Endesa the new utility power in Ireland

Amazon Renewable Energy Projects advance net zero goals with a Scotland wind farm PPA and US solar farms in North Carolina and Virginia, delivering clean power, added capacity, and lower carbon emissions across cloud operations.

Key Points

Amazon initiatives adding wind and solar capacity in the UK and US to cut carbon and power cloud operations.

✅ Largest UK corporate wind PPA on Scotland Kintyre Peninsula

✅ Two US solar farms in North Carolina and Virginia

✅ 265 MW added capacity, 668,997 MWh clean power annually

Amazon is launching three renewable energy projects in the United States and the United Kingdom that support Amazon’s commitment to using net zero carbon energy by 2040.

The U.K. project is a wind farm on the Kintyre Peninsula in Scotland, aligned with a 10 GW renewables contract boosting the U.K. grid. It will generate 168,000 megawatt hours (MWh) of clean energy each year, enough to power 46,000 U.K. homes. It will be the largest corporate wind power purchase agreement (PPA) in the U.K.

Offshore wind energy in the UK is powering up rapidly, complementing onshore developments.

The other two are solar projects – one in Warren County, N.C, and the other in Prince George County, Va, reflecting broader US solar and wind growth trends nationwide. Together, they are expected to generate 500,997 MWh of energy annually. It is Amazon’s second renewable energy project in North Carolina, following the Amazon Wind Farm US East operated by Avangrid Renewables, and eighth in Virginia.

The three new Amazon wind and solar projects – which are expected to be in operation in 2012 — will provide 265 MW of additional renewable capacity, and align with U.K. wind power lessons for the U.S. market nationwide.

“In addition to the environmental benefits inherently associated with running applications in the cloud, Amazon is committed to minimizing our carbon emissions and reaching 80% renewable energy use across the company by 2024. We’ve announced eight projects this year and have more projects on the horizon – and we’re committed to investing in renewable energy as a critical step toward addressing our carbon footprint globally,” Kara Hurst, director of sustainability at Amazon, said. “With nearly 70 renewable energy projects around the globe – including 54 solar rooftops – we are making significant progress towards reaching Amazon’s company-wide commitment to reach 100% renewable energy by 2030.”

Amazon has launched 18 utility-scale wind and solar renewable energy projects to date, and in parallel, Duke Energy Renewables has acquired three California solar projects, underscoring sector momentum. They will generate over 1,600 MW of renewable capacity and deliver more than 4.6 million MWh of clean energy annually. Amazon has also installed more than 50 solar rooftops on fulfillment centers and sort centers around the world. They generate 98 MW of renewable capacity and deliver 130,000 MWh of clean energy annually.

“Today’s announcement by Amazon is another important step for North Carolina’s clean energy plan that will increase our reliance on renewables and reduce our greenhouse gas emissions,” North Carolina Governor Roy Cooper said. “Not only is this the right thing to do for our planet, it’s the right thing to do for our economy. More clean energy jobs means better jobs for North Carolina families.”

Amazon reports on its sustainability commitments, initiatives, and performance on a new web site the company recently launched. It includes information on Amazon’s carbon footprint and other metrics and updates the company’s progress towards reaching The Climate Pledge. 

“It’s wonderful to see the announcement of these new projects, helping bring more clean energy to the Commonwealth of Virginia where Amazon is already recognized as a leader in bringing renewable energy projects online,” Virginia Governor Ralph Northam said. “These solar farms help reaffirm the Commonwealth’s role as a leading producer of clean energy in the U.S., helping take the nation forward in responding to climate change.”

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Texas After-Labor Day School Start could ease ERCOT's power grid strain by shifting peak demand, lowering air-conditioning loads in schools, improving grid reliability, reducing electricity costs, and curbing emissions during extreme heat the summer months.

Key Points

A proposed calendar shift to start school after Labor Day to lower ERCOT peak demand, costs, and grid risk.

✅ Cuts school HVAC loads during peak summer heat

✅ Lowers costly peaker plant use and electricity rates

✅ Requires calendar changes, testing and activities shifts

As Texas faces increasing demands on its power grid, a new proposal is gaining traction: starting the school year after Labor Day. This idea, reported by the Dallas News, suggests that delaying the start of the academic year could help alleviate some of the pressure on the state’s electricity grid during the peak summer months, potentially leading to both grid stability and financial savings. Here’s an in-depth look at how this proposed change could impact Texas’s energy landscape and education system.

