Combining the electric grids operated by PacifiCorp and the California Independent System Operator to create a regional power marketplace could reduce energy costs by billions of dollars and help states meet their environmental goals, including CaliforniaÂ’s 50 percent renewable energy mark, according to a study released recently.
The study, commissioned by PacifiCorp and conducted by Energy and Environmental Economics E3, finds that integrating the two largest high-voltage transmission grids in the West to create a regional ISO could produce between $3.4 billion and $9.1 billion in shared cost reductions in the first 20 years through better grid management and efficiencies gained by planning for the resource needs of a single, rather than multiple systems.
The study also projects that development of a regional ISO is likely to reduce greenhouse gas emissions through coordinated planning, reduced curtailment of renewable energy, and lower overall costs to build new renewable resources.
"The study clearly highlights the benefits of a regional grid for all customers,” said Steve Berberich, President and CEO of the ISO. “It shows that a regional grid creates the opportunity to integrate higher levels of renewables more efficiently and effectively across a more diverse area. This regional approach is foundational to support the historic California SB 350 legislation and carbon reduction goals of nearby states.”
Agreement extended to look at costs, next steps. PacifiCorp and the ISO signed a Memorandum of Understanding in April to examine the potential benefits of creating a regional ISO, which included commissioning the benefits study recently released. The parties have extended the MOU to further explore costs and other requirements needed to achieve the benefits of integration outlined in the study, as well as to develop a transition agreement to outline the terms and conditions for the potential integration of PacifiCorp into a regional market.
“The report demonstrates clearly that a true regional grid in the West could provide significant benefits for customers,” said Cindy Crane, President and CEO of Rocky Mountain Power, a unit of PacifiCorp serving customers in Utah, Idaho and Wyoming. “We will continue to coordinate with stakeholders and regulators to ensure that moving forward is in the best interest of customers and our states.”
Both PacifiCorp and the ISO will receive input from regulators and stakeholders, and will need regulatory approval before full integration could occur. In addition, work will begin on establishing a new governance structure for a regional market as outlined in recently signed California legislation Senate Bill 350. Following market design and simulation tests, full integration could occur in late 2018 or in 2019.
Potential benefits. The study shows how creation of a regional ISO would benefit customers of both PacifiCorp and the ISO. PacifiCorpÂ’s customers, for instance, would benefit primarily from savings in fuel and energy procurement costs, while ISO wholesale customer savings would come from procuring lower cost clean energy and mitigating the negative impacts of oversupply of renewable energy on the system.
Annual gross cost savings in 2024 for PacifiCorp and ISO customers could range from $153 million to $355 million, increasing to $402 million to $1.2 billion in annual savings in 2030.
“Over the first full 20 years, assumed here to be 2020 to 2039, we estimate the PacifiCorp and ISO integration would yield $1.6 to $2.3 billion in total present value incremental savings for PacifiCorp, and $1.8 to $6.8 billion for ISO customers,” according to the study.
“The quantified benefits for both PacifiCorp and ISO customers are sufficient to support continued progress toward PacifiCorp and ISO integration,” the report concluded.
In response to the California Independent System Operator's announcement that western grid integration could produce significant cost savings, environmental benefits, the President of the California Public Utilities Commission, Michael Picker, issued this statement:
“The benefits look promising and underscore the value of moving to a more diverse mix of renewable resources for meeting California’s 50 percent renewable generation goal. I look forward to seeing the additional work being done to address environmental and job issues as well as how costs will be fairly allocated across a larger region.”
Smart EV Charging orchestrates vehicle-to-grid (V2G), demand response, and fast charging to balance the power grid, integrating renewables, electrolyzers for hydrogen, and megawatt chargers for fleets with advanced control and co-optimization.
Key Points
Smart EV charging coordinates EV load to stabilize the grid, cut peaks, and integrate renewable energy efficiently.
✅ Reduces peak demand via coordinated, flexible load control
✅ Enables V2G services with renewables and battery storage
✅ Supports megawatt fast charging for heavy-duty fleets
As electric vehicle (EV) sales continue to rev up in the United States, the power grid is in parallel contending with the greatest transformation in its 100-year history: the large-scale integration of renewable energy and power electronic devices. The expected expansion of EVs will shift those challenges into high gear, causing cities to face gigawatt-growth in electricity demand, as analyses of EV grid impacts indicate, and higher amounts of variable energy.
Coordinating large numbers of EVs with the power system presents a highly complex challenge. EVs introduce variable electrical loads that are highly dependent on customer behavior. Electrified transportation involves co-optimization with other energy systems, like natural gas and bulk battery storage, including mobile energy storage flexibility for new operational options. It could involve fleets of automated ride-hailing EVs and lead to hybrid-energy truck stops that provide hydrogen and fast-charging to heavy-duty vehicles.
