Macron: France, Germany to provide each other with gas, electricity, to weather crisis

Minnesota Electric Cooperatives are driving grid innovation with smart meters, time-of-use pricing, demand response, and energy storage, including iron-air batteries, to manage peak loads, integrate wind and solar, and cut costs for rural members.

Key Points

Member-owned utilities piloting load management, meters, and storage to integrate wind and solar, cutting peak demand.

✅ Time-of-use pricing pilots lower bills and shift peak load.

✅ Iron-air battery tests add multi-day, low-cost energy storage.

✅ Smart meters enable demand response across rural co-ops.

Minnesota electric cooperatives have quietly emerged as laboratories for clean grid innovation, outpacing investor-owned utilities on smart meter installations, time-based pricing pilots, and experimental battery storage solutions.

“Co-ops have innovation in their DNA,” said David Ranallo, a spokesperson for Great River Energy, a generation and distribution cooperative that supplies power to 28 member utilities — making it one of the state’s largest co-op players.

Minnesota farmers helped pioneer the electric co-op model more than a century ago, similar to modern community-generated green electricity initiatives, pooling resources to build power lines, transformers and other equipment to deliver power to rural parts of the state. Today, 44 member-owned electric co-ops serve about 1.7 million rural and suburban customers and supply almost a quarter of the state’s electricity.

Co-op utilities have by many measures lagged on clean energy. Many still rely on electricity from coal-fired power plants. They’ve used political clout with rural lawmakers to oppose new pollution regulations and climate legislation, and some have tried to levy steep fees on customers who install solar panels.

Where they are emerging as innovators is with new models and technology for managing electric grid loads — from load-shifting water heaters to a giant experimental battery made of iron. The programs are saving customers money by delaying the need for expensive new infrastructure, and also showing ways to unlock more value from cheap but variable wind and solar power.

Unlike investor-owned utilities, “we have no incentive to invest in new generation,” said Darrick Moe, executive director of the Minnesota Rural Electric Association. Curbing peak energy demand has a direct financial benefit for members.

Minnesota electric cooperatives have launched dozens of programs, such as the South Metro solar project, in recent years aimed at reducing energy use and peak loads, in particular. They include:

Cost calculations are the primary driver for electric cooperatives’ recent experimentation, and a lighter regulatory structure and evolving electricity market reforms have allowed them to act more quickly than for-profit utilities.

“Co-ops and [municipal utilities] can act a lot more nimbly compared to investor-owned utilities … which have to go through years of proceedings and discussions about cost-recovery,” said Gabe Chan, a University of Minnesota associate professor who has researched electric co-ops extensively. Often, approval from a local board is all that’s required to launch a venture.

Great River Energy’s programs, which are rebranded and sold through member co-ops, yielded more than 101 million kilowatt-hours of savings last year — enough to power 9,500 homes for a year.

Beyond lowering costs for participants and customers at large, the energy-saving and behavior-changing programs sometimes end up being cited as case studies by larger utilities considering similar offerings. Advocates supporting a proposal by the city of Minneapolis and CenterPoint Energy to allow residents to pay for energy efficiency improvements on their utility bills through distributed energy rebates used several examples from cooperatives.

Despite the pace of innovation on load management, electric cooperatives have been relatively slow to transition from coal-fired power. More than half of Great River Energy’s electricity came from coal last year, and Dairyland Power, another major power wholesaler for Minnesota co-ops, generated 70% of its energy from coal. Meanwhile, Xcel Energy, the state’s largest investor-owned utility, has already reduced coal to about 20% of its energy mix.

The transition to cleaner power for some co-ops has been slowed by long-term contracts with power suppliers that have locked them into dirty power. Others have also been stalled by management or boards that have been resistant to change. John Farrell, director of the Institute for Local Self-Reliance’s Energy Democracy program, said generalizing co-ops is difficult. 

“We’ve seen some co-ops that have got 75-year contracts for coal, that are invested in coal mines and using their newsletter to deny climate change,” he said. “Then you see a lot of them doing really amazing things like creating energy storage systems … and load balancing [programs], because they are unique and locally managed and can have that freedom to experiment without having to go through a regulatory process.”

