The Environmental Protection Agency made public a list of 26 communities in 10 states where residents are potentially threatened by coal ash storage ponds similar to one that flooded a neighborhood in Tennessee last year.
North Carolina has the most sites on the list, a dozen. The largest concentration is near Cochise, Ariz., where there are seven storage ponds.
The agency said it will inspect each of the 44 coal ash sites located near communities to make certain they are structurally sound. The sites are being classified as potentially highly hazardous because they are near where people live and not because of any discovered defect.
"The high hazard potential means there will be probable loss of human life if there is a significant dam failure," said Matt Hale, director of EPA's office of research, conservation and recovery. "It is a measure of what would happen if the dam would fail. It is not a measure of the stability of the dam."
Sen. Barbara Boxer, D-Calif., whose Environment and Public Works Committee held hearings on the coal ash risks, hailed the EPA decision. She said making the most high-risk sites public is essential "so that people have the information they need to quickly press for action to make these sites safer." Boxer had called on the EPA to make the information available.
Burning coal produces ash, which is kept in liquid, known as slurry, in containment ponds or dams. The EPA lists more than 400 such impoundments across the country, but the 44 singled out represent those that are near populated areas, posing a higher danger.
Last year, two days before Christmas, a coal ash pond broke near Kingston, Tenn., sending 5 million cubic yards of ash and sludge across more than 300 acres, destroying or damaging 40 homes. The incident prompted a safety review of storage ponds that hold the waste byproduct near large coal-burning power plants.
The storage ponds hold fly ash, bottom ash, coal slag and flue gas residues that contain toxic metals such as arsenic, selenium, cadmium, lead and mercury, although generally at low concentrations.
Until now, the national coal ash site list has not been provided to the public. Earlier this month the Army Corps of Engineers said it didn't want the locations disclosed because of national security and that it could help terrorists target such facilities. Hale said that issue has been resolved.
The EPA has been to half the 44 sites and expects to issue reports soon, Hale said. The EPA inspections are continuing. The EPA also is reviewing state inspection reports at some of the sites.
The seven ponds near Cochise, Ariz., hold material from the Apache Station Combustion Waste Disposal Facility operated by Arizona Electric Power Cooperative.
The 10 states, the number of sites, and communities are:
• North Carolina, 12 (Belmont, Walnut Cove, Spencer, Eden, Mount Holy, Terrell and Arden).
• Arizona, 9 (Cochise, Joseph City).
• Kentucky, 7 (Louisa, Harrodsburg, Ghent and Louisville).
• Ohio, 6 (Waterford, Brilliant and Cheshire).
• West Virginia, 4 (Willow Island, St. Albans, Moundsville, New Haven).
• Illiniois, 2 (Havana, Alton).
• Indiana, 1 (Lawrenceburg).
• Pennsylvania, 1 (Shippingport).
• Georgia, 1 (Milledgeville).
• Montana, 1 (Colstrip).
Two electric utilities — Columbus, Ohio-based America Electric Power and Charlotte-N.C.-based Duke Energy Corp. — operate nearly half of the coal ash sites on the list. Spokesmen for both companies said the sites are routinely inspected and are safe.
"We go above and beyond to make sure our (coal ash) dams are safe," said AEP spokesman Pat Hemlepp, whose utility has 11 of the ponds on the list. He said the sites are inspected annually by the corporation and more frequently by the individual power plant officials.
Jason Wells, spokesman for Duke Energy, which has 10 sites on the list, said, "We are absolutely confident from our monitoring, maintenance and inspections that the dams have the structural integrity to protect the public and the environment."
BC Hydro COVID-19 Site C updates detail monitoring, self-isolation at the work camp, Northern Health coordination, social distancing, reduced staffing, progress on diversion tunnels, Highway 29 realignment, and public reports to Peace River Regional District.
Key Points
Regular reports on COVID-19 monitoring, isolation protocols, staffing, and Site C work with Northern Health.
✅ Daily updates to Peace River Regional District
✅ Isolation rooms reserved in camp dorms
✅ Construction continues with social distancing
BC Hydro says it will begin giving regular updates to the public and the Peace River Regional District about its monitoring of the coronavirus COVID-19 at Site C, reflecting broader industry alerts such as a U.S. grid warning on pandemic risks.
BC Hydro met with the Peace River Regional District Sunday via phone call to discuss the forthcoming measures.
"We did a make a commitment to provide regular updates to Peace River Regional District member communities on an ongoing basis," said spokesman Dave Conway.
"(It's) certainly one of the things that we heard that they want and we heard that strongly and repeatedly."