Those changes will all test the limits of grid integration, but the National Renewable Energy Laboratory (NREL) sees opportunity at the intersection of energy systems and transportation. With powerful resources for simulating and evaluating complex systems, several NREL projects are determining the coordination required for fast charging, balancing electrical supply and demand, and efficient use of all energy assets.
Smart and Not-So-Smart Control To appreciate the value of coordinated EV charging, it is helpful to imagine the opposite scenario.
"Our first question is how much benefit or burden the super simple, uncoordinated approach to electric vehicle charging offers the grid," said Andrew Meintz, the researcher leading NREL's Electric Vehicle Grid Integration team, as well as the RECHARGE project for smart EV charging. "Then we compare that to the 'whiz-bang,' everything-is-connected approach. We want to know the difference in value."
In the "super simple" approach, Meintz explained that battery-powered electric vehicles grow in market share, exemplified by mass-market EVs, without any evolution in vehicle charging coordination. Picture every employee at your workplace driving home at 5 p.m. and charging their vehicle. That is the grid's equivalent of going 0 to 100 mph, and if it does not wreck the system, it is at least very expensive. According to NREL's Electrification Futures Study, a comprehensive analysis of the impacts of widespread electrification across all U.S. economic sectors, in 2050 EVs could contribute to a 33% increase in energy use during peak electrical demand, underscoring state grid challenges that make these intervals costly when energy reserves are procured. In duck curve parlance, EVs will further strain the duck's neck.
The Optimization and Control Lab's Electric Vehicle Grid Integration bays allow researchers to determine how advanced high power chargers can be added safely and effectively to the grid, with the potential to explore how to combine buildings and EV charging. Credit: Dennis Schroeder, NREL Meintz's "whiz-bang" approach instead imagines EV control strategies that are deliberate and serve to smooth, rather than intensify, the upcoming demand for electricity. It means managing both when and where vehicles charge to create flexible load on the grid.
At NREL, smart strategies to dispatch vehicles for optimal charging are being developed for both the grid edge, where consumers and energy users connect to the grid, as in RECHARGEPDF, and the entire distribution system, as in the GEMINI-XFC projectPDF. Both projects, funded by the U.S. Department of Energy's (DOE's) Vehicle Technologies Office, lean on advanced capabilities at NREL's Energy Systems Integration Facility to simulate future energy systems.
At the grid edge, EVs can be co-optimized with distributed energy resources—small-scale generation or storage technologies—the subject of a partnership with Eaton that brought industry perspectives to bear on coordinated management of EV fleets.
At the larger-system level, the GEMINI-XFC project has extended EV optimization scenarios to the city scale—the San Francisco Bay Area, to be specific.
"GEMINI-XFC involves the highest-ever-fidelity modeling of transportation and the grid," said NREL Research Manager of Grid-Connected Energy Systems Bryan Palmintier.
"We're combining future transportation scenarios with a large metro area co-simulationPDF—millions of simulated customers and a realistic distribution system model—to find the best approaches to vehicles helping the grid."
GEMINI-XFC and RECHARGE can foresee future electrification scenarios and then insert controls that reduce grid congestion or offset peak demand, for example. Charging EVs involves a sort of shell game, where loads are continually moved among charging stations to accommodate grid demand.
But for heavy-duty vehicles, the load is harder to hide. Electrified truck fleets will hit the road soon, creating power needs for electric truck fleets that translate to megawatts of localized demand. No amount of rerouting can avoid the requirements of charging heavy-duty vehicles or other instances of extreme fast-charging (XFC). To address this challenge, NREL is working with industry and other national laboratories to study and demonstrate the technological buildout necessary to achieve 1+ MW charging stationsPDF that are capable of fast charging at very high energy levels for medium- and heavy-duty vehicles.
To reach such a scale, NREL is also considering new power conversion hardware based on advanced materials like wide-bandgap semiconductors, as well as new controllers and algorithms that are uniquely suited for fleets of charge-hungry vehicles. The challenge to integrate 1+ MW charging is also pushing NREL research to higher power: Upcoming capabilities will look at many-megawatt systems that tie in the support of other energy sectors.
Renewable In-Roads for Hydrogen
At NREL, the drive toward larger charging demands is being met with larger research capabilities. The announcement of ARIES opens the door to energy systems integration research at a scale 10-times greater than current capabilities: 20 MW, up from 2 MW. Critically, it presents an opportunity to understand how mobility with high energy demands can be co-optimized with other utility-scale assets to benefit grid stability.
"If you've got a grid humming along with a steady load, then a truck requires 500 kW or more of power, it could create a large disruption for the grid," said Keith Wipke, the laboratory program manager for fuel cells and hydrogen technologies at NREL.
Such a high power demand could be partially served by battery storage systems. Or it could be hidden entirely with hydrogen production. Wipke's program, with support from the DOE's Hydrogen and Fuel Cell Technologies Office, has been performing studies into how electrolyzers—devices that use electricity to break water into hydrogen and oxygen—could offset the grid impacts of XFC. These efforts are also closely aligned with DOE's H2@Scale vision for affordable and effective hydrogen use across multiple sectors, including heavy-duty transportation, power generation, and metals manufacturing, among others.
