Atlantic City ElectricÂ’s Blueprint for the Future

Great Northern Transmission Line delivers 250 MW of carbon-free hydropower from Manitoba Hydro, strengthening Midwest grid reliability, enabling wind storage balancing, and advancing Minnesota Power's EnergyForward strategy for cleaner, renewable energy across the region.

Key Points

A 500 kV cross-border line delivering 250 MW of carbon-free hydropower, strengthening reliability and enabling renewables.

✅ 500 kV, 224-mile line from Manitoba to Minnesota

✅ Delivers 250 MW hydropower via ALLETE-Minnesota Power

✅ Enables wind storage and grid balancing with Manitoba Hydro

Minnesota Power, a utility division of ALLETE Inc. (NYSE:ALE), has energized its Great Northern Transmission Line, bringing online an innovative delivery and storage system for renewable energy that spans two states and one Canadian province, similar to the Maritime Link project in Atlantic Canada.

The 500 kV line is now delivering 250 megawatts of carbon-free hydropower from Manitoba, Canada, to Minnesota Power customers.

Minnesota Power completed the Great Northern Transmission Line (GNTL) in February 2020, ahead of schedule and under budget. The 224-mile line runs from the Canadian border in Roseau County to a substation near Grand Rapids, Minnesota. It consists of 800 tower structures which were fabricated in the United States and used 10,000 tons of North American steel. About 2,200 miles of wire were required to install the line's conductors. The GNTL also is contributing significant property tax revenue to local communities along the route.

"This is such an incredible achievement for Minnesota Power, ALLETE, and our region, and is the culmination of a decade-long vision brought to life by our talented and dedicated employees," said ALLETE President and CEO Bethany Owen. "The GNTL will help Minnesota Power to provide our customers with 50 percent renewable energy less than a year from now. As part of our EnergyForward strategy, it also strengthens the grid across the Midwest and in Canada, enhancing reliability for all of our customers."

With the GNTL energized and connected to Manitoba Hydro's recently completed Manitoba-Minnesota Transmission Project at the border, the companies now have a unique "wind storage" mechanism that quickly balances energy supply and demand in Minnesota and Manitoba, and enables a larger role for renewables in the North American energy grid.

The GNTL and its delivery of carbon-free hydropower are important components of Minnesota Power's EnergyForward strategy to transition away from coal and add renewable power sources while maintaining reliable and affordable service for customers, echoing interties like the Maritime Link that facilitate regional power flows. It also is part of a broader ALLETE strategy to advance and invest in critical regional transmission and distribution infrastructure, such as the TransWest Express transmission project, to ensure grid integrity and enable cleaner energy to reduce carbon emissions.

"The seed for this renewable energy initiative was planted in 2008 when Minnesota Power proposed purchasing 250 megawatts of hydropower from Manitoba Hydro. Beyond the transmission line, it also included a creative asset swap to move wind power from North Dakota to Minnesota, innovative power purchase agreements, and a remarkable advocacy process to find an acceptable route for the GNTL," said ALLETE Executive Chairman Al Hodnik. "It marries wind and water in a unique connection that will help transform the energy landscape of North America and reduce carbon emissions related to the existential threat of climate change."

Minnesota Power and Manitoba Hydro, a provincial Crown Corporation, coordinated on the project from the beginning, navigating National Energy Board reviews along the way. It is based on the companies' shared values of integrity, environmental stewardship and community engagement.

"The completion of Minnesota Power's Great Northern Transmission Line and our Manitoba-Minnesota Transmission Project is a testament to the creativity, perseverance, cooperation and skills of hundreds of people over so many years on both sides of the border," said Jay Grewal, president and CEO of Manitoba Hydro. "Perhaps even more importantly, it is a testament to the wonderful, longstanding relationship between our two companies and two countries. It shows just how much we can accomplish when we all work together toward a common goal."

Minnesota Power engaged federal, state and local agencies; the sovereign Red Lake Nation and other tribes, reflecting First Nations involvement in major transmission planning; and landowners along the proposed routes beginning in 2012. Through 75 voluntary meetings and other outreach forums, a preferred route was selected with strong support from stakeholders that was approved by the Minnesota Public Utilities Commission in April 2016.

A four-year state and federal regulatory process culminated in late 2016 when the federal Department of Energy approved a Presidential Permit for the GNTL, similar to the New England Clean Power Link process, needed because of the international border crossing. Construction of the line began in early 2017.

