In response to the Ombudsman's media briefing earlier today, Hydro One provided the following update to the media.
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Significant improvements have been made since the implementation of the Company's new customer information system in May 2013 a change which led to billing issues for about 6 of its 1.3 million customers. The Company is committed to continue to work with the Ombudsman to resolve all issues brought forward. Any customer who experienced a billing disruption as a consequence of our new billing system implementation has been excluded from the collections process for a year.
Customers with incorrect bills will not receive disconnection notices.
"We have come a long way. In the past year, we have restored service levels at our call centre and performance of our billing system to levels higher than before the transition to our new billing system two years ago," said Carm Marcello, President and CEO, Hydro One. "Our relationship with our customers goes far beyond the bill. With the technical issues behind us, we are now revisiting all of our customer interactions with the goal of transforming our business into a truly customer caring organization."
Recently, the Ombudsman also referenced our disconnection process:
- Hydro One is reviewing and revising its disconnection communications to ensure that they are a clear and accurate reflection of our policies and easy for our customers to understand. We will work with the Ombudsman to resolve this issue.
- Disconnection is always a last resort.
- We do not disconnect during the winter months.
- Regardless of the time of year, we do communicate with customers to encourage them to keep their accounts current.
- Hydro One's process for working with customers in arrears has multiple stages and notifications to make customers aware of the actions they can take to keep their accounts current.
- We also inform them of the help and programs that are available if they are in financial difficulty.
- Managing credit and collections processes is about striking the right balance between compassion for individual hardship and fairness for all customers.
- Hydro One has brought in a North American expert on credit and collections to analyze our practices and make recommendations. His initial assessment is that Hydro One's collections practices are consistent with electric utility industry, but Hydro One provides customers with more time and leeway to manage their accounts than is typical in the industry.
- We hear the Ombudsman's concerns and Hydro One would like to sit down with him and write the disconnection letter to his satisfaction.
At this time, Hydro One's customer service operations and billing system are performing well. As of today, the Company has:
- Completed 99 of the 3,395 complaints received from the Ombudsman's office. The Ombudsman's office has told Hydro One that the remaining 6,005 complaints will not be transferred to Hydro One.
- Reduced the number of customers who have not received a bill for a prolonged period of time: less than 0.1: improved from 5 475 from 53,495.
- Reduced the number of customers who have received only estimated bills for a prolonged period of time: 0.4 from 3 4,681 from 30,899.
- Improved first call resolution to 85 from 75.
- Communicated with more than 60,000 customers through three teletownhalls and an online survey seeking their advice on how to improve service.
SDG&E Ramona Microgrid delivers renewable energy and battery storage for wildfire mitigation, grid resilience, and PSPS support, powering the Cal Fire Air Attack Base with a 500 kW, 2,000 kWh lithium-ion system during outages.
Key Points
A renewable, battery-backed microgrid powering Ramona's Air Attack Base, boosting wildfire response and PSPS resilience.
✅ Keeps Cal Fire and USFS aircraft operations powered
✅ Supports PSPS continuity and rural water reliability
It figures to be another dry year — with the potential to spark wildfires in the region. But San Diego Gas & Electric just completed a renewable energy upgrade to a microgrid in Ramona that will help firefighters and reduce the effects of power shutoffs to backcountry residents.
The microgrid will provide backup power to the Ramona Air Attack Base, helping keep the lights on during outages, home to Cal Fire and the U.S. Forest Service's fleet of aircrafts that can quickly douse fires before they get out of hand.
"It gives us peace of mind to have backup power for a critical facility like the Ramona Air Attack Base, especially given the fact that fire season in California has become year-round," Cal Fire/San Diego County Fire Chief Tony Mecham said in a statement.
The air attack base serves as a hub for fixed-wing aircraft assigned to put out fires. Cal Fire staffs the base throughout the year with one two airtankers and one tactical aircraft. The base also houses the Forest Service's Bell 205 A++ helicopter and crew to protect the Cleveland National Forest. Aircraft for both CalFire and the Forest Service can also be mobilized to help fight fires throughout the state.
This summer, the Ramona microgrid won't have to rely on diesel generation. Instead, the facility next to the town's airport will be powered by a 500 kilowatt and 2,000 kilowatt-hour lithium-ion battery storage system that won't generate any greenhouse gas emissions.
"What's great about it, besides that it's a renewable resource, is that it's a permanent installation," said Jonathan Woldemariam, SDG&E's director of wildfire mitigation and vegetation management. "In other words, we don't have to roll a portable generator out there. It's something that can be leveraged right there because it's already installed and ready to go."
Microgrids have taken on a larger profile across the state because they can operate independently of the larger electric grid, where repairing California's grid is an ongoing challenge, thus allowing small areas or communities to keep the power flowing for hours at a time during emergencies.
That can be crucial in wildfire-prone areas affected by Public Safety Power Shutoffs, or PSPS, the practice in which investor-owned utilities in California de-energize electrical power lines in a defined area when conditions are dry and windy in order to reduce the risk of a power line falling and igniting a wildfire, while power grid upgrades move forward statewide.
Rural and backcountry communities are particularly hard hit when the power is pre-emptively cut off because many homes rely on water from wells powered by electricity for their homes, horses and livestock.