"We're simulating electrolyzers that can match the charging load of heavy-duty battery electric vehicles. When fast charging begins, the electrolyzers are ramped down. When fast charging ends, the electrolyzers are ramped back up," Wipke said. "If done smoothly, the utility doesn't even know it's happening."
NREL Researchers Rishabh Jain, Kazunori Nagasawa, and Jen Kurtz are working on how grid integration of electrolyzers—devices that use electricity to break water into hydrogen and oxygen—could offset the grid impacts of extreme fast-charging. Credit: National Renewable Energy Laboratory As electrolyzers harness the cheap electrons from off-demand periods, a significant amount of hydrogen can be produced on site. That creates a natural energy pathway from discount electricity into a fuel. It is no wonder, then, that several well-known transportation and fuel companies have recently initiated a multimillion-dollar partnership with NREL to advance heavy-duty hydrogen vehicle technologies.
"The logistics of expanding electric charging infrastructure from 50 kW for a single demonstration battery electric truck to 5,000 kW for a fleet of 100 could present challenges," Wipke said. "Hydrogen scales very nicely; you're basically bringing hydrogen to a fueling station or producing it on site, but either way the hydrogen fueling events are decoupled in time from hydrogen production, providing benefits to the grid."
The long driving range and fast refuel times—including a DOE target of achieving 10-minutes refuel for a truck—have already made hydrogen the standout solution for applications in warehouse forklifts. Further, NREL is finding that distributed electrolyzers can simultaneously produce hydrogen and improve voltage conditions, which can add much-needed stability to a grid that is accommodating more energy from variable resources.
Those examples that co-optimize mobility with the grid, using diverse technologies, are encouraging NREL and its partners to pursue a new scale of systems integration. Several forward-thinking projects are reimagining urban mobility as a mix of energy solutions that integrate the relative strengths of transportation technologies, which complement each other to fill important gaps in grid reliability.
The Future of Urban Mobility What will electrified transportation look like at high penetrations? A few NREL projects offer some perspective. Among the most experimental, NREL is helping the city of Denver develop a smart community, integrated with electrified mobility and featuring automated charging and vehicle dispatch.
On another path to advanced mobility, Los Angeles has embarked on a plan to modernize its electricity system infrastructure, reflecting California EV grid stability goals—aiming for a 100% renewable energy supply by 2045, along with aggressive electrification targets for buildings and vehicles. Through the Los Angeles 100% Renewable Energy Study, the city is currently working with NREL to assess the full-scale impacts of the transition in a detailed analysis that integrates diverse capabilities across the laboratory.
The transition would include the Port of Long Beach, the busiest container port in the United States.
At the port, NREL is applying the same sort of scenario forecasting and controls evaluation as other projects, in order to find the optimal mix of technologies that can be integrated for both grid stability and a reliable quality of service: a mix of hydrogen fuel-cell and battery EVs, battery storage systems, on-site renewable generation, and extreme coordination among everything.
"Hydrogen at ports makes sense for the same reason as trucks: Marine applications have big power and energy demands," Wipke said. "But it's really the synergies between diverse technologies—the existing infrastructure for EVs and the flexibility of bulk battery systems—that will truly make the transition to high renewable energy possible."
Like the Port of Long Beach, transportation hubs across the nation are adapting to a complex environment of new mobility solutions. Airports and public transit stations involve the movement of passengers, goods, and services at a volume exceeding anywhere else. With the transition to digitally connected electric mobility changing how airports plan for the future, NREL projects such as Athena are using the power of high-performance computing to demonstrate how these hubs can maximize the value of passenger and freight mobility per unit of energy, time, and/or cost.
The growth in complexity for transportation hubs has just begun, however. Looking ahead, fleets of ride-sharing EVs, automated vehicles, and automated ride-sharing EV fleets could present the largest effort to manage mobility yet.
A Self-Driving Power Grid To understand the full impact of future mobility-service providers, NREL developed the HIVE (Highly Integrated Vehicle Ecosystem) simulation framework. HIVE combines factors related to serving mobility needs and grid operations—such as a customer's willingness to carpool or delay travel, and potentially time-variable costs of recharging—and simulates the outcome in an integrated environment.
"Our question is, how do you optimize the management of a fleet whose primary purpose is to provide rides and improve that fleet's dispatch and charging?" said Eric Wood, an NREL vehicle systems engineer.
HIVE was developed as part of NREL's Autonomous Energy Systems research to optimize the control of automated vehicle fleets. That is, optimized routing and dispatch of automated electric vehicles.
The project imagines how price signals could influence dispatch algorithms. Consider one customer booking a commute through a ride-hailing app. Out of the fleet of vehicles nearby—variously charged and continually changing locations—which one should pick up the customer?
