coal utilizes steam to generate electricity. 

However, much of the attention paid to the flood risk of power plant sites has centered on nuclear plants, a key source of low-carbon electricity discussed in IAEA low-carbon electricity lessons that also require a water source for the creation of steam, as well as for keeping the plant cool in an emergency. To name a notable flood example here in the United States–both visually and substantively–in 2011, the Fort Calhoun nuclear plant in Nebraska was completely surrounded by water due to late-spring flooding along the Missouri River. This sparked a lot of concerns because it was just a few months after the March 2011 meltdown of the Fukushima Daiichi nuclear plant in Japan. The public was thankfully not harmed by the Nebraska incident, but this was unfortunately not an isolated incident in terms of flood risks posed to the US nuclear power fleet. 

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