"A robust stakeholder process is essential to the success of any project, but especially when building a project of this scope," Owen said. "We appreciated the early engagement and support from stakeholders, local communities and tribes, agencies and regulators through the many approval milestones to the completion of the GNTL."

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Egypt-Huawei Smart Grid advances Egypt's energy sector with digital transformation, grid modernization, and ICT solutions, enhancing power generation, transmission, and distribution while enabling renewable integration, data analytics, cybersecurity, and scalable infrastructure nationwide.

Key Points

An Egypt-Huawei project to modernize Egypt's grid into a smart network using ICT, analytics, and scalable infrastructure.

✅ Gradual migration to a smart grid to absorb higher load

✅ Boosts generation, transmission, and distribution efficiency

✅ ICT training supports workforce and digital transformation

Egypt and China's tech giant Huawei on Thursday discussed the gradual transformation of Egypt's electricity network to a smart grid model, Egyptian Ministry of Electricity and Renewable Energy said.

Egyptian Minister of Electricity and Renewable Energy Mohamed Shaker met with Huawei's regional president Li Jiguang in Cairo, where they discussed the cooperation, the ministry said in a statement.

The meeting is part of Egypt's plans to develop its energy sector based on the latest technologies and smarter electricity infrastructure initiatives, it added.

During the meeting, Shaker hailed the existing cooperation between Egypt and China in several mega projects, citing regional efforts like the Philippines power grid upgrades, welcoming further cooperation with China to benefit from its expertise and technological progress.

"The future vision of the Egyptian electricity sector is based on the gradual transformation of the current network from a typical one to a smart grid that would help absorb the large amounts of generated power," Shaker said.

Shaker highlighted his ministry's efforts to improve its services, including power generation, transportation and grid improvements across distribution.

Li, president of Huawei Northern Africa Enterprise Business Group, commended the rapid and remarkable development of the projects implemented by the Egyptian ministry to establish a strong infrastructure along with a smart grid that supports the digital grid transformation.

The Huawei official added that despite the challenges the corporation faced in the first half of 2020, it has managed to achieve revenues growth, which shows Huawei's strength and stability amid global challenges such as cybersecurity fears in critical infrastructure.

In late February, Egypt's Ministry of Higher Education and Scientific Research and Huawei discussed plans to provide training to develop the skills of Egyptian university students talented in information and communications technology, including emerging topics like 5G energy use considerations.

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Frisco 100% Renewable Electricity Goal outlines decarbonization via Xcel Energy, wind, solar, and battery storage, enabling beneficial electrification and a smarter grid for 100% municipal power by 2025 and community-wide clean electricity by 2035.

Key Points

Frisco targets 100% renewable electricity: municipal by 2025, community by 2035, via Xcel decarbonization.

✅ Municipal operations to reach 100% renewable electricity by 2025

✅ Community-wide electricity to be 100% carbon-free by 2035

✅ Partnerships: Xcel Energy, wind, solar, storage, grid markets

Frisco has now set a goal of 100-per-cent renewable energy, joining communities on the road to 100% renewables across the country. But unlike some other resolutions adopted in the last decade, this one isn't purely aspirational. It's swimming with a strong current.

With the resolution adopted last week by the town council, Frisco joins 10 other Colorado towns and cities, plus Pueblo and Summit counties, a trend reflected in tracking progress on clean energy targets reports nationwide, in adopting 100-per-cent goals.

The goal is to get the municipality's electricity to 100-per-cent by 2025 and the community altogether by 2035, a timeline aligned with scenarios showing zero-emissions electricity by 2035 is possible in North America.

Decarbonizing electricity will be far easier than transportation, and transportation far easier than buildings. Many see carbon-free electricity as being crucial to both, a concept called "beneficial electrification," and point to ways to meet decarbonization goals that leverage electrified end uses.

Electricity for Frisco comes from Xcel Energy, an investor-owned utility that is making giant steps toward decarbonizing its power supply.

Xcel first announced plans to close its work-horse power plants early to take advantage of now-cheap wind and solar resources plus what will be the largest battery storage project east of the Rocky Mountains. All this will be accomplished by 2026 and will put Xcel at 55 per cent renewable generation in Colorado.