Now consider the movements of thousands of passengers in a city and thousands of vehicles providing transportation services. Among the number of agents, the moment-to-moment change in energy supply and demand, and the broad diversity in vendor technologies, "we're playing with a lot of parameters," Wood said.
But cutting through all the complexity, and in the midst of massive simulations, the end goal for vehicle-to-grid integration is consistent:
"The motivation for our work is that there are forecasts for significant load on the grid from the electrification of transportation," Wood said. "We want to ensure that this load is safely and effectively integrated, while meeting the expectations and needs of passengers."
The Port of Long Beach uses a mix of hydrogen fuel-cell and battery EVs, battery storage systems, on-site renewable generation, and extreme coordination among everything. Credit: National Renewable Energy Laboratory True Replacement without Caveats
Electric vehicles are not necessarily helpful to the grid, but they can be. As EVs become established in the transportation sector, NREL is studying how to even out any bumps that electrified mobility could cause on the grid and advance any benefits to commuters or industry.
"It all comes down to load flexibility," Meintz said. "We're trying to decide how to optimally dispatch vehicle charging to meet quality-of-service considerations, while also minimizing charging costs."
Toronto Electricity Demand Growth underscores IESO projections of rising peak load by 2050, driven by population growth, electrification, new housing density, and tech economy, requiring grid modernization, transmission upgrades, demand response, and local renewable energy.
Key Points
It refers to the projected near-doubling of Toronto's peak load by 2050, driven by electrification and urban growth.
✅ IESO projects peak demand nearly doubling by 2050
Toronto faces a significant challenge in meeting the growing electricity needs of its expanding population and ambitious development plans. According to a new report from Ontario's Independent Electricity System Operator (IESO), Toronto's peak electricity demand is expected to nearly double by 2050. This highlights the need for proactive steps to secure adequate electricity supply amidst the city's ongoing economic and population growth.
Key Factors Driving Demand
Several factors are contributing to the projected increase in electricity demand:
Population Growth: Toronto is one of the fastest-growing cities in North America, and this trend is expected to continue. More residents mean more need for housing, businesses, and other electricity-consuming infrastructure.
New Homes and Density: The city's housing strategy calls for 285,000 new homes within the next decade, including significant densification in existing neighbourhoods. High-rise buildings in urban centers are generally more energy-intensive than low-rise residential developments.
Economic Development: Toronto's robust economy, a hub for tech and innovation, attracts new businesses, including energy-intensive AI data centers that fuel further demand for electricity.
Electrification: The push to reduce carbon emissions is driving the electrification of transportation and home heating, further increasing pressure on Toronto's electricity grid.
Planning for the Future
Ontario and the City of Toronto recognize the urgency to secure stable and reliable electricity supplies to support continued growth and prosperity without sacrificing affordability, drawing lessons from British Columbia's clean energy shift to inform local approaches. Officials are collaborating to develop a long-term plan that focuses on:
Energy Efficiency: Efforts aim to reduce wasteful electricity usage through upgrades to existing buildings, promoting energy-efficient appliances, and implementing smart grid technologies. These will play a crucial role in curbing overall demand.
New Infrastructure: Significant investments in building new electricity generation, transmission lines, and substations, as well as regional macrogrids to enhance reliability, will be necessary to meet the projected demands of Toronto's future.
Demand Management: Programs incentivizing energy conservation during peak hours will help to avoid strain on the grid and reduce the need to build expensive power plants only used at peak demand times.
Challenges Ahead
The path ahead isn't without its hurdles. Building new power infrastructure in a dense urban environment like Toronto can be time-consuming, expensive, and sometimes disruptive, especially as grids face harsh weather risks that complicate construction and operations. Residents and businesses might worry about potential rate increases required to fund these necessary investments.
Opportunity for Innovation
The IESO and the city view the situation as an opportunity to embrace innovative solutions. Exploring renewable energy sources within and near the city, developing local energy storage systems, and promoting distributed energy generation such as rooftop solar, where power is created near the point of use, are all vital strategies for meeting needs in a sustainable way.
Toronto's electricity future depends heavily on proactive planning and investment in modernizing its power infrastructure. The decisions made now will determine whether the city can support economic growth, address climate goals and a net-zero grid by 2050 ambition, and ensure that lights stay on for all Torontonians as the city continues to expand.
Nunavut electricity rate increase sees QEC raise domestic electricity rates 6.6% over two years, affecting customer rates, base rates, subsidies, and kWh overage charges across communities, with public housing exempt and territory-wide pricing denied.
Key Points
A 6.6% QEC hike over 2018-2019, affecting customer rates, subsidies, and kWh overage; public housing remains exempt.
✅ Territory-wide base rate denied; public housing exempt
Ahead of the Nunavut government's approval of the general rate increase for the Qulliq Energy Corporation, many Nunavummiut wondered how the change would impact their electricity bills.
