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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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Ireland electricity support measures include PSO levy rebates, RESS 2 renewables, CRU-directed EirGrid backup capacity, and grid investment for the Celtic Interconnector, cutting bills, boosting security of supply, and reducing reliance on imported fossil fuels.

Key Points

Government steps to cut bills and secure supply via PSO rebates, RESS 2 renewables, backup power, and grid upgrades.

✅ PSO levy rebates lower domestic electricity bills.

✅ RESS 2 adds wind, solar, and hydro to the grid.

✅ EirGrid to procure temporary backup capacity for winter peaks.

Ireland's Cabinet has approved a package of measures to help mitigate the rising cost of rising electricity bills, as Irish provider price increases continue to pressure consumers, and to ensure secure supplies to electricity for households and business across Ireland over the coming years.

The package of measures includes changes to the Public Service Obligation (PSO) levy (beyond those announced earlier in the year), which align with emerging EU plans for more fixed-price electricity contracts to improve price stability. The changes will result in rebates, and thus savings, for domestic electricity bills over the course of the next PSO year beginning in October. This further reduction in the PSO levy occurs because of a fall in the relative cost of renewable energy, compared to fossil fuel generation.

The Government has also approved the final results of the second onshore Renewable Electricity Support Scheme (RESS 2) auction, echoing how Ontario's electricity auctions have aimed to lower costs for consumers. This will bring significantly more indigenous wind, solar and hydro-electric energy onto the National Grid. This, in turn, will reduce our reliance on increasingly expensive imported fossil fuels, as the UK explores ending the gas-electricity price link to curb bills.

The package also includes Government approval for the provision of funding for back-up generation capacity, to address risks to security of electricity supply over the coming winters, similar to the UK's forthcoming energy security law approach in this area. The Commission for the Regulation of Utilities (CRU), which has statutory responsibility for security of supply, has directed EirGrid to procure additional temporary emergency generation capacity (for the winters of 2023/2024 to 2025/2026). This will ultimately provide flexible and temporary back-up capacity, to safeguard secure supplies of electricity for households and businesses as we deploy longer-term generation capacity.

Today’s measures also see an increased borrowing limit (€3 billion) for EirGrid – to strengthen our National Grid as part of 'Shaping Our Electricity Future' and to deliver the Celtic (Ireland-France) Interconnector, amid wider European moves to revamp the electricity market that could enhance cross-border resilience. An increased borrowing limit (€650 million) for Bord na Móna will drive greater deployment of indigenous renewable energy across the Midlands and beyond – as part of its 'Brown to Green' strategy, while measures like the UK's household energy price cap illustrate the scale of consumer support elsewhere.

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Rolls-Royce and Exelon UKSMR Partnership accelerates factory-built small modular reactors, nuclear power, clean energy, 440MW units, advanced manufacturing, fleet deployment, net zero goals, and resilient, low-cost baseload generation in the UK and globally.

Key Points

A partnership to deploy factory-built SMR stations, providing 440MW low-carbon baseload for the UK and export markets.

✅ 440MW factory-built SMR units with rapid modular assembly

✅ Exelon to operate and enhance high capacity factors

✅ Supports UK net zero, jobs, and export-led manufacturing

Rolls-Royce and Exelon Generation have signed a Memorandum of Understanding to pursue the potential for Exelon Generation to operate compact nuclear power stations both in the UK and internationally, including markets such as Canada where New Brunswick SMR questions are prompting public debate today.

Exelon Generation will be using their operational experience to assist Rolls Royce in the development and deployment of the UKSMR.

Rolls-Royce is leading a consortium that is designing a low-cost factory built nuclear power station, known as a small modular reactor (SMR), with UK mini-reactor approval anticipated as development progresses. Its standardised, factory-made components and advanced manufacturing processes push costs down, while the rapid assembly of the modules and components inside a weatherproof canopy on the power station site itself avoid costly schedule disruptions.

The consortium is working with its partners and UK Government to secure a commitment for a fleet of factory built nuclear power stations, each providing 440MW of electricity, to be operational within a decade, helping the UK meet its net zero obligations in line with the green industrial revolution policy set out by government. A fleet deployment in the UK will lead to the creation of new factories that will make the components and modules which will help the economy recover from the Covid-19 pandemic and pave the way for significant export opportunities as well.

The consortium members feature the best of nuclear engineering, construction and infrastructure expertise in Assystem, Atkins, BAM Nuttall, Jacobs, Laing O'Rourke, National Nuclear Laboratory, Nuclear Advanced Manufacturing Research Centre, Rolls-Royce and TWI. Exelon will add valuable operational experience to the team.