Conway said updates could be posted as early as Monday on BC Hydro's website for the project.
As of March 23, there were sixteen people in self-isolation at the work camp just outside Fort St. John. Conway did not know how many of the workers have been tested for the virus, but said there are no confirmed cases on site. Provincial guidelines are being followed, he said.
"If they show any of the following symptoms, so sneezing, sore throat, muscle aches, headaches, coughs, or difficulty breathing, they're isolated for 14 days," Conway said.
"We're being very cautious of our application of the guidelines. We're asking anybody to self isolate if they have any slight symptoms."
BC Hydro has set aside one 30-room dorm at the camp for workers who need to isolate themselves, similar to measures in other jurisdictions where the power industry may house staff on-site to maintain operations, and has another four dorms with another 120 rooms that can be used as necessary. Conway could not immediately say whether additional rooms at hotels or at its apartment block have also been reserved.
There have been 700 workers home since a scale-back in construction was announced on March 18, and more workers are expected to be sent home this week. There were 940 people in camp on March 23, Conway said.
"To put that into perspective, the number of people staying in camp at this time of year, based on previous years, usually averages around 1,700," Conway said.
Brad Sperling, board chair for the Peace River Regional District, said BC Hydro has committed to formulating a strategy over the next few days to keep local government and public informed.
Electoral director Karen Goodings said she was pleased by that, and that it's important to everyone that BC Hydro works with Northern Health and adheres to provincial guidelines.
"The senior governments are critical to what measures will be undertaken not only on the project, including the camp, but also on the rules around transportation of workers and on addressing workplace conduct investigations at other utilities," Goodings wrote in an email.
On Sunday, the Site C leisure bus was seen at Totem Mall with two passengers on board.
Conway said the ongoing use of the shuttle is being monitored and evaluated, and is operating under social distancing and extra cleaning guidelines aligned with public transportation changes that have come under BC Transit.
The bus makes 10 trips per day from the camp, with an average of two passengers per trip, Conway said.
"We still have, of course, people in camp, and it's an opportunity for guests to get out and go for a walk and re-provision themselves for essentials for personal needs," Conway said.
Construction of the river diversion tunnels continues to meet a fall deadline, while work also carries on to realign Highway 29, build the transmission line, and clear the valley and future reservoir. Other site security and environmental monitoring work also continues, as utilities confront a dangerous dam-climbing trend driven by social media.
BC Hydro has said measures have been put into place, amid concerns similar to those voiced by nuclear plant workers about precautions at industrial sites, to minimize the potential spread of the COVID-19 on site, such as closing the camp gym and theatre, eliminating self serve dining stations, as well as non-essential travel, tours, and meetings.
Some workers, however, have raised worries about the tight working conditions on site, noting field safety incidents that highlight risks in the sector.
The province announced Monday 48 new cases in B.C., including one more in the Northern Health region, bringing the region's total to five, while Saskatchewan's numbers show how the crisis has reshaped that province. Their precise whereabouts are not being reported by B.C. public health officials.
London Tube Strikes Economic Impact highlights transport disruption reducing foot traffic, commuter flows, and tourism, squeezing small businesses, hospitality revenue, and citywide growth while business leaders urge negotiations, resolution, and policy responses to stabilize operations.
Key Points
Reduced transport options cut foot traffic and sales, straining small businesses and slowing London-wide growth.
✅ Hospitality venues report lower revenue and temporary closures
✅ Commuter and tourism declines reduce daily sales and bookings
✅ Business groups urge swift negotiations to restore services
London's economy is facing significant challenges due to ongoing tube strikes, challenges that are compounded by scrutiny of UK energy network profits and broader cost pressures across sectors, with businesses across the city experiencing disruptions that are impacting their operations and bottom lines.
Impact on Small Businesses
Small businesses, particularly those in the hospitality sector, are bearing the brunt of the disruptions caused by the strikes. Many establishments rely on the steady flow of commuters and tourists that the tube system facilitates, while also hoping for measures like temporary electricity bill relief that can ease operating costs during downturns. With reduced transportation options, foot traffic has dwindled, leading to decreased sales and, in some cases, temporary closures.
Economic Consequences
The strikes are not only affecting individual businesses but are also having a ripple effect on the broader economy, a dynamic seen when commercial electricity consumption plummeted in B.C. during the pandemic. The reduced activity in key sectors is contributing to a slowdown in economic growth, echoing periods when BC Hydro demand fell 10% and prompting policy responses such as Ontario electricity rate reductions for businesses, with potential long-term consequences if the disruptions continue.