QEC's request for a 6.6-per-cent increase was approved by the government last week. The increase will be spread out over two years, a pattern similar to BC Hydro's two-year rate plan, with the first increase (3.3 per cent) effective May 1, 2018. The remaining 3.3 per cent will be applied on April 1, 2019.
Public housing units, however, are exempt from the government's increase altogether.
The power corporation also asked for a territory-wide rate, so every community would pay the same base rate (we'll go over specific terms in a minute if you're not familiar with them). But that request was denied, even as Manitoba Hydro scaled back increases next year, and QEC will now take the next two years reassessing each community's base rate.
#google#
So, what does this mean for your home's power bill? Well, there's a few things you need to know, which we'll get to in a second.
But in essence, as long as you don't go over the government-subsidized monthly electricity usage limit, you're paying an extra 3.61 cents per kilowatt hour (kWh).
To be clear, we're talking about non-government domestic rates — basically, private homeowners — and those living in a government-owned unit but pay for their own power.
The basics
First, some quick terminology. The "base rate" term we're going to use (and used above) in this story refers to the community rate. As in, what QEC charges customers in every community. The "customer rate" is the rate customers actually pay, after the government's subsidy.
The first thing you need to know is everyone in Nunavut starts off by paying the same customer rate, unlike jurisdictions using a price cap to limit spikes.
That's because the government subsidizes electricity costs, and that subsidy is different in every community, because the base rate is different.
For example, Iqaluit's new base rate after the 3.3 per cent increase (remember, the 6.6 per cent is being applied over two years) is 56.69 cents per kWh, while Kugaaruk's base rate rose to 112.34 cents per kWh. Those, by the way, are the territory's lowest and highest respective base rates.
However, customers in both Iqaluit and Kugaaruk will each now pay 28.35 cents per kWh because, remember, the government subsidizes the base rates in every community.
Now, remember earlier we mentioned a "government-subsidized monthly electricity usage limit?" That's where customers in various communities start to pay different amounts.
As simply as we can explain it, the government will only cover so much electricity usage in a month, in every household.
Between October and March, the government will subsidize the first 1,000 kilowatt hours, and only 700 kilowatt hours from April to September. QEC says the average Nunavut home will use about 500 kilowatt hours every month over the course of a year.
But if your household goes over that limit, you're at the mercy of your community's base rate for any extra electricity you use. Homes in Kugaaruk in December, for instance, will have to pay that 122.34 cents for every extra kilowatt hour it uses, while homes in Iqaluit only have to pay 56.69 cents per kWh for its extra electricity.
That's where many Nunavummiut have criticized the current rate structure, because smaller communities are paying more for their extra costs than larger communities.
QEC had hoped — as it had asked for — to change the structure so every community pays the same base rate. So regardless of if people go over their electricity usage limits for the government subsidy, everyone would pay the same overage rates.
But the government denied that request.
New rate is actually lower
The one thing we should highlight, however, is the new rate after the increase is actually lower than what customers were paying in 2014.
That's because when QEC sets its rates, it does so based on global oil price forecasts. Since 2014, the price of oil worldwide has slumped, and so QEC was able to purchase it at less than it had anticipated.
When that happens, and QEC makes more than $1 million within a six month period thanks to the lower oil prices, it refunds the excess profits back to customers through a discount on electricity base rates — a mechanism similar to a lump-sum credit used elsewhere — the government subsidy, however, doesn't change so the savings are passed on directly to customers.
Now, the 6.6 per cent increase to electricity rates, is actually being applied to the discounted base rate from the last seven months.
So again, while customers are paying more than they have been for the last seven months, it's lower than what they were paying in 2014.
Lastly, to be clear, all the figures used in this story are only for domestic non-government rates. Commercial rates and changes have not been explored in this story, given the differences in subsidy and rate application.
Texas Gulf Coast Power Outages from Harvey continue as flooding, high winds, and downed lines paralyze Houston and coastal utilities, while restoration crews from out-of-state work to repair infrastructure and restore electricity across impacted communities.
Key Points
Power disruptions across Houston and the Gulf Coast from Harvey, driven by flooding, wind damage, and blocked access.
✅ CenterPoint warns multi-day outages in flooded zones.
✅ AEP Texas aided by crews from Kentucky, Illinois, Missouri.
✅ Entergy expects more outages as storm nears Galveston.
Hundreds of thousands of Texans were without power along the Gulf Coast as Tropical Storm Harvey left parts of the Houston area under water, with extended Houston outages compounding response efforts.
There were roughly 280,000 customers without power along the Texas's coast and in Houston and the surrounding areas on Monday, according to reported outages by the state's investor-owned utilities. Harvey, which made landfall on Friday, caused devastating flooding and knocked out power lines along its destructive path, similar to the Louisiana grid rebuild after Laura that required weeks of restoration.
CenterPoint Energy reported more than 100,000 outages earlier on Monday, though that figure was down to 91,744 shortly after 1 p.m. on Monday.