In December, a week after Frisco launched the process that produced the resolution, Xcel announced further steps, an 80 percent reduction in carbon dioxide emissions by 2030 as compared to 2050 levels. By 2050, the company vows to be 100 per cent "carbon-free" energy by 2050.

Frisco's non-binding goals were triggered by Fran Long, who is retired and living in Frisco. For eight years, though, he worked for Xcel in helping shape its response to the declining prices of renewables. In his retirement, he has also helped put together the aspirational goal adopted by Breckenridge for 100-per-cent renewables.

A task force that Long led identified a three-pronged approach. First, the city government must lead by example. The resolution calls for the town to spend $25,000 to $50,000 annually during the next several years to improve energy efficiency in its municipal facilities. Then, through an Xcel program called Renewable Connect, it can pay an added cost to allow it to say it uses 100-per-cent electricity from renewable sources.

Beyond that, Frisco wants to work with high-end businesses to encourage buying output from solar gardens or other devices that will allow them to proclaim 100-per-cent renewable energy. The task force also recommends a marketing program directed to homes and smaller businesses.

Goals of 100-per-cent renewable electricity are problematic, given why the grid isn't 100% renewable today for technical and economic reasons. Aspen Electric, which provides electricity for about two-thirds of the town, by 2015 had secured enough wind and hydro, mostly from distant locations, to allow it to proclaim 100 per cent renewables.

In fact, some of those electrons in Aspen almost certainly originate in coal or gas plants. That doesn't make Aspen's claim wrong. But the fact remains that nobody has figured out how, at least at affordable cost, to deliver 100-per-cent clean energy on a broad basis.

Xcel Energy, which supplies more than 60 per cent of electricity in Colorado, one of six states in which it operates, has a taller challenge. But it is a very different utility than it was in 2004, when it spent heavily in advertising to oppose a mandate that it would have to achieve 10 per cent of its electricity from renewable sources by 2020.

Once it lost the election, though, Xcel set out to comply. Integrating renewables proved far more easily than was feared. It has more than doubled the original mandate for 2020. Wind delivers 82 per cent of that generation, with another 18 per cent coming from community, rooftop, and utility-scale solar.

The company has become steadily more proficient at juggling different intermittent power supplies while ensuring lights and computers remain on. This is partly the result of practice but also of relatively minor technological wrinkles, such as improved weather forecasting, according to an Energy News Network story published in March.

For example, a Boulder company, Global Weather corporation, projects wind—and hence electrical production—from turbines for 10 days ahead. It updates its forecasts every 15 minutes.

Forecasts have become so good, said John T. Welch, director of power operations for Xcel in Colorado, that the utility uses 95 per cent to 98 per cent of the electricity generated by turbines. This has allowed the company to use its coal and natural gas plants less.M

Moreover, prices of wind and then solar declined slowly at first and then dramatically.

Xcel is now comfortable that existing technology will allow it to push from 55 per cent renewables in 2026 to an 80 per cent carbon reduction goal by 2030.

But when announcing their goal of emissions-free energy by mid-century in December, the company's Minneapolis-based chief executive, Ben Fowke, and Alice Jackson, the chief executive of the company's Colorado subsidiary, freely admitted they had no idea how they will achieve it. "I have a lot of confidence they will be developed," Fowke said of new technologies.

Everything is on the table, they said, including nuclear. But also including fossil fuels, if the carbon dioxide can be sequestered. So far, such technology has proven prohibitively expensive despite billions of dollars in federal support for research and deployment. They suggested it might involve new technology.

Xcel's Welch told Energy News Network that he believes solar must play a larger role, and he believes solar forecasting must improve.

Storage technology must also improve as batteries are transforming solar economics across markets. Batteries, such as produced by Tesla at its Gigafactory near Reno, can store electricity for hours, maybe even a few days. But batteries that can store large amounts of electricity for months will be needed in Colorado. Wind is plentiful in spring but not so much in summer, when air conditioners crank up.

Increased sharing of cheap renewable generation among utilities will also allow deeper penetration of carbon-free energy, a dynamic consistent with studies finding wind and solar could meet 80% of demand with improved transmission. Western US states and Canadian provinces are all on one grid, but the different parts are Balkanized. In other words, California is largely its own energy balancing authority, ensuring electricity supplies match electricity demands. Ditto for Colorado. The Pacific Northwest has its own balancing authority.