Tom Samson, interim Chief Executive Officer of the UKSMR consortium, said: 'Nuclear power is central to tackling climate change and economic recovery, but it must be affordable, reliable and investable and the way we manufacture and assemble our power station brings its cost down to be comparable with offshore wind.

'It's a compelling proposition that could draw new players into the UK's power generation landscape, improving choice for consumers and providing uninterrupted low carbon energy to homes and businesses.

'The opportunity to partner with Exelon is a very exciting prospect for our program, complementing our existing Consortium partnerships with one of the world's largest nuclear operator adds an important dimension to our growth ambitions, embodies the strength of the UK and USA alliance on nuclear matters and reflects wider international moves, such as a Canadian premiers' SMR initiative to accelerate technology development, and offers our future customers the ability to achieve the highest performance standards associated with Exelon's outstanding operational track record.'

The power stations will be built by the UKSMR consortium, before being handed over to be operated by power generation companies. Exelon Generation will work closely with the consortium during the pre-operation period. Exelon Nuclear operates 21 nuclear reactors in America, and U.S. regulators recently issued a final safety evaluation for a NuScale SMR that underscores momentum in the sector. The Exelon nuclear fleet is an integral part of the U.S. clean power mix; it produces more than 158 million megawatt-hours of clean electricity every year.

Bryan Hanson, EVP and COO of Exelon Generation said: 'We believe that SMRs are a crucial part of the world's clean energy mix, as projects like Darlington SMRs advance in Ontario. With our experience both in the US and internationally, Exelon is confident that we can help Rolls Royce ensure SMRs play a key role in the UK's energy future. We've had a very strong record of performance for 20 consecutive years, with a 2019 capacity factor of 95.7 percent. We will leverage this experience to achieve sustainably high capacity factors for the UKSMRs.'

Ralph Hunter, Managing Director of Exelon Nuclear Partners, who runs Exelon's international clean energy business, said: 'We have a strong track record of success to be the operator of choice for the UKSMR. We will help develop operational capability, training and human capacity development in the UK, as utilities such as Ontario Power Generation commit to SMRs abroad, ensuring localisation of skills and a strong culture of safety, performance and efficiency.'

By 2050 a full UK programme of a fleet of factory built nuclear power stations in the UK could create:

Up to 40,000 jobs GBP52BN of value to the UK economy GBP250BN of exports

The current phase of the programme has been jointly funded by all consortium members and UK Research and Innovation.

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Fort Frances Microgrid aims to boost reliability in Ontario with grid-connected and island modes, Siemens feasibility study, renewable energy integration, EV charging expansion, and resilience modeled after First Nations projects and regional biomass initiatives.

Key Points

A community microgrid in Fort Frances enabling grid and island modes to improve reliability and integrate renewables.

✅ Siemens-led feasibility via FedNor funding

✅ Grid-connected or islanded for outage resilience

✅ Integrates renewables, EV charging, and industry growth

When the power goes out in Fort Frances, Ont., the community may be left in the dark for hours.

The hydro system's unreliability — caused by its location on the provincial power grid — has prompted the town to seek a creative solution: its own self-contained electricity grid with its own source of power, known as a microgrid. 

Located more than 340 kilometres west of Thunder Bay, Ont., on the border of Minnesota, near the Great Northern Transmission Line corridor, Fort Frances gets its power from a single supply point on Ontario's grid. 

"Sometimes, it's inevitable that we have to have like a six- to eight-hour power outage while equipment is being worked on, and that is no longer acceptable to many of our customers," said Joerg Ruppenstein, president and chief executive officer of Fort Frances Power Corporation.

While Ontario's electrical grid serves the entire province, and national efforts explore macrogrids, a microgrid is contained within a community. Fort Frances hopes to develop an integrated, community-based electric microgrid system that can operate in two modes:

• Grid-connected mode, which means it's connected to the provincial grid and informed by western grid planning approaches
• Island mode, which means it's disconnected from the provincial grid and operates independently

The ability to switch between modes allows flexibility. If a storm knocks down a line, the community will still have power.

The town has been given grant funding from the Federal Economic Development Agency for Northern Ontario (FedNor), echoing smart grid funding in Sault Ste. Marie initiatives, for the project. On Monday night, council voted to grant a request for proposal to Siemens Canada Limited to conduct a feasibility study into a microgrid system.

The study, anticipated to be completed by the end of 2023 or early 2024, will assess what an integrated community-based microgrid system could look like in the town of just over 7,000 people, said Faisal Anwar, chief administrative officer of Fort Frances. A timeline for construction will be determined after that. 