The Context of Power Grid Strain

Texas's power grid, operated by the Electric Reliability Council of Texas (ERCOT), has faced significant challenges in recent years. Extreme weather events, record-breaking temperatures, and high energy demand have strained the grid, and some analyses argue that climate change, not demand is the biggest challenge today, leading to concerns about reliability and stability. The summer months are particularly taxing, as the demand for air conditioning surges, often pushing the grid to its limits.

In this context, the idea of adjusting the school calendar to start after Labor Day has been proposed as a potential strategy to help manage electricity demand. By delaying the start of school, proponents argue that it could reduce the load on the power grid during peak usage periods, thereby easing some of the stress on energy resources.

Potential Benefits for the Power Grid

The concept of delaying the school year is rooted in the potential benefits for the power grid. During the hottest months of summer, the demand for electricity often spikes as families use air conditioning to stay cool, and utilities warn to prepare for blackouts as summer takes hold. School buildings, typically large and energy-intensive facilities, contribute significantly to this demand when they are in operation.

Starting school later could help reduce this peak demand, as schools would be closed during the hottest months when the grid is under the most pressure. This reduction in demand could help prevent grid overloads and reduce the risk of power outages, at a time when longer, more frequent outages are afflicting the U.S. power grid, ultimately contributing to a more stable and reliable electricity supply.

Additionally, a decrease in peak demand could help lower electricity costs. Power plants, particularly those that are less efficient and more expensive to operate, are often brought online during periods of high demand. By reducing the peak load, the state could potentially minimize the need for these costly power sources, leading to lower overall energy costs.

Financial and Environmental Considerations

The financial implications of starting school after Labor Day extend beyond just the power grid. By reducing energy consumption during peak periods, the state could see significant savings on electricity costs. This, in turn, could lead to lower utility bills for schools, businesses, and residents alike, a meaningful relief as millions risk electricity shut-offs during summer heat.

Moreover, reducing the demand for electricity from fossil fuel sources can have positive environmental impacts. Lower peak demand may reduce the reliance on less environmentally friendly energy sources, and aligns with calls to invest in a smarter electricity infrastructure nationwide, thereby decreasing greenhouse gas emissions and contributing to overall environmental sustainability.

Challenges and Trade-offs

While the proposal offers potential benefits, it also comes with challenges and trade-offs. Adjusting the school calendar would require significant changes to the academic schedule, potentially affecting extracurricular activities, summer programs, and family plans, and comparisons to California's reliability challenges underscore the complexity. Additionally, there could be resistance from various stakeholders, including parents, educators, and students, who are accustomed to the current school calendar.

There are also logistical considerations to address, such as how a delayed start might impact standardized testing schedules and the academic calendar for higher education institutions. These factors would need to be carefully evaluated to ensure that the proposed changes do not adversely affect educational outcomes or create unintended consequences.

Looking Ahead

The idea of starting Texas schools after Labor Day represents an innovative approach to addressing the challenges facing the state’s power grid. By potentially reducing peak demand and lowering energy costs, and alongside efforts to connect Texas's grid to the rest of the nation, this proposal could contribute to greater grid stability and financial savings. However, careful consideration and planning will be essential to navigate the complexities of altering the school calendar and to ensure that the benefits outweigh the challenges.

As Texas continues to explore solutions for managing its power grid and energy resources, the proposal to shift the school year schedule provides an intriguing possibility. It reflects a broader trend of seeking creative and multifaceted approaches to balancing energy demand, environmental sustainability, and public needs.

In conclusion, starting schools after Labor Day could offer tangible benefits for Texas’s power grid and financial well-being. As discussions on this proposal advance, it will be important to weigh all factors and engage stakeholders to ensure a successful and equitable implementation.

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Neste wind power agreement boosts renewable electricity in Finland, partnering with Ilmatar and Fortum to supply Porvoo and Naantali sites, cutting Scope 2 emissions and advancing a 2035 carbon-neutral production target via long-term PPAs.

Key Points

A PPA to source wind power for sites, cutting Scope 2 emissions and supporting Neste's 2035 carbon-neutral goal.

✅ 10-year PPA with Ilmatar; + Fortum boosts renewable electricity share.

✅ Supplies ~7% of Porvoo-Naantali electricity; capacity >20 MW.

✅ Cuts Scope 2 emissions by ~55 kt CO2e per year toward 2035 neutrality.

Neste is committed to reaching carbon neutral production by 2035, mirroring efforts such as Olympus 100% renewable electricity commitments across industry.