Calls for Resolution
Business leaders and industry groups are urging for a swift resolution to the strikes. They emphasize the need for dialogue between the involved parties to reach an agreement that minimizes further economic damage and restores normalcy to the city's transportation system.
The ongoing tube strikes in London are causing significant disruptions to the city's economy, particularly affecting small businesses that depend on the efficient movement of people. Immediate action is needed to address the issues, drawing on tools like a subsidized hydro plan used elsewhere to spur recovery, to prevent further economic downturn.
AEMC Storage Charging Rules spark industry backlash as Tesla, Snowy Hydro, and investors warn transmission charges on batteries and pumped hydro could deter grid-scale storage, distort the National Electricity Market, and slow decarbonisation.
Key Points
AEMC Storage Charging Rules are proposals to bill grid storage for network use, shaping costs and investment.
✅ Charges apply when batteries draw power; double-charging concerns.
✅ Tesla and Snowy Hydro warn of reduced viability and delays.
Tesla, Snowy Hydro and other big suppliers of storage capacity on Australia’s main electricity grid warn proposed rule changes amount to a tax on their operations that will deter investors and slow the decarbonisation of the industry.
The Australian Energy Market Commission (AEMC) will release its final decision this Thursday on new rules for integrating batteries, pumped hydro and other forms of storage.
The AEMC’s draft decision, released in July, angered many firms because it proposed charging storage providers for drawing power, ignoring a recommendation by the Australian Electricity Market Operator (AEMO) that they be exempt.
Battery maker Tesla, which has supplied some of the largest storage to the National Electricity Market, said in a submission that the charges would “kill the commercial viability of all grid storage projects, causing inefficient investment in alternative network”, with consumers paying higher costs.
Snowy Hydro, which is building the giant Snowy 2 pumped storage project and already operates a smaller one, said in its submission the proposed changes if implemented would jeopardise investment.
“This is a major policy change, amounting to a tax on infrastructure critical to achieving a renewable future,” Snowy Hydro said.
AEMO itself argued it was important storage providers were not “disincentivised from connecting to the transmission network, as they generally provide a net benefit to the power system by charging at periods of low demand”.
Australia’s electricity grid faces economic and engineering challenges, similar to Ontario's storage push as it adjusts to the arrival of lower cost and also lower carbon alternatives to fossil fuels.
While rule changes are necessary to account for operators that can both draw from and supply power, how they are implemented can have long-lasting effects on the technologies that get encouraged or repelled, including control of EV charging issues, independent experts say.
“It doesn’t have to be this way,” said Bruce Mountain, director of the Victoria Energy Policy Centre. “In Britain, where the UK grid transformation is underway, the regulator dealing with the same issues has said that storage devices don’t pay the system charges when they withdraw electricity from the grid,” he said.
The prospect that storage operators will have to pay transmission charges could “drastically” affect their profitability since their business models rely on the difference between the price their pay for power and how much they can sell it for. Gas generators and network monopolies would benefit from the change, Mountain said.
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An AEMC spokesperson said the commission had consulted widely, including from those who objected to the payment for transmission access.
“The market is moving towards a future that will be increasingly reliant on energy storage to firm up the growing volume of renewable energy and deliver on the increasing need for critical system security services, with examples such as EVs supporting grid stability in California as the ageing fleet of thermal generators retire,” the spokesperson said, declining to elaborate on the final ruling before it is published.
“The regulatory framework needs to facilitate this transition as the energy sector continues to decarbonise,” the official said.
AusNet, which operates the Victorian energy transmission grid, said that while “technological neutrality is paramount for battery and hybrid unit connections to both the distribution and transmission networks,” it did not back charging storage access to networks in all cases.
“[Ausnet] supports a clear exemptions framework for energy storage providers,” a spokesperson said. “We recommend that batteries and other hybrid facilities should have transmission use of system charges waived if they provide a net benefit to network customers.”
We are not aware of anyone that supports the charging storage access to networks in all circumstances.
“Batteries and hybrid facilities that consume energy from the network should be provided no preferential treatment relative to other customers and generators.”
Jonathan Upson, a principal at Strategic Renewable Consulting, though, said the AEMC wants electricity flowing through batteries to be taxed twice to pay network charges – once when the electricity charges the battery and then again when the same electricity is sent out by the battery an hour or two later but this time with customers paying.
“The AEMC’s draft decision has the identical rationale for eliminating franking credits on all dividends, resulting in double taxing of company profits,” he said.
Christiaan Zuur, director of energy transformation at the Clean Energy Council, said that while much of AEMC’s draft proposal was constructive, “those benefits are either nullified or maybe even outweighed” by uncertainty over charges.