Great River Energy, for its part, says it intends to reach 54% renewable generation by 2025, while some communities, like Frisco, Colorado, are targeting 100% clean electricity by specific dates. Its members recently voted to sell North Dakota’s largest coal plant, but the arrangement involves members continuing to buy power from the new owners for another decade.

The cooperative’s path to clean power could become clearer if its experimental iron-air battery project is successful. The project, the first of its kind in the country, is expected to be completed by 2023.

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Western Canada Electric Grid could deliver interprovincial transmission, reliability, peak-load support, reserve sharing, and wind and solar integration, lowering costs versus new generation while respecting AESO markets and Crown utility structures.

Key Points

Interprovincial transmission to share reserves, boost reliability, integrate wind and solar, and cut peak capacity costs.

✅ Cuts reserve margins via diversity of peak loads

✅ Enables wind and solar balancing across provinces

✅ Saves ratepayers vs replacing retiring thermal plants

The 2017 Canadian Free Trade Agreement does not do much to encourage provinces to trade electric energy east and west. Would a western Canada electric grid help electricity consumers in the western provinces? Some Alberta officials feel that their electric utilities are investor owned and they perceive the Crown corporations of BC Hydro, SaskPower and Manitoba Hydro to be subsidized by their provincial governments, so an interprovincial electric energy trade would not be on a level playing field.

Because of the limited trade of electric energy between the western provinces, each utility maintains an excessive reserve of thermal and hydroelectric generation greater than their peak loads, to provide a reliable supply during peak load days as grids are increasingly exposed to harsh weather across Canada. This excess does not include variable wind and solar generation, which within a province can’t be guaranteed to be available when needed most.

This attitude must change. Transmission is cheaper than generation, and coordinated macrogrids can further improve reliability and cut costs. By constructing a substantial grid with low profile and aesthetically designed overhead transmission lines, the excess reserve of thermal and hydroelectric generation above the peak electric load can be reduced in each province over time. Detailed assessments will ensure each province retains its required reliability of electric supply.

As the provinces retire aging thermal and coal-fired generators, they only need to replace them to a much lower level, by just enough to meet their future electric loads and Canada's net-zero grid by 2050 goals. Some of the money not spent in replacing retired generation can be profitably invested in the transmission grid across the four western provinces.

But what about Alberta, which does not want to trade electric energy with the other western provinces? It can carry on as usual within the Alberta Electric System Operator’s (AESO) market and will save money by keeping the installed reserve of thermal and hydroelectric generation to a minimum. When Alberta experiences a peak electric load day and some generators are out of service due to unplanned maintenance, it can obtain the needed power from the interprovincial electric grid. None of the other three western provinces will peak at the same time, because of different weather and time zones, so they will have spare capacity to help Alberta over its peak. The peak load in a province only lasts for a few hours, so Alberta will get by with a little help from its friends if needed.

The grid will have no energy flowing on it for this purpose except to assist a province from time to time when it’s unable to meet its peak load. The grid may only carry load five per cent of the time in a year for this purpose. Under such circumstances, the empty grid can then be used for other profitable markets in electric energy. This includes more effective use of variable wind and solar energy, by enabling a province to better balance such intermittent power as well as allowing increased installation of it in every province. This is a challenge for AESO which the grid would substantially ease.

Natural Resources Canada promoted the “Regional Electricity Co-Operative and Strategic Infrastructure” initiative for completion this year and contracted through AESO, alongside an Atlantic grid study to explore regional improvements. This is a first step, but more is needed to achieve the full benefit of a western grid.

In 1970 a study was undertaken to electrically interconnect Britain with France, which was justified based on the ability to reduce reserve generation in both countries. Initially Britain rejected it, but France was partially supportive. In time, a substantial interconnection was built, and being a profitable venture, they are contemplating increasing the grid connections between them.

For the sake of the western consumers of electricity and to keep electricity rates from rising too quickly, as well as allowing productive expansion of wind and solar energy in places like British Columbia's clean energy shift efforts, an electric grid is essential across western Canada.

Dennis Woodford is president of Electranix Corporation in Winnipeg, which studies electric transmission problems, particularly involving renewable energy generators requiring firm connection to the grid.