The community is still reeling from the closure of the Resolute Forest Products pulp and paper mill in 2014 and faces a declining population, said Ruppenstein. It's hoped the microgrid system will help attract new industry to replace those lost workers and jobs, drawing on Manitoba's hydro experience as a model.

This gives the town a competitive advantage.

"If we were conceivably to attract a larger industrial player that would consume a considerable amount of energy, it would result in reduced rates for everyone…we're the only utility really in Ontario that can offer that model," Ruppenstein said.

The project can also incorporate renewable energy like solar or wind power, as seen in B.C.'s clean energy shift efforts, into the microgrid system, and support the growth of electric vehicles, he said. Many residents fill their gas tanks in Minnesota because it's cheaper, but Fort Frances has the potential to become a hub for electric vehicle charging.

A few remote First Nations have recently switched to microgrid systems fuelled by green energy, including Gull Bay First Nation and Fort Severn First Nation. These are communities that have historically relied on diesel fuel either flown in, which is incredibly expensive, or transported via ice roads, which are seeing shorter seasons each year.

Natural Resources Minister Jonathan Wilkinson was in Thunder Bay, Ont., to announce $35 million for a biomass generation facility in Whitesand First Nation, complementing federal funding for the Manitoba-Saskatchewan transmission line elsewhere in the region.

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Texas Deep Freeze Energy Crisis strains grids as polar vortex triggers rolling blackouts, record natural gas and electricity prices, refinery shutdowns, WTI gains, and scarcity pricing across Texas, Oklahoma, SPP, and Mexico.

Key Points

A polar vortex slamming Texas energy: outages, record power prices, gas spikes, and reduced oil output.

✅ Record gas trades near $500/mmBtu; power hits $6,000/MWh

✅ WTI tops $60 as Texas shuts in ~1 million bpd

✅ Rolling blackouts across SPP; ERCOT scarcity pricing

A deep freeze is roiling electricity markets in more than a dozen U.S. states, leading to record-setting prices for electricity and natural gas, knocking oil production off line and shutting down some of North America’s largest refineries.

“It’s freakishly cold,” said Eric Fell, a senior natural gas analyst with Wood Mackenzie in Houston, where record cold temperatures and snow have blanketed the city, caused rolling power outages, shut down refineries and sent both natural gas and electricity prices soaring.

'It’s freakishly cold': Deep freeze slams North American energy sector

The polar vortex has led to freezing temperatures in every county in Texas, the largest energy-producing state in the U.S., and caused massive disruptions across the North American energy complex, triggering Texas power outages as far south as Mexico.

As the plunge in temperatures forced oil companies to shut in an estimated one million barrels of oil production in Texas on Monday, the West Texas Intermediate benchmark price rose above the US$60 per barrel threshold for the first time in a year to settle up 1 per cent, or US65 cents, at US$60.12 per barrel.

President Joe Biden declared an emergency on Monday, unlocking federal assistance to Texas.

People carry groceries from a local gas station on Monday in Austin, Texas. Winter storm Uri has brought historic cold weather to Texas, causing traffic delays and power outages. 

Frozen wind farms are just a small piece of Texas’s power grid woes right now.

Fell said regional natural gas and electricity prices in Oklahoma and Texas broke U.S. records over the weekend.

On Friday, Oklahoma gas transmission prices averaged US$350 per million British thermal units and Fell said one trade went as high as US$600 per mmBtu. In parts of the Texas panhandle and elsewhere, prices jumped to US$200, “all of which individually would have been new records,” Fell said, noting the previous record was US$160.

On Monday, natural gas for physical delivery in the U.S. was trading for as much as US$500 per mmBtu as demand for the heating and power plant fuel soared.  Spot gas has been trading for hundreds of dollars across the central U.S. since Thursday with a surge in heating demand triggering widespread blackouts and sending electricity prices soaring. The fuel normally trades in the region for less than US$3 per mmBtu.

Similarly, electricity prices in Texas surged to US$6,000 per megawatt hour on Monday, as U.S. power companies grapple with supply-chain constraints, which Fell said is “100 times the normal price.”

“You’re seeing scarcity pricing in power and gas. The only thing that’s different this time is it’s staying there – it’s not just an hour or two hours, it’s the whole day,” he said.

The blast of Arctic cold, which has blanketed Canada and much of the U.S., has created a massive draw on natural gas supplies, used both for home heating and industrial uses like electricity generation.

Little Rock, Ark.-based Southwest Power Pool, which coordinates electricity distribution for parts of 14 states including Oklahoma Kansas, Nebraska and even as far north as North Dakota, announced rolling blackouts across its network on Monday as a result of the power outages.