“Risk perception” will be important since potential newcomers won’t be sure of what charges they will pay to connect to the grid and existing operators could have their connection agreements reopened, Zuur said.
“Investors focus on the potential risk. It does factor through to the integral costs for projects,” he said.
The outcome of new charges may prompt more people to put batteries on their premises and draw power from their own solar panels, Mountain said, with rising EV adoption introducing new grid challenges, cutting their reliance on a centralised network.
“Ironically, it encourages customers to depend less and less on the grid,” he said. “It’s almost like the capture of the dominant interests playing out over time at their own expense.”
Separately, the latest edition of the Clean Energy Council Confidence Index shows leadership by state governments is helping to shore up investor appetite for investing in renewable energy amid 2021 electricity lessons even with higher 2030 emissions reduction goals from the federal government.
Overall, investor confidence increased by a point in the last six months – from 6.3 to 7.3 out of 10 – following strong commitments and policy development from state governments, particularly on the east coast, the council said.
“The results of this latest survey illustrate the economic value in policy that lowers the emissions footprint of our electricity generation, supporting regional centres and creating jobs. Investors recognise the opportunities created by limiting global temperature rise to 1.5 degrees,” said council chief executive Kane Thornton.
Among the states, NSW, Victoria and Queensland led in terms of positive investor sentiment.
Correction: this article was amended on 30 November. An earlier version stated Ausnet supported charging storage for network access. A spokesperson said it backed a waiver on charges if certain conditions are met.
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.
FERC Transmission Rule accelerates grid modernization and interregional high-voltage lines, enabling renewable energy integration, load balancing, and reliability to advance net-zero goals while strengthening resilience, capacity expansion, and decarbonization across U.S. regional transmission organizations.
Key Points
A federal policy mandating interregional grid planning and cost sharing to expand high-voltage lines for renewables.
✅ Improves reliability, resilience, and load balancing
✅ Aligns cost allocation and long-term planning for renewables
On May 13th, 2024, the US took a monumental step towards its clean energy goals. The Federal Energy Regulatory Commission (FERC) approved a long-awaited rule designed to significantly expand the transmission of renewable energy across the nation's power grid, a US grid overhaul that many advocates say was overdue. This decision aligns with President Biden's ambitious plan to achieve net-zero carbon emissions by 2050, with renewable energy playing a central role.
The new rule tackles a critical bottleneck hindering the widespread adoption of renewables – transmission infrastructure. Unlike traditional power plants like coal or natural gas that run constantly, solar and wind power generation fluctuates with weather conditions. This variability poses a challenge for the existing grid, which is not designed to efficiently handle large-scale integration of these intermittent sources, helping explain why the grid isn't 100% renewable today.
The FERC rule aims to address this by promoting the construction of new, high-voltage transmission lines, particularly those connecting different regions, where grid limitations in the Pacific Northwest have highlighted the need for better interregional transfers. This improved connectivity would allow for a more strategic distribution of renewable energy. Imagine solar energy harnessed in the sun-drenched Southwest being transmitted eastward to meet peak demand during hot summer days on the Atlantic Coast.
The benefits of this expanded transmission network are multifaceted. First, it unlocks the full potential of renewable resources by allowing for their efficient utilization across the country, a trend consistent with wind and solar surpassing coal in U.S. generation. Abundant wind power in the Midwest could be utilized on the West Coast, while surplus solar energy from the South could supplement demand in the Northeast.
Second, a more robust grid with a higher capacity for renewables reduces reliance on fossil fuel-based power plants and complements other ways to meet decarbonization goals across sectors. This translates to cleaner air and a significant reduction in greenhouse gas emissions, contributing to the fight against climate change.
Third, a modernized grid with improved long-distance transmission bolsters the nation's energy security. Extreme weather events, a growing concern due to climate change, can disrupt energy production in specific regions. This interconnected grid would provide a buffer, ensuring a more reliable and resilient power supply and helping put regions on the road to 100% renewables even during adverse weather conditions.
The FERC's decision is a win for environmental groups and the renewable energy industry. They see it as a critical step towards a cleaner energy future and a significant driver of job creation in the construction and maintenance of new transmission lines. However, concerns have been raised by some stakeholders, particularly investor-owned utilities. They worry about the potential cost burden associated with building these expansive new lines, and recent reports of stalled grid spending underscore those concerns and the need for efficient cost allocation mechanisms. Striking a balance between efficiency, affordability, and environmental responsibility will be crucial for the successful implementation of this policy.