The company said it was unable to access hard-hit areas until floodwaters recede and electric infrastructure dries out, a challenge that, as seen in Florida power restoration efforts elsewhere, has taken weeks to resolve. Outages in the most flooded areas could last for several days, CenterPoint warned.
AEP Texas's coverage area south of Houston had 150,500 customers without electricity as of 11 a.m. ET on Monday. That was down from the peak of its outages on Saturday afternoon, which affected 220,000 customers.
Former FEMA deputy director: Texas has already begun recovery from storm 1:54 PM ET Mon, 28 Aug 2017 | 05:57
Corpus Christi and the surrounding areas along the Gulf Coast were still experiencing the most outages, while persistent Toronto outages after a spring storm underscored how long recovery can take in urban areas. AEP credited assistance from out-of-state workers for helping to get the lights back on.
"Thousands of resources have arrived from across the country to help AEP Texas with restoration efforts following this historic weather event. Crews from Kentucky, Illinois, Missouri and other states have arrived and are working on restoring power to those impacted by Hurricane Harvey," AEP said in a statement.
Entergy reported 29,500 customers were without power on Monday in areas north of Houston. The company warned that additional outages were expected if Harvey moves inland near the island city of Galveston on Wednesday as anticipated, a pattern similar to New Orleans during Ida where electricity failed despite levees holding.
Houston, Beaumont and Victoria are expected to see continued periods of torrential rain through Tuesday, before Harvey begins to move north on Wednesday and out of the flood zone by Thursday.
"Our crews are safely restoring power as quickly as possible, but the continued wind, rain and flooding are having an impact on restoration efforts," Entergy said in a statement.
South of Houston, about 7,500 Texas New Mexico Power Company customers were still experiencing outages, according to the company's outage map.
France-Germany Energy Solidarity underscores EU energy crisis cooperation: gas supply swaps, electricity imports, price cap talks, and curbs on speculation as Russian pipeline flows halt and winter demand rises across the bloc.
Key Points
A pact where France sends gas to Germany as Germany supplies power, bolstering EU cooperation and winter security.
✅ Gas to Germany; power to France amid nuclear outages.
✅ EU price cap, anti-speculation, joint gas purchasing.
✅ No new Spain-France pipeline unless case improves.
France will send gas to Germany if needed while Germany stands ready to provide it with electricity, President Emmanuel Macron said on Monday, saying this showcased European solidarity in the face of the energy crisis stemming from the war in Ukraine, which many view as a wake-up call to ditch fossil fuels across the bloc.
European gas prices surged, share prices slid and the euro sank on Monday after Russia stopped pumping gas via a major supply route, and Germany's 200 billion euro package sought to cushion the blow, in another warning to the 27-nation EU as it scrambled to respond to the crisis ahead of winter. read more
"Germany needs our gas and we need power from the rest of Europe, notably Germany," France's president told a news conference as EU electricity reform remains under debate following a phone call with German Chancellor Olaf Scholz.
The necessary connections for France to deliver gas to Germany when needed would be finalised in the coming weeks, he said, adding that France, which had long been a net exporter of electricity, will need help from its neighbours because of technical problems its nuclear plants face. read more
Macron, however, said that he did not understand demand for a third gas link between France and Spain, rejecting calls to increase capacity with a new pipeline.
He added he was open to changing his mind on that point, especially as Germany's utility troubles deepen, should Scholz or Prime Minister Pedro Sanchez argue convincingly for it.
Ahead of a meeting on Friday of EU energy ministers, Macron said France was in favour of buying gas at a European rather than a national level, as emergency electricity measures are weighed, and called for European Union measures to control energy prices.
He said it was necessary to act against speculation on energy prices at EU level, as the EU outlines possible gas price cap strategies for discussion, and also said France was in favour of putting a cap on the price of pipeline Russian gas.
Macron also repeated calls for all to turn down air conditioners when it's hot and to limit heating to 19 degrees Celsius this winter, noting that rolling back electricity prices is tougher than it appears this year.
Boeing 787 More-Electric Architecture replaces pneumatics with bleedless pressurization, VFSG starter-generators, electric brakes, and heated wing anti-ice, leveraging APU, RAT, batteries, and airport ground power for efficient, redundant electrical power distribution.
Key Points
An integrated, bleedless electrical system powering start, pressurization, brakes, and anti-ice via VFSGs, APU and RAT.
✅ VFSGs start engines, then generate 235Vac variable-frequency power
✅ Bleedless pressurization, electric anti-ice improve fuel efficiency
✅ Electric brakes cut hydraulic weight and simplify maintenance
The 787 Dreamliner is different to most commercial aircraft flying the skies today. On the surface it may seem pretty similar to the likes of the 777 and A350, but get under the skin and it’s a whole different aircraft.