As part of this effort, the company is increasing the use of renewable electricity at its production sites in Finland, reflecting trends such as Ireland's green electricity targets across Europe, and has signed a wind power agreement with Ilmatar, a wind power company. The agreement has been made together with Borealis, Neste's long-term partner in the Kilpilahti area in Porvoo, Finland.

As a result of the agreement with Ilmatar, as well as that signed with Fortum at the end of 2019, and in line with global growth such as Enel's 450 MW wind project in the U.S., nearly 30% of the energy used at Neste's production sites in Porvoo and Naantali will be renewable wind power in 2022.

'Neste's purpose is to create a healthier planet for our children. Our two climate commitments play an important role in living up to this ambition, and one of them is to reach carbon neutral production by 2035. It is an enormous challenge and requires several concrete measures and investments, including innovations like offshore green hydrogen initiatives. Wind power, including advances like UK offshore wind projects, is one of the over 70 measures we have identified to reduce our production's greenhouse gas emissions,' Neste's President and CEO Peter Vanacker says.

With the ten year contract, Neste is committed to purchase about one-third of the production of Ilmatar's two wind farms, reflecting broader market moves such as BC Hydro wind deals in Canada. The total capacity of the agreement is more than 20 MW, and the energy produced will correspond to around 7% of the electricity consumption at Neste's sites in Porvoo and Naantali. The wind power deliveries are expected to begin in 2022.

The two wind power agreements help Neste to reduce the indirect greenhouse gas emissions (Scope 2 emissions defined by the Greenhouse Gas Protocol) of electricity purchases at its Finnish production sites, a trend mirrored by Dutch green electricity growth across Europe, annually by approximately 55 kilotons. 55 kt/a CO2e equals annual carbon footprint of more than 8,500 EU citizens.

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Electric tractors are surging, with battery-powered models, grid-tethered JD GridCON, and solar-charged designs delivering autonomous guidance, high efficiency, low maintenance, quiet operation, robust PTO compatibility, and durability for sustainable, precision agriculture.

Key Points

Electric tractors use battery or grid power to run implements with high efficiency, low noise, and minimal maintenance.

✅ Battery, grid-tethered, or solar-charged power options

✅ Lower operating costs, reduced noise, fewer moving parts

✅ Autonomous guidance, PTO compatibility, and quick charging

Car and truck manufacturers are falling off the fossil fuel bandwagon in droves and jumping on the electric train.

Now add tractors to that list.

Every month, another e-tractor announcement comes across our desks. Environmental factors drive this trend, along with energy efficiency, lower maintenance, lower noise level and motor longevity, and even autonomous weed-zapping robots are emerging.

Let’s start with the Big Daddy of them all, the 400 horsepower JD GridCON. This tractor is not a hybrid and it has no hassle with batteries. The 300 kilowatts of power come to the GridCON through a 1,000 metre extension cord connected to the grid, including virtual power plants or an off-field generator. A reel on the tractor rolls the cable in and out. The cable is guided by a robotic arm to prevent the tractor from running over it.

It uses a 700 volt DC bus for electric power distribution onboard and for auxiliary implements. It uses a cooling infrastructure for off-board electrical use. Total efficiency of the drive train is around 85 percent. A 100 kilowatt electric motor runs the IVT transmission. There’s an auxiliary outlet for implements powered by an electric motor up to 200 kW.

GridCON autonomously follows prescribed routes in the field at speeds up to 12 m.p.h., leveraging concepts similar to fleet management solutions for coordination. It can also be guided manually with a remote control when manoeuvring the tractor to enter a field. Empty weight is 8.5 tonnes, which is about the same as a 6195R but with double the power. Deere engineers say it will save about 50 percent in operating costs compared to battery powered tractors.

Solectrac
Two California-built all-battery powered tractors are finally in full production. While the biggest is only 40 horsepower, these are serious tractors that may foretell the future of farm equipment.

The all-electric 40 h.p. eUtility tractor is based on a 1950s Ford built in India. Solectrac is able to buy the bare tractor without an engine, so it can create a brand new electric tractor with no used components for North American customers. One tractor has already been sold to a farmer in Ontario. | Solectrac photo
The tractors are built by Solectrac, owned by inventor Steve Heckeroth, who has been doing electric conversions on cars, trucks, race cars and tractors for 25 years. He said there are three main reasons to take electric tractors seriously: simplicity, energy efficiency and longevity.