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BC Hydro LNG Load Forecast signals rising electricity demand from LNG Canada, Woodfibre, and Tilbury, aligning Site C dam capacity with BCUC review, hydroelectric supply, and a potential fourth project in feasibility study British Columbia.

Key Points

BC Hydro's projection of LNG-driven power demand, guiding Site C capacity, BCUC review, and grid planning.

✅ Includes LNG Canada, Woodfibre, and Tilbury load requests

✅ Aligns Site C hydroelectric output with industrial electrification

✅ Notes feasibility study for a fourth LNG project

Despite recent project cancellations, such as the Siwash Creek independent power project now in limbo, BC Hydro still expects three LNG projects — and possibly a fourth, which is undergoing a feasibility study — will need power from its controversial and expensive Site C hydroelectric dam.

In a letter sent to the British Columbia Utilities Commission (BCUC) on Oct. 3, BC Hydro’s chief regulatory officer Fred James said the provincially owned utility’s load forecast includes power demand for three proposed liquefied natural gas projects because they continue to ask the company for power.

The letter and attached report provide some detail on which of the LNG projects proposed in B.C. are more likely to be built, given recent project cancellations.

The documents are also an attempt to explain why BC Hydro continues to forecast a surge in electricity demand in the province, as seen in its first call for power in 15 years driven by electrification, even though massive LNG projects proposed by Malaysia’s state owned oil company Petronas and China’s CNOOC Nexen have been cancelled.

An explanation is needed because B.C.’s new NDP government had promised the BCUC would review the need for the $9-billion Site C dam, which was commissioned to provide power for the province’s nascent LNG industry, amid debates over alternatives like going nuclear among residents. The commission had specifically asked for an explanation of BC Hydro’s electric load forecast as it relates to LNG projects by Wednesday.

The three projects that continue to ask BC Hydro for electricity are Shell Canada Ltd.’s LNG Canada project, the Woodfibre LNG project and a future expansion of FortisBC’s Tilbury LNG storage facility.

None of those projects have officially been sanctioned but “service requests from industrial sector customers, including LNG, are generally included in our industrial load forecast,” the report noted, even as Manitoba Hydro warned about energy-intensive customers in a separate notice.

In a redacted section of the report, BC Hydro also raises the possibility of a fourth LNG project, which is exploring the need for power in B.C.

“BC Hydro is currently undertaking feasibility studies for another large LNG project, which is not currently included in its Current Load Forecast,” one section of the report notes, though the remainder of the section is redacted.

The Site C dam, which has become a source of controversy in B.C. and was an important election issue, is currently under construction and, following two new generating stations recently commissioned, is expected to be in service by 2024, a timeline which had been considered to provide LNG projects with power by the time they are operational.

BC Hydro’s letter to the BCUC refers to media and financial industry reports that indicate global LNG markets will require more supply by 2023.

“While there remains significant uncertainty, global LNG demand will continue to grow and there is opportunity for B.C. LNG,” the report notes.

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California Grid Modernization Funding will upgrade transmission and distribution, boost grid resilience, enable renewable energy integration, expand energy storage, and deploy smart grid controls statewide with over $500 million in federal infrastructure investment.

Key Points

Federal support to harden California's grid, integrate renewables, add storage, and deploy smart upgrades for reliability.

✅ Strengthens transmission and distribution for wildfire and heat resilience

✅ Integrates solar and wind with storage and advanced grid controls

✅ Deploys smart meters, DER management, and modern cybersecurity

California has recently been awarded over $500 million in federal funds to significantly improve and modernize its power grid. This substantial investment marks a pivotal step in addressing the state’s ongoing energy challenges, enhancing grid resilience, and supporting its ambitious climate goals. The funding, announced by federal and state officials, is set to bolster California’s efforts to upgrade its electrical infrastructure, integrate renewable energy sources, and ensure a more reliable and sustainable energy system for its residents.

California's power grid has faced numerous challenges in recent years, including extreme weather events, high energy demand, and an increasing reliance on renewable energy sources. The state's electrical infrastructure has struggled to keep pace with these demands, leading to concerns about reliability, efficiency, and the capacity to handle new energy technologies. The recent federal funding is a critical component of a broader strategy to address these issues and prepare the grid for future demands.