When Boeing designed the 787, in order to make it as fuel efficient as possible, it had to completely shake up the way some of the normal aircraft systems operated. Traditionally, systems such as the pressurization, engine start and wing anti-ice were powered by pneumatics. The wheel brakes were powered by the hydraulics. These essential systems required a lot of physical architecture and with that comes weight and maintenance. This got engineers thinking.
What if the brakes didn’t need the hydraulics? What if the engines could be started without the pneumatic system? What if the pressurisation system didn’t need bleed air from the engines? Imagine if all these systems could be powered electrically… so that’s what they did.
Power sources
The 787 uses a lot of electricity. Therefore, to keep up with the demand, it has a number of sources of power, much as grid operators track supply on the GB energy dashboard to balance loads. Depending on whether the aircraft is on the ground with its engines off or in the air with both engines running, different combinations of the power sources are used.
Engine starter/generators
The main source of power comes from four 235Vac variable frequency engine starter/generators (VFSGs). There are two of these in each engine. These function as electrically powered starter motors for the engine start, and once the engine is running, then act as engine driven generators.
The generators in the left engine are designated as L1 and L2, the two in the right engine are R1 and R2. They are connected to their respective engine gearbox to generate electrical power directly proportional to the engine speed. With the engines running, the generators provide electrical power to all the aircraft systems.
APU starter/generators
In the tail of most commercial aircraft sits a small engine, the Auxiliary Power Unit (APU). While this does not provide any power for aircraft propulsion, it does provide electrics for when the engines are not running.
The APU of the 787 has the same generators as each of the engines — two 235Vac VFSGs, designated L and R. They act as starter motors to get the APU going and once running, then act as generators. The power generated is once again directly proportional to the APU speed.
The APU not only provides power to the aircraft on the ground when the engines are switched off, but it can also provide power in flight should there be a problem with one of the engine generators.
Battery power
The aircraft has one main battery and one APU battery. The latter is quite basic, providing power to start the APU and for some of the external aircraft lighting.
The main battery is there to power the aircraft up when everything has been switched off and also in cases of extreme electrical failure in flight, and in the grid context, alternatives such as gravity power storage are being explored for long-duration resilience. It provides power to start the APU, acts as a back-up for the brakes and also feeds the captain’s flight instruments until the Ram Air Turbine deploys.
Ram air turbine (RAT) generator
When you need this, you’re really not having a great day. The RAT is a small propeller which automatically drops out of the underside of the aircraft in the event of a double engine failure (or when all three hydraulics system pressures are low). It can also be deployed manually by pressing a switch in the flight deck.
Once deployed into the airflow, the RAT spins up and turns the RAT generator. This provides enough electrical power to operate the captain’s flight instruments and other essentials items for communication, navigation and flight controls.
External power
Using the APU on the ground for electrics is fine, but they do tend to be quite noisy. Not great for airports wishing to keep their noise footprint down. To enable aircraft to be powered without the APU, most big airports will have a ground power system drawing from national grids, including output from facilities such as Barakah Unit 1 as part of the mix. Large cables from the airport power supply connect 115Vac to the aircraft and allow pilots to shut down the APU. This not only keeps the noise down but also saves on the fuel which the APU would use.
The 787 has three external power inputs — two at the front and one at the rear. The forward system is used to power systems required for ground operations such as lighting, cargo door operation and some cabin systems. If only one forward power source is connected, only very limited functions will be available.
The aft external power is only used when the ground power is required for engine start.
Circuit breakers
Most flight decks you visit will have the back wall covered in circuit breakers — CBs. If there is a problem with a system, the circuit breaker may “pop” to preserve the aircraft electrical system. If a particular system is not working, part of the engineers procedure may require them to pull and “collar” a CB — placing a small ring around the CB to stop it from being pushed back in. However, on the 787 there are no physical circuit breakers. You’ve guessed it, they’re electric.
Within the Multi Function Display screen is the Circuit Breaker Indication and Control (CBIC). From here, engineers and pilots are able to access all the “CBs” which would normally be on the back wall of the flight deck. If an operational procedure requires it, engineers are able to electrically pull and collar a CB giving the same result as a conventional CB.
Not only does this mean that the there are no physical CBs which may need replacing, it also creates space behind the flight deck which can be utilised for the galley area and cabin.
A normal flight
While it’s useful to have all these systems, they are never all used at the same time, and, as the power sector’s COVID-19 mitigation strategies showed, resilience planning matters across operations. Depending on the stage of the flight, different power sources will be used, sometimes in conjunction with others, to supply the required power.
On the ground
When we arrive at the aircraft, more often than not the aircraft is plugged into the external power with the APU off. Electricity is the blood of the 787 and it doesn’t like to be without a good supply constantly pumping through its system, and, as seen in NYC electric rhythms during COVID-19, demand patterns can shift quickly. Ground staff will connect two forward external power sources, as this enables us to operate the maximum number of systems as we prepare the aircraft for departure.