If they were all orchestrated as one in an expanded energy market across the West, however, electricity supplies and demands could more easily be matched. California's surplus of solar on summer afternoons, for example, might be moved to Colorado.

Colorado legislators in early May adopted a bill that requires the state's Public Utilities Commission to begin study by late this year of an energy imbalance market or regional transmission organization.

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AI-Powered Utility Customer Experience enables transparency, real-time pricing, smart thermostats, demand response, and billing optimization, helping utilities integrate distributed energy resources, battery storage, and microgrids while boosting customer satisfaction and reducing costs.

Key Points

An approach where utilities use AI and real-time data to personalize service, optimize billing, and cut energy costs.

✅ Real-time pricing aligns retail and wholesale market signals

✅ Device control via smart thermostats and home energy management

✅ Analytics reveal appliance-level usage and personalized savings

The latest electric utility customer satisfaction survey results from the American Customer Satisfaction Index (ACSI) Energy Utilities report reveal that nearly every investor-owned utility saw customer satisfaction go down from 2018 to 2019. Residential customers are sending a clear message in the report: They want more transparency and control over energy usage, billing and ways to reduce costs.

With both customer satisfaction and utility revenues on the decline, utilities are facing daunting challenges to their traditional business models amid flat electricity demand across many markets today. That said, it is the utilities that see these changing times as an opportunity to evolve that will become the energy leaders of tomorrow, where the customer relationship is no longer defined by sales volume but instead by a utility company's ability to optimize service and deliver meaningful customer solutions.

We have seen how the proliferation of centralized and distributed renewables on the grid has already dramatically changed the cost profile of traditional generation and variability of wholesale energy prices. This signals the real cost drivers in the future will come from optimizing energy service with things like batteries, microgrids and peer-to-peer trading networks. In the foreseeable future, flat electricity rates may be the norm, or electricity might even become entirely free as services become the primary source of utility revenue.

The key to this future is technological innovation that allows utilities to better understand a customer’s unique needs and priorities and then deliver personalized, well-timed solutions that make customers feel valued and appreciated as their utility helps them save and alleviates their greatest pain points.

I predict utilities that adopt new technologies focused on customer experience, aligned with key utility trends shaping the sector, and deliver continual service improvements and optimization will earn the most satisfied, most loyal customers.

To illustrate this, look at how fixed pricing today is applied for most residential customers. Unless you live in one of the states with deregulated utilities where most customers are free to choose a service provider in a competitive marketplace, as consumers in power markets increasingly reshape offerings, fixed-rate tariffs or time-of-use tariffs might be the only rate structures you have ever known, though new utility rate designs are being tested nationwide today. These tariffs are often market distortions, bearing little relation to the real-time price that the utility pays on the wholesale market.

It can be easy enough to compare the rate you pay as a consumer and the market rate that utilities pay. The California ISO has a public dashboard -- as do other grid operators -- that shows the real-time marginal cost of energy. On a recent Friday, for example, a buyer in San Francisco could go to the real-time market and procure electricity at a rate of around 9.5 cents per kilowatt-hour (kWh), yet a residential customer can pay the utility PG&E between 22 cents and 49 cents per kWh amid major changes to electric bills being debated, depending on usage.

The problem is that utility customers do not usually see this data or know how to interpret it in a way that helps add value to their service or drive down the cost.

This is a scenario ripe for innovation. Artificial intelligence (AI) technologies are beginning to be applied to give customers the transparency and control over the energy they desire, and a new type of utility is emerging using real-time pricing signals from wholesale markets to give households hassle-free energy savings. Evolve Energy in Texas is developing a utility service model, even as Texas utilities revisit smart home network strategies, that delivers electricity to consumers at real-time market prices and connects to smart thermostats and other connected devices in the home for simple monitoring and control -- all managed via an intuitive consumer app.

My company, Bidgely, partners with utilities and energy retailers all over the world to apply artificial intelligence and machine learning algorithms to customer data in order to bring transparency to their electricity bills, showing exactly where the customers’ money is going down to the appliance and offering personalized, actionable advice on how to save.

Another example is from energy management company Keewi. Its wireless outlet adaptors are revealing real-time energy usage information to Texas A&M dorm residents as well as providing students the ability to conserve energy through controlling items in their rooms from their smartphones.