IESO Fictitious Demand Error inflated HOEP in the Ontario electricity market, after embedded generation was mis-modeled; the OEB says double-counted load lifted wholesale prices and shifted costs via the Global Adjustment.
Key Points
An IESO modeling flaw that double-counted load, inflating HOEP and charges in Ontario's wholesale market.
✅ Double-counted unmetered load from embedded generation
✅ Inflated HOEP; shifted costs via Global Adjustment
✅ OEB flagged transparency; exporters paid more
For almost a year, the operator of Ontario’s electricity system erroneously counted enough phantom demand to power a small city, causing prices to spike and hundreds of millions of dollars in extra charges to consumers, according to the provincial energy regulator.
The Independent Electricity System Operator (IESO) also failed to tell anyone about the error once it noticed and fixed it.
The error likely added between $450 million and $560 million to hourly rates and other charges before it was fixed in April 2017, according to a report released this month by the Ontario Energy Board’s Market Surveillance Panel.
It did this by adding as much as 220 MW of “fictitious demand” to the market starting in May 2016, when the IESO started paying consumers who reduced their demand for power during peak periods. This involved the integration of small-scale embedded generation (largely made up of solar) into its wholesale model for the first time.
The mistake assumed maximum consumption at such sites without meters, and double-counted that consumption.
The OEB said the mistake particularly hurt exporters and some end-users, who did not benefit from a related reduction of a global adjustment rate applicable to other customers.
“The most direct impact of the increase in HOEP (Hourly Ontario Energy Price) was felt by Ontario consumers and exporters of electricity, who paid an artificially high HOEP, to the benefit of generators and importers,” the OEB said.
The mix-up did not result in an equivalent increase in total system costs, because changes to the HOEP are offset by inverse changes to a electricity cost allocation mechanism such as the Global Adjustment rate, the OEB noted.
A chart from the OEB's report shows the time of day when fictitious demand was added to the system, and its influence on hourly rates.
Peak time spikes The OEB said that the fictitious demand “regularly inflated” the hourly price of energy and other costs calculated as a direct function of it.
For almost a year, Ontario's electricity system operator @IESO_Tweets erroneously counted enough phantom demand to power a small city, causing price spikes and hundreds of millions in charges to consumers, @OntEnergyBoard says. @5thEstate reports.
It estimated the average increase to the HOEP was as much as $4.50/MWh, but that price spikes, compounded by scheduled OEB rate changes, would have been much higher during busier times, such as the mid-morning and early evening.
“In times of tight supply, the addition of fictitious demand often had a dramatic inflationary impact on the HOEP,” the report said.
That meant on one summer evening in 2016 the hourly rate jumped to $1,619/MWh, it said, which was the fourth highest in the history of the Ontario wholesale electricity market.
“Additional demand is met by scheduling increasingly expensive supply, thus increasing the market price. In instances where supply is tight and the supply stack is steep, small increases in demand can cause significant increases in the market price.
The OEB questioned why, as of September this year, the IESO had failed to notify its customers or the broader public, amid a broader auditor-regulator dispute that drew political attention, about the mistake and its effect on prices.
“It's time for greater transparency on where electricity costs are really coming from,” said Sarah Buchanan, clean energy program manager at Environmental Defence.
“Ontario will be making big decisions in the coming years about whether to keep our electricity grid clean, or burn more fossil fuels to keep the lights on,” she added. “These decisions need to be informed by the best possible evidence, and that can't happen if critical information is hidden.”
In a response to the OEB report on Monday, the IESO said its own initial analysis found that the error likely pushed wholesale electricity payments up by $225 million. That calculation assumed that the higher prices would have changed consumer behaviour, while upcoming electricity auctions were cited as a way to lower costs, it said.
In response to questions, a spokesperson said residential and small commercial consumers would have saved $11 million in electricity costs over the 11-month period, even as a typical bill increase loomed province-wide, while larger consumers would have paid an extra $14 million.
That is because residential and small commercial customers pay some costs via time-of-use rates, including a temporary recovery rate framework, the IESO said, while larger customers pay them in a way that reflects their share of overall electricity use during the five highest demand hours of the year.
The IESO said it could not compensate those that had paid too much, given the complexity of the system, and that the modelling error did not have a significant impact on ratepayers.
While acknowledging the effects of the mistake would vary among its customers, the IESO said the net market impact was less than $10 million, amid ongoing legislation to lower electricity rates in Ontario.
It said it would improve testing of its processes prior to deployment and agreed to publicly disclose errors that significantly affect the wholesale market in the future.