“The electric motor has only one moving part, unlike small diesel engines, which have over 300 moving parts,” Heckeroth said, adding that Solectrac tractors are not halfway compromise hybrids but true electric machines that get their power from the sun or the grid, particularly in hydro-rich regions like Manitoba where clean electricity is abundant, whichever is closest.

Neither tractor uses hydraulics. Instead, Heckeroth uses electric linear actuators. The ones he installs provide 1,000 pounds of dynamic load and 3,000 lb. static loads. He uses linear actuators because they are 20 times more efficient than hydraulics.

The eUtility and eFarmer are two-wheel drive only, but engineers are working on compact four-wheel drive electric tractors. Each tractor carries a price tag of US$40,000. Because production numbers are still limited, both tractors are available on a first to deposit basis. One e-tractor has already been sold and delivered to a farmer in Ontario.

The eUtility is a 40 h.p. yard tractor that accepts all Category 1, 540 r.p.m. power take-off implements on the rear three-point hitch, except those requiring hydraulics. An optional hydraulic pump can be installed for $3,000 for legacy implements that require hydraulics. For that price, a dedicated electricity believer might instead consider converting the implement to electric.

“The eUtility is actually a converted new 1950s Ford tractor made in a factory in India that was taken over after the British were kicked out in 1948,” Heckeroth said.

“I am able to buy only the parts I need and then add the motor, controller and batteries. I had to go to India because it’s one of the few places that still makes geared transmissions. These transmissions work the best for electric tractors. Gear reduction is necessary to keep the motor in the most efficient range of about 2,000 r.p.m. It has four gears with a high and low range, which covers everything from creep to 25 m.p.h.

On his eUtility, a single 30 kWh onboard battery pack provides five to eight hours of run time, depending on loads. It can carry two battery packs. The Level 2 quick charge gives an 80 percent charge for one pack in three hours. Two packs can receive a full charge overnight with support from home batteries like Powerwall for load management.

The integrated battery management system protects the batteries during charging and discharging, while backup fuel cell chargers can keep storage healthy in remote deployments. Batteries are expected to last about 10 years, depending on the number of operating cycles and depth of discharge.

Exchangeable battery packs are available to keep the tractor running through the full work day. These smaller 20 kWh packs can be mounted on the rear hitch to balance the weight of the optional front loader or carried in the optional front loader to balance the weight of heavy implements mounted on the rear hitch.

The second tractor is the 20 kWh eFarmer, which features high visibility for row crop farms at a fraction of the cost of diesel fuel tractors. The 30 h.p. eFarmer is basically just a tube frame with the necessary components attached. A simple joystick controls steering, speed and brakes.

Harvest
Introduced to the North American public this spring by Motivo Engineering in California, the Harvest tractor is simply a big battery on wheels. The complex electrical system takes power in through a variety of renewable energy sources, such as solar panels with smart solar inverters enabling optimized PV integration, water wheels, wind turbines or even intermittent electrical grids. It stores electrical power on-board and delivers it when and where required, putting power out to a large number of electrical tools and farm implements. It operates in AC or DC modes.

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Texas PUC Appointments signal post-storm reform as Gov. Greg Abbott taps Peter Lake and advances Will McAdams for Senate confirmation, affecting ERCOT oversight, grid reliability, wholesale power pricing, and securitization for co-ops.

Key Points

Texas PUC appointments add Peter Lake and Will McAdams to steer ERCOT, grid reliability, and market policy.

✅ Peter Lake nominated chair to replace Arthur D'Andrea.

✅ Will McAdams advances toward Senate confirmation.

✅ Focus on ERCOT oversight, price cap debate, grid resilience.

A new set of Texas electricity regulators began to take shape Monday, as Gov. Greg Abbott nominated a finance expert to be the next chairman of the Public Utility Commission while his earlier choice of a PUC member moved toward Senate confirmation.

The Republican governor put forward Peter Lake of Austin, who has spent more than five years as an Abbott appointee to the Texas Water Development Board, as his second commission pick in as many weeks.

“I am confident he will bring a fresh perspective and trustworthy leadership to the PUC,” Abbott said of Lake, who once worked as a trader of futures and derivatives for a firm belonging to the Chicago Mercantile Exchange and more recently has eagerly promoted bonds for the State Water Implementation Fund for Texas.

“Peter’s expertise in the Texas energy industry and business management will make him an asset to the agency,” Abbott, who has touted grid readiness in recent months, said in a written statement. “I urge the Senate to swiftly confirm Peter’s appointment.”