“In our history as a grid operator, this is an unprecedented event and marks the first time SPP has ever had to call for controlled interruptions of service” SPP’s executive vice-president and chief operating officer Lanny Nickell said in a release, adding the move was “a last resort” to “prevent circumstances from getting worse.”

The frigid conditions have led to a surge in natural gas prices across the continent, including in Alberta where the AECO benchmark price jumped to a seven-year high of $6.36 per thousand cubic feet last week, a price not seen since 2014.

Energy systems in Texas and Oklahoma, which are major energy exporters to other U.S. states, are built to withstand severe heat – not extreme cold. The result is a disruption to the gas supply at exactly the time the U.S. energy system is demanding those molecules.

“Given how far south it’s gone into Texas, this is where you have a lot of gas production that isn’t properly winterized,” said Jeremy McCrea, an analyst with Raymond James covering the natural gas industry.

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BNEF 2019 New Energy Outlook projects surging renewable energy demand, aggressive decarbonization, wind and solar cost declines, battery storage growth, coal phase-out, and power market reform to meet Paris Agreement targets through 2050.

Key Points

Bloomberg's NEO 2019 forecasts power demand, renewables growth, and decarbonization pathways through 2050.

✅ Predicts wind/solar to ~50% of global electricity by 2050

✅ Foresees coal decline; Asia transitions slower than Europe

✅ Calls for power market reform and battery integration

In a report that examines the ways in which renewable energy demand is expected to increase, Bloomberg New Energy Finance (BNEF) finds that “aggressive decarbonization” will be required beyond 2030 to meet the temperature goals of the Paris Agreement on climate change.

Focusing on electricity, BNEF’s 2019 New Energy Outlook (NEO) predicts a 62% increase in global power demand, leading to global generating capacity tripling between now and 2050, when wind and solar are expected to make up almost 50% of world electricity, as wind and solar gains indicate, due to decreasing costs.

The report concludes that coal will collapse everywhere except Asia, and, by 2032, there will be more wind and solar electricity than coal-fired electricity. It forecasts that coal’s role in the global power mix will decrease from 37% today, as renewables surpass 30% globally, to 12% by 2050 with the virtual elimination of oil as a power-generating source.

Highlighting regional differences, the report finds that:

Western European economies are already on a strong decarbonization path due to carbon pricing and strong policy support, with offshore wind costs dropping bolstering progress;

by 2040, renewables will comprise 90% of the electricity mix in Europe, with wind and solar accounting for 80%;

the US, with low-priced natural gas, and China, with its coal-fired plants, will transition more slowly even as 30% from wind and solar becomes feasible; and

China’s power sector emissions will peak in 2026 and then fall by more than half over the next 20 years, as solar PV growth accelerates, with wind and solar increasing from 8% to 48% of total electricity generation by 2050.

Power markets must be reformed to ensure wind, solar and batteries are properly remunerated for their contributions to the grid.

The 2019 report finds that wind and solar now represent the cheapest option for adding new power-generating capacity in much of the world, amid record-setting momentum, which is expected to attract USD 13.3 trillion in new investment. While solar, wind, batteries and other renewables are expected to attract USD 10 trillion in investment by 2050, the report warns that curbing emissions will require other technologies as well.

Speaking about the report, Matthias Kimmel, NEO 2019 lead analyst, said solar photovoltaic modules, wind turbines and lithium-ion batteries are set to continue on aggressive cost reduction curves of 28%, 14% and 18%, respectively, for every doubling in global installed capacity. He explained that by 2030, energy generated or stored and dispatched by these technologies will undercut electricity generated by existing coal and gas plants.

To achieve this level of transition and decarbonization, the report stresses, power markets must be reformed to ensure wind, solar and batteries are “properly remunerated for their contributions to the grid.”

Additionally, the 2019 NEO includes a number of updates such as:

• new scenarios on global warming of 2°C above preindustrial levels, electrified heat and road transport, and an updated coal phase-out scenario;
• new sections on coal and gas power technology, the future grid, energy access, and costs related to decarbonization technology such as carbon capture and storage (CCS), biogas, hydrogen fuel cells, nuclear and solar thermal;
• sub-national results for China;
• the addition of commercial electric vehicles;
• an expanded air-conditioning analysis; and
• modeling of Brazil, Mexico, Chile, Turkey and Southeast Asia in greater detail.

Every year, the NEO compares the costs of competing energy technologies, informing projections like US renewables at one-fourth in the near term. The 2019 report brought together 65 market and technology experts from 12 countries to provide their views on how the market might evolve.

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