These are but a few examples of innovations among many in play that answer the consumer demand for increased transparency and control over energy usage.

Electric service providers will be closely watching how consumers respond to AI-driven innovation, including providers in traditionally regulated markets that are exploring equitable regulation approaches now, to stay aligned with policy and customer expectations. While regulated utilities have no reason to fear that their customers might sign up with a competitor, they understand that the revenues from electricity sales are going down and the deployment of distributed energy resources is going up. Both trends were reflected in a March report from Bloomberg New Energy Finance (via ThinkProgress) that claimed unsubsidized storage projects co-located with solar or wind are starting to compete with coal and gas for dispatchable power. Change is coming to regulated markets, and some of that change can be attributed to customer dissatisfaction with utility service.

Like so many industries before, the utility-customer relationship is on track to become less about measuring unit sales and more about driving revenue through services and delivering the best customer value. Loyal customers are most likely to listen and follow through on the utility’s advice and to trust the utility for a wide range of energy-related products and services. Utilities that make customer experience the highest priority today will emerge tomorrow as the leaders of a new energy service era.

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Idaho Renewable Energy 2018 saw over 80% in-state utility-scale power from hydropower, wind, solar, biomass, and geothermal, per EIA, with imports declining as Snake River Plain resources and Hells Canyon hydro lead.

Key Points

Idaho produced over 80% in-state power from renewables in 2018, led by hydropower, wind, solar, and biomass.

✅ Hydropower supplies about half of capacity; Hells Canyon leads.

✅ Wind provides nearly 20% of capacity along the Snake River Plain.

✅ Utility-scale solar surged since 2016; biomass and geothermal add output.

More than 80% of Idaho’s in-state utility-scale electricity generation came from renewable resources in 2018, behind only Vermont, according to recently released data from the U.S. Energy Information Administration’s Electric Power Monthly and broader trends showing that solar and wind reached about 10% of U.S. generation in the first half of 2018.

Idaho generated 17.4 million MWh of electricity in 2018, of which 14.2 million MWh came from renewable sources, while nationally January power generation jumped 9.3% year over year according to EIA. Idaho uses a variety of renewable resources to generate electricity:

Hydroelectricity. Idaho ranked seventh in the U.S. in electricity generation from hydropower in 2018. About half of Idaho’s electricity generating capacity is at hydroelectric power plants, and utility actions such as the Idaho Power settlement could influence future resource choices, and seven of the state’s 10 largest power plants (in terms of electricity generation) are hydroelectric facilities. The largest privately owned hydroelectric generating facility in the U.S. is a three-dam complex on the Snake River in Hells Canyon, the deepest river gorge in North America.

Wind. Nearly one-fifth of Idaho’s electricity generating capacity and one-sixth of its generation comes from wind turbines. Idaho has substantial wind energy potential, and nationally the EIA expects solar and wind to be larger sources this summer, although only a small percentage of the state's land area is well-suited for wind development. All of the state’s wind farms are located in the southern half of the state along the Snake River Plain.

Solar. Almost 5% of Idaho’s electricity generating capacity and 3% of its generation come from utility-scale solar facilities, and nationally over half of new capacity in 2023 will be solar according to projections. The state had no utility-scale solar generation as recently as 2015. Between 2016 and 2017, Idaho’s utility-scale capacity doubled and generation increased from 30,000 MWh to more than 450,000 MWh. Idaho’s small-scale solar capacity also doubled since 2017, generating 33,000 MWh in 2018.

Biomass. Biomass-fueled power plants account for about 2% of the state’s utility-scale electricity generating capacity and 3% of its generation, contributing to a broader U.S. shift where 40% of electricity came from non-fossil sources in 2021. Wood waste from the state’s forests is the primary fuel for these plants.

Geothermal. Idaho is one of seven states with utility-scale geothermal electricity generation. Idaho has one 18-MW geothermal facility, located near the state’s southern border with Utah.

EIA says Idaho requires significant electricity imports, totaling about one-third of demand, to meet its electricity needs. However, Idaho’s electricity imports have decreased over time, and Georgia's recent import levels illustrate how regional dynamics can vary. Almost all of these imports are from neighboring states, as electricity imports from Canada accounted for less than 0.1% of Idaho’s total electricity supply in 2017.