On Monday, the Senate appeared to be moving quickly to confirm Abbott’s April 1 selection for the PUC, Will McAdams, president of Associated Builders and Contractors of Texas and a former legislative aide who helped write policy for regulated industries such as electricity.

McAdams was among the 129 nominees that the Senate Nominations Committee voted out, 8-0. His nomination heads now to the Senate floor.

All three of Abbott’s handpicked PUC commissioners who were in place before and during February’s calamitous winter storm have since quit or said they’re resigning, even as Sierra Club criticism of Abbott's demands intensified in the aftermath.

February’s polar vortex left in its wake physical and financial wreckage after a nonprofit grid operator answering to the PUC, amid calls for market reforms to avoid blackouts, shut off electricity to more than 4 million Texans, causing the deaths of at least 125 people, 13 of them in the Dallas-Fort Worth area.

Gov. Greg Abbott on Thursday named Will McAdams to the embattled Public Utility Commission of Texas. McAdams is a construction industry lobbyist with strong ties to the GOP-controlled Legislature. In Feb. 17 file photo, winter storm's snowfall andn large electrical transmission lines in South Arlington are pictured.

In a 45-minute confirmation hearing, McAdams, as lawmakers discussed ways to improve electricity reliability statewide, drew praise – and few tough questions.

McAdams, who previously worked for three GOP senators, testified that had he been on the commission in February, he would not have kept in place a controversial, $9,000-per-megawatt hour price cap on wholesale power for about 32 hours on Feb. 18-19.

“I don’t see myself making that decision,” he said.

McAdams, though, hedged slightly, saying he’s not privy to all information that the Electric Reliability Council of Texas, or ERCOT, and the PUC may have had at their disposal during the crisis.

The comments were notable because Lt. Gov. Dan Patrick and the Senate have fought with Abbott and the House over $16 billion in overcharges that, according to an independent market monitor, wrongly accrued near the end of the Feb. 15-19 outages.

Sen. Charles Schwertner, R-Georgetown, said the commission’s former chairwoman, DeAnn Walker, and Bill Magness, president of ERCOT, decided to hold the high cap in place because there “was still great concern about grid stability, even though there was significant reserves.”

He pressed McAdams to call that incorrect, which McAdams did.

“Given the fact pattern that I’m privy to, senator,” it wasn’t the right move, he said. “But again, there may be other facts out there. There probably are.”

McAdams acknowledged many homeowners and businesses were traumatized.

“The public’s confidence in the ability of the PUC to effectively regulate our electric markets has been badly damaged and shaken,” he said.

McAdams spoke favorably of renewable energy, calling wind and solar “absolutely valuable resources,” as the electricity sector faces profound change nationwide. To whatever extent those are not available, the PUC should “firm that up” with “dispatchable forms of generation,” such as gas, coal and nuclear, McAdams said.

He also called for lawmakers to consider providing electricity market bailout through “securitization,” or low-interest bond financing, to rural electric co-ops that were unable to pay the massive wholesale power bills they racked up during the February crisis.

“It would prevent those systems from having to front-load those costs onto their own members and smooth that out over a term of years,” while preventing an “uplift” of costs to other market participants who wisely hedged against soaring prices, McAdams said.

Noting that more than 400 bills have been filed to change ERCOT and how it’s governed, and as Texans prepare to vote on grid modernization funding this year, McAdams told the Senate panel, “It is clear to me that the Legislature wants meaningful changes to the status quo – to ensure that something positive comes out of this tragedy.”

Lake, who if confirmed by the Senate would replace Arthur D’Andrea as PUC chairman, grew up in Tyler. He attended prep school in New England and earned an undergraduate degree from the University of Chicago and a master of business administration degree from Stanford University.

He then worked for a commodities trading firm, a behavioral health company and as a business consultant before he became director of business development for Tyler-based Lake Ronel Oil Co. in 2014.

In late 2015, Abbott named Lake to the Texas Water Development Board and in February 2018 picked him to be the chairman of the three-member board that seeks to ensure water supplies for a fast-growing state.

Lake has steered the water board as it rolled out additional loans for water projects, approved by the Legislature and voters in 2013, and took the lead after Hurricane Harvey on flood control planning and infrastructure financing.

He’s posted exuberantly on Twitter as he toured agricultural water installations, lakes in West Texas and river authorities.

If confirmed, Lake and McAdams each would make $189,500 a year.

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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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