Whilst connected to the external source, there is not enough power to run the air conditioning system. As a result, whilst the APU is off, air conditioning is provided by Preconditioned Air (PCA) units on the ground. These connect to the aircraft by a pipe and pump cool air into the cabin to keep the temperature at a comfortable level.
APU start
As we near departure time, we need to start making some changes to the configuration of the electrical system. Before we can push back , the external power needs to be disconnected — the airports don’t take too kindly to us taking their cables with us — and since that supply ultimately comes from the grid, projects like the Bruce Power upgrade increase available capacity during peaks, but we need to generate our own power before we start the engines so to do this, we use the APU.
The APU, like any engine, takes a little time to start up, around 90 seconds or so. If you remember from before, the external power only supplies 115Vac whereas the two VFSGs in the APU each provide 235Vac. As a result, as soon as the APU is running, it automatically takes over the running of the electrical systems. The ground staff are then clear to disconnect the ground power.
If you read my article on how the 787 is pressurised, you’ll know that it’s powered by the electrical system. As soon as the APU is supplying the electricity, there is enough power to run the aircraft air conditioning. The PCA can then be removed.
Engine start
Once all doors and hatches are closed, external cables and pipes have been removed and the APU is running, we’re ready to push back from the gate and start our engines. Both engines are normally started at the same time, unless the outside air temperature is below 5°C.
On other aircraft types, the engines require high pressure air from the APU to turn the starter in the engine. This requires a lot of power from the APU and is also quite noisy. On the 787, the engine start is entirely electrical.
Power is drawn from the APU and feeds the VFSGs in the engines. If you remember from earlier, these fist act as starter motors. The starter motor starts the turn the turbines in the middle of the engine. These in turn start to turn the forward stages of the engine. Once there is enough airflow through the engine, and the fuel is igniting, there is enough energy to continue running itself.
After start
Once the engine is running, the VFSGs stop acting as starter motors and revert to acting as generators. As these generators are the preferred power source, they automatically take over the running of the electrical systems from the APU, which can then be switched off. The aircraft is now in the desired configuration for flight, with the 4 VFSGs in both engines providing all the power the aircraft needs.
As the aircraft moves away towards the runway, another electrically powered system is used — the brakes. On other aircraft types, the brakes are powered by the hydraulics system. This requires extra pipe work and the associated weight that goes with that. Hydraulically powered brake units can also be time consuming to replace.
By having electric brakes, the 787 is able to reduce the weight of the hydraulics system and it also makes it easier to change brake units. “Plug in and play” brakes are far quicker to change, keeping maintenance costs down and reducing flight delays.
In-flight
Another system which is powered electrically on the 787 is the anti-ice system. As aircraft fly though clouds in cold temperatures, ice can build up along the leading edge of the wing. As this reduces the efficiency of the the wing, we need to get rid of this.
Other aircraft types use hot air from the engines to melt it. On the 787, we have electrically powered pads along the leading edge which heat up to melt the ice.
Not only does this keep more power in the engines, but it also reduces the drag created as the hot air leaves the structure of the wing. A double win for fuel savings.
Once on the ground at the destination, it’s time to start thinking about the electrical configuration again. As we make our way to the gate, we start the APU in preparation for the engine shut down. However, because the engine generators have a high priority than the APU generators, the APU does not automatically take over. Instead, an indication on the EICAS shows APU RUNNING, to inform us that the APU is ready to take the electrical load.
Shutdown
With the park brake set, it’s time to shut the engines down. A final check that the APU is indeed running is made before moving the engine control switches to shut off. Plunging the cabin into darkness isn’t a smooth move. As the engines are shut down, the APU automatically takes over the power supply for the aircraft. Once the ground staff have connected the external power, we then have the option to also shut down the APU.
However, before doing this, we consider the cabin environment. If there is no PCA available and it’s hot outside, without the APU the cabin temperature will rise pretty quickly. In situations like this we’ll wait until all the passengers are off the aircraft until we shut down the APU.
Once on external power, the full flight cycle is complete. The aircraft can now be cleaned and catered, ready for the next crew to take over.
Bottom line
Electricity is a fundamental part of operating the 787. Even when there are no passengers on board, some power is required to keep the systems running, ready for the arrival of the next crew. As we prepare the aircraft for departure and start the engines, various methods of powering the aircraft are used.
The aircraft has six electrical generators, of which only four are used in normal flights. Should one fail, there are back-ups available. Should these back-ups fail, there are back-ups for the back-ups in the form of the battery. Should this back-up fail, there is yet another layer of contingency in the form of the RAT. A highly unlikely event.
The 787 was built around improving efficiency and lowering carbon emissions whilst ensuring unrivalled levels safety, and, in the wider energy landscape, perspectives like nuclear beyond electricity highlight complementary paths to decarbonization — a mission it’s able to achieve on hundreds of flights every single day.
Whether you would prefer Live Online or In-Person
instruction, our electrical training courses can be
tailored to meet your company's specific requirements
and delivered to your employees in one location or at
various locations.