The $500 million in federal funds is part of a larger initiative to support energy infrastructure projects across the United States, including a Washington state grant that strengthens regional infrastructure. The investment aims to modernize aging grid systems, improve energy efficiency, and enhance the integration of renewable energy sources. For California, this funding represents a significant opportunity to address several key areas of concern in its power grid.

One of the primary objectives of the funding is to enhance the resilience of the power grid. California has experienced a series of extreme weather events, including wildfires and heatwaves, driven in part by climate change impacts across the U.S., which have put considerable strain on the electrical infrastructure. The new investment will support projects designed to strengthen the grid’s ability to withstand and recover from these events. This includes upgrading infrastructure to make it more robust and less susceptible to damage from natural disasters.

Another key focus of the funding is the integration of renewable energy sources. California is a leader in the adoption of solar and wind energy, and the state has set ambitious goals for increasing its use of clean energy. However, integrating these variable energy sources into the grid presents technical challenges, including ensuring a stable and reliable power supply. The federal funds will be used to develop and deploy advanced technologies that can better manage and store renewable energy, such as battery storage systems, improving the overall efficiency and effectiveness of the grid.

In addition to resilience and renewable integration, the funding will also support efforts to modernize grid infrastructure. This includes upgrading transmission and distribution systems, implementing smarter electricity infrastructure and smart grid technologies, and enhancing grid management and control systems. These improvements are essential for creating a more flexible and responsive power grid that can meet the evolving needs of California’s energy landscape.

The investment in grid modernization also aligns with California’s broader climate goals. The state has set targets to reduce greenhouse gas emissions and increase the use of clean energy sources as it navigates keeping the lights on during its energy transition. By improving the power grid and supporting the integration of renewable energy, California is making progress toward achieving these goals while also creating jobs and stimulating economic growth.

The allocation of federal funds comes at a crucial time for California. The state has faced significant challenges in recent years, including power outages, energy reliability issues, and increasing energy costs that make repairing California's grid especially complex today. The new funding is expected to address many of these concerns by supporting critical infrastructure improvements and ensuring that the state’s power grid can meet current and future demands.

Federal and state officials have expressed strong support for the funding and its potential impact. The investment is seen as a major step forward in creating a more resilient and sustainable energy system for California. It is also expected to serve as a model for other states facing similar challenges in modernizing their power grids and integrating renewable energy sources.

The federal funding is part of a broader push to address infrastructure needs across the country. The Biden administration has prioritized investment in energy infrastructure, including a $34 million DOE initiative supporting grid improvements, as part of its broader agenda to combat climate change and build a more sustainable economy. The funding for California’s power grid is a reflection of this commitment and an example of how federal resources can support state and local efforts to improve infrastructure and address pressing energy challenges.

In summary, California’s receipt of over $500 million in federal funds represents a significant investment in the state’s power grid. The funding will support efforts to enhance grid resilience, integrate renewable energy sources, and modernize infrastructure. As California continues to face challenges related to extreme weather, energy reliability, and climate goals, this investment will play a crucial role in building a more reliable, efficient, and sustainable energy system. The initiative also highlights the importance of federal support in addressing infrastructure needs and advancing environmental and economic goals.

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Alberta Energy-Only Electricity Market faces capacity market debate, AESO price cap review, and coal-to-gas shifts by TransAlta and Capital Power, balancing reliability with volatility as investment signals evolve across Alberta's grid.

Key Points

An energy market paying generators only for electricity sold, with AESO oversight and a price cap guiding new capacity.

✅ AESO reviewing $999 per MW-h wholesale price cap.

✅ UCP retained energy-only; capacity market plan cancelled.

✅ TransAlta and Capital Power shift to coal-to-gas.

The Kenney government’s decision to cancel the redesign of Alberta’s electricity system to a capacity market won’t side-track two of the province’s largest power generators from converting coal-fired facilities to burn natural gas as part of Alberta’s shift from coal to cleaner energy overall.

But other changes could be coming to the province’s existing energy-only electricity market — including the alteration of the $999 per megawatt-hour (MW-h) wholesale price cap in Alberta.

The heads of TransAlta Corp. and Capital Power Corp. are proceeding with strategies to convert existing coal-fired power generating facilities to use natural gas in the coming years.