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EU Power Market Overhaul targets soaring electricity prices by decoupling gas from power, boosting renewables, refining price caps, and stabilizing grids amid inflation, supply shocks, droughts, nuclear outages, and intermittent wind and solar.

Key Points

EU plan to redesign electricity pricing, curb gas-driven costs, boost renewables, and protect consumers from volatility.

✅ Decouples power prices from marginal gas generation

✅ Caps non-gas revenues to fund consumer relief

✅ Supports grid stability with storage, demand response, LNG

While energy prices are soaring around the world, Europe is in a particularly tight spot. Its heavy dependence on Russian gas -- on top of droughts, heat waves, an unreliable fleet of French nuclear reactors and a continent-wide shift to greener but more intermittent sources like solar and wind -- has been driving electricity bills up and feeding the highest inflation in decades. As Europe stands on the brink of a recession, and with the winter heating season approaching, officials are considering a major overhaul of the region’s power market to reflect the ongoing shift from fossil fuels to renewables.

1. How is electricity priced? 
Unlike oil or natural gas, there’s no efficient way to save lots of electricity to use in the future, though projects to store electricity in gas pipes are emerging. Commercial use of large-scale batteries is still years away. So power prices have been set by the availability at any given moment. When it’s really windy or sunny, for example, then more is produced relatively cheaply and prices are lower. If that supply shrinks, then prices rise because more generators are brought online to help meet demand -- fueled by more expensive sources. The way the market has long worked is that it is that final technology, or type of plant, needed to meet the last unit of consumption that sets the price for everyone. In Europe this year, that has usually meant natural gas. 

2. What is the relationship between power and gas? 
Very close. Across western Europe, gas plants have been a vital part of the energy infrastructure for decades, with Irish price spikes highlighting dispatchable power risks, fed in large part by supplies piped in from Siberia. Gas-fired plants were relatively quick to build and the technology straightforward, at least compared with nuclear plants and burns cleaner than coal. About 18% of Europe’s electricity was generated at gas plants last year; in 2020 about 43% of the imported gas came from Russia. Even during the depths of the Cold War, there’d never been a serious supply problem -- until the relationship with Russia deteriorated this year after it invaded Ukraine. Diversifying away from Russia, such as by increasing imports of liquefied natural gas, requires new infrastructure that takes a lot of time and money.

3. Why does it work this way? 
In theory, the relationship isn’t different from that with coal, for example. But production hiccups and heatwave curbs on plants from nuclear in France to hydro in Spain and Norway significantly changed the generation picture this year, and power hit records as plants buckled in the heat. Since coal-fired and nuclear plants are generally running all the time anyway, gas plants were being called upon more often -- at times just to keep the lights on as summer temperatures hit records. And with the war in Ukraine resulting in record gas prices, that pushed up overall production costs. It’s that relationship that has made the surging gas price the driver for electricity prices. And since the continent is all connected, it has pushed up prices across the region. The value of the European power market jumped threefold last year, to a record 836 billion euros ($827 billion today).

4. What’s being considered? 
With large parts of European industry on its knees and households facing jumps in energy bills of several hundred percent, as record electricity prices ripple through markets, the pressure on governments and the European Union to intervene has never been higher. One major proposal is to impose a price cap on electricity from non-gas producers, with the difference between that and the market price channeled to relief for consumers. While it sounds simple, any such changes would rip up a market design that’s worked for decades and could threaten future investments because of unintended consequences.

5. How did this market evolve?
The Nordic region and the British market were front-runners in the 1990s, then Germany followed and is now the largest by far. A trader can buy and sell electricity delivered later on same day in blocks of an hour or even down to 15-minute periods, to meet sudden demand or take advantage of price differentials. The price for these contracts is decided entirely by the supply and demand, how much the wind is blowing or which coal plants are operating, for example. Demand tends to surge early in the morning and late afternoon. This system was designed when fossil fuels provided the bulk of power. Now there are more renewables, which are less predictable, with wind and solar surpassing gas in EU generation last year, and the proposed changes reflect that shift. 

6. What else have governments done?
There are also traders who focus on longer-dated contracts covering periods several years ahead, where broader factors such as expected economic output and the extent to which renewables are crowding out gas help drive prices. This year’s wild price swings have prompted countries including Germany, Sweden and Finland to earmark billions of euros in emergency liquidity loans to backstop utilities hit with sudden margin calls on their trading.

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