Calgary-based TransAlta first announced in 2017 that it would make the switch, as the NDP government was in the midst of overhauling the electricity sector and wind generation began to outpace coal in the province.

At the time, the Notley government planned to phase out coal-fired power by 2030, even as Alberta moved to retire coal by 2023 in practice, and shift Alberta into an electricity capacity market in 2021.

Such a move, made on the recommendation of the Alberta Electric System Operator (AESO), was intended to reduce price volatility and ensure system reliability.

Under the energy-only market, generators receive payments for electricity produced and sold into the grid. In a capacity market, generators are also paid for having power available on demand, regardless of how often they sell energy into the provincial grid.

The UCP government decided last month to ditch plans for a capacity market after consulting with the sector, saying it would be better for consumers.

On a conference call, TransAlta CEO Dawn Farrell said the company will convert coal-fired generating plants to burn gas, although it may alter the mix between simple conversions and switching to so-called “hybrid” plants.

(A hybrid conversion is a larger and more-expensive switch, as it includes installing a new gas turbine and heat-recovery steam generator, but it creates a highly efficient combined cycle unit.)

“Our view is fundamentally that carbon will be priced over the next 20 years no matter what,” she said Friday.

“We cannot get off coal fast enough in this company, and gas right now in Alberta is extremely inexpensive…

“So our coal-to-gas strategy is completely predicated on our belief that it’s not smart to be in carbon-intensive fuels for the future.”

Elsewhere in Canada, the Stop the Shock campaign has advocated for reviving coal power, underscoring ongoing policy debates.

The company said it’s planning the coal-to-gas conversion and re-powering of some or all of the units at its Keephills and Sundance facilities to gas-fired generation sometime between 2020 and 2023.

Similarly, Capital Power CEO Brian Vaasjo said the Edmonton-based company is moving ahead with a project that will allow it to burn both coal and natural gas at its Genesee generating station, even as Ontario’s energy minister sought to explore a halt to natural gas generation elsewhere.

In June, the company announced it would spend an estimated $50 million between 2019 and 2021 to allow it to use gas at the facility.

“What we’re doing is going to be dual fuel, so we will be able to operate 100 per cent natural gas or 100 per cent coal and everything in between,” Vaasjo said in an interview.

“You can expect to see we will be burning coal in the winter when natural gas prices are high, and we will be burning natural gas in summer when gas prices are real low.”

The transition comes as the government’s decision to stick with the energy-only market has been welcomed by players in the industry, and as Alberta's electricity future increasingly leans on wind resources.

A study by electricity consultancy EDC Associates found the capacity market would result in consumers paying an extra $1.4 billion in direct costs in 2021-22, as it required more generation to come online earlier than expected.

These additional costs would have accumulated to $10 billion by 2030, said EDC chief executive Duane-Reid Carlson.

For Capital Power, the decision to stick with the current system makes the province more investable in the future. Vaasjo said there was great uncertainty about the transition to a capacity market, and the possibility of rules shifting further.

Officials with Enmax Corp. said the city-owned utility would not have invested in future generation under the proposed capacity market.

“There is no short-term need (today) for new generation, so we’re just looking at the market and saying, ‘OK, as it evolves, we will see what happens,’” said Enmax vice-president Tim Boston.

Sticking with the energy-only market doesn’t mean Alberta will keep the existing rules.

In a July 25 letter, Alberta Energy Minister Sonya Savage directed AESO chair Will Bridge to examine if changes to the existing market are needed and report back by July 2020.

AESO, which manages the power grid, has been asked to investigate whether the current price cap of $999 per megawatt-hour (MW-h) should be changed.

The price ceiling hasn’t been altered since the energy-only market was implemented by the Klein government about two decades ago.

While allowing prices to go higher would increase volatility, reflecting lessons from Europe’s power crisis about scarcity pricing, during periods of rising demand and limited supply, it would send a signal to generators when investment in new generation is required, said Kent Fellows, a research associate at the University of Calgary’s School of Public Policy.

“Keeping the price (cap) too low could end up costing us more in the long run,” he said.

In a 2016 report, AESO said the province examined raising the price cap to $5,000 per MW-h, but “determined that it was unlikely to be successful in attracting investment due to increased price volatility.”

However, the amount of future generation that will be required in Alberta has been scaled back by the province.

In the United States, the Electricity Reliability Council of Texas (ERCOT) allows wholesale power prices in the state to climb to a cap of $9,000 per megawatt hours as demand rises — as it did Tuesday in the midst of a heat wave, according to Bloomberg.

Jim Wachowich, legal counsel for the Consumers’ Coalition of Alberta, said while few players are exposed to spot electricity prices, he has yet to be convinced raising the cap would be good for Albertans.

“Someone has to show me the evidence, and I suspect that’s what the minister has asked the AESO to do,” he said.

Generators say they believe some tinkering is needed to the energy-only market to ensure new generation is built when it’s required.

“The No. 1 change that the government has to … think about is in pricing,” added Farrell.

“If you don’t have enough of a price signal in an energy-only market to attract new capital, you won’t get new capital — and you’ll run up against the wall.”

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Texas EV Registration Fee adds a $200 annual charge under Senate Bill 505, offsetting lost gasoline tax revenue to the State Highway Fund, impacting electric vehicle owners at registration and renewals across Texas.

Key Points

A $200 yearly charge on electric vehicles to replace lost gasoline tax revenue and support Texas Highway Fund road work.

✅ $200 due at registration or renewal; $400 upfront on new EVs.

✅ Enacted by Senate Bill 505 to offset lost gasoline tax revenue.

✅ Advocates propose mileage-based fees; limited $2,500 rebates exist.

Plano resident Tony Federico bought his Tesla five years ago in part because he hated spending lots of money on gas, and Supercharger billing changes have also influenced charging expenses. But that financial calculus will change slightly on Sept. 1, when Texas will start charging electric vehicle drivers an additional fee of $200 each year.

“It just seems like it’s arbitrary, with no real logic behind it,” said Federico, 51, who works in information technology. “But I’m going to have to pay it.”

Earlier this year, state lawmakers passed Senate Bill 505, which requires electric vehicle owners to pay the fee when they register a vehicle or renew their registration, even as fights for control over charging continue among utilities, automakers and retailers. It’s being imposed because lawmakers said EV drivers weren’t paying their fair share into a fund that helps cover road construction and repairs across Texas.

The cost will be especially high for those who purchase a new electric vehicle and have to pay two years of registration, or $400, up front.

Texas agencies estimated in a 2020 report that the state lost an average of $200 per year in federal and state gasoline tax dollars when an electric vehicle replaced a gas-fueled one. The agencies called the fee “the most straightforward” remedy.

Gasoline taxes go to the State Highway Fund, which the Texas Department of Transportation calls its “primary funding source.” Electric vehicle drivers don’t pay those taxes, though, because they don’t use gasoline.

Still, EV drivers do use the roads. And while electric vehicles make up a tiny portion of cars in Texas for now, that fraction is expected to increase, raising concerns about state power grids in the years ahead.

Many environmental and consumer advocates agreed with lawmakers that EV drivers should pay into the highway fund but argued over how much, and debates over fairer vehicle taxes are surfacing abroad as well.

Some thought the state should set the fee lower to cover only the lost state tax dollars, rather than both the state and federal money, because federal officials may devise their own scheme. Others argued the state should charge nothing because EVs help reduce greenhouse gas emissions that drive climate change and can offer budget benefits for many owners.

“We urgently need to get more electric vehicles on the road,” said Luke Metzger, executive director of Environment Texas. “Any increased fee could create an additional barrier for Texans, and particularly more moderate- to low-income Texans, to make that transition.”

Tom “Smitty” Smith, the executive director of the Texas Electric Transportation Resources Alliance, advocated for a fee based on how many miles a person drove their electric car, which would better mirror how the gas taxes are assessed.

Texas has a limited incentive that could offset the cost: It offers rebates of up to $2,500 for up to 2,000 new hydrogen fuel cell, electric or hybrid vehicles every two years. Adrian Shelley, Public Citizen’s Texas office director, recommended that the state expand the rebates, noting that state-level EV benefits can be significant.

In the Houston area, dealer Steven Wolf isn’t worried about the fee deterring potential customers from buying the electric Ford F-150 Lightning and Mustang Mach-E vehicles he sells. Electric cars are already more expensive than comparable gasoline-fueled cars, and charging networks compete for drivers, he said.

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