In addition to Ramona, SDG&E has established microgrids in three other areas in High Fire Threat Districts:
The microgrids in Butterfield Ranch and Shelter Valley run on diesel power but the utility plans to complete solar and battery storage systems for each locale by the end of next year, as other regions develop new microgrid rules to guide deployment.
SDG&E has a fifth microgrid in operation — in Borrego Springs, which in 2013 became the first utility-scale microgrid in the country. It provides grid resiliency to the roughly 2,700 residents of the desert town and serves as a model for integrated microgrid projects elsewhere in delivering local electricity. While the Borrego Springs microgrid is not located in a High Fire Threat District, "when and if any power is turned off, especially the power transmission feed that goes to Borrego, we can support the customers using the microgrid out there," Woldemariam said.
Microgrid costs can be higher than conventional energy systems, even as projected energy storage revenue grows over the next decade, and the costs of the SDG&E projects are passed on to ratepayers. As per California Public Utilities Commission rules, the financial details for each of microgrid are kept confidential for at least three years.
SDG&E's microgrids are part of the utility's larger plan to reduce wildfire risk that SDG&E files with the utilities commission. In its wildfire plan for 2020 through 2022, SDG&E expected to spend $1.89 billion on mitigation measures.
Site C Dam Update outlines hydroelectric budget overruns, geotechnical risks, COVID-19 construction delays, BC Hydro timelines, cancellation costs, and First Nations treaty rights concerns affecting renewable energy, ratepayers, and Peace Valley impacts.
Key Points
Overview of Site C costs, delays, geotechnical risks, and concerns shaping BC Hydro hydroelectric plans.
✅ Cost to cancel estimated at least $10B
✅ Final budget now about $16B; completion pushed to 2025
✅ COVID-19 and geotechnical risks drove delays and redesigns
The cost to cancel a massive B.C. energy development project would be at least $10 billion, provincial officials revealed in an update on the future of Site C.
Thus the project will go ahead, Premier John Horgan and Energy Minister Bruce Ralston announced Friday, but with an increased budget and timeline.
Horgan and Ralston spoke at a news conference in Victoria about the findings of a status report into the hydroelectric dam project in northeastern B.C.
Peter Milburn, former deputy finance minister, finished the report earlier this year, but the findings were not initially made public.
$10B more than initial estimate On Friday, it was announced that the project's final price tag has once again ballooned by billions of dollars.
Site C was initially estimated to cost $6 billion, and the first approved budget, back in 2014, was $8.775 billion. The budget increased to $10.8 billion in 2018.
But the latest update suggests it will cost about $16 billion in total.
And, in addition to a higher budget, the date of completion has been pushed back to 2025 – a year later than the initial target.
Among the reasons for the revisions, according to the province, is the impact of COVID-19. While officials did not get into details, there have been multiple cases of the disease publicly reported at Site C work camps.
Additionally, fewer workers were permitted on site to allow for physical distancing, and construction was scaled back.
Also cited as a cause for the increased cost were "unforeseeable" geotechnical issues at the site, which required installation of an enhanced drainage system.
Speaking to reporters Friday, the premier deflected blame.
“Managing the contract the BC Liberals signed has been difficult because it transfers the vast majority of the geotechnical risk back to BC Hydro,” said Horgan.
Former Premier Christy Clark vowed to get the project to a point of no return, and in 2017 the NDP decided to continue with the project because of the cost of cancelling it.
The Liberals now say the clean energy project should continue, but deny they shoulder any of the blame.
“Someone has to take ownership – and it's got to be government in power,” said MLA Tom Shypitka, BC Liberal critic for energy.
There are also several reviews underway, including how to change contractor schedules to reflect delays and potential cost impacts from COVID-19, and how to keep the work environment safe during the pandemic.
A total of 17 recommendations were made in Milburn's report, all of which have been accepted by BC Hydro and the province.
Among these recommendations is a restructured project assurance board with a focus on skill-specific membership and autonomy from BC Hydro.
Cost of cancelling the project The report looked into whether it would be better to scrap the project altogether, but the cost of cancelling it at this point would be at least $10 billion, Horgan and Ralston said.
That cost does not include replacing lost energy and capacity that Site C's electricity would have provided, according to the province.
A study conducted in 2019 suggested B.C. will need to double its electricity production by 2055, especially as drought conditions are forcing BC Hydro to adapt power generation.
The NDP government says the cost to ratepayers of cancelling the project would be $216 a year for 10 years. Going forward will still have a cost, but instead, that payment will be split over more than 70 years, the estimated lifetime of Site C, meaning BC Hydro customers will pay about $36 more a year once the site goes live, the NDP says, even as cryptocurrency mining raises questions about electricity use.
“We will not put jobs at risk; we will not shock people's hydro bills,” said Horgan.
"Our government has taken this situation very seriously, and with the advice of independent experts guiding us, I am confident in the path forward for Site C," Ralston said.
"B.C. needs more renewable energy to bridge the electricity gap with Alberta and electrify our economy, transition away from fossil fuels and meet our climate targets."
The minister said the site is currently employing about 4,500 people.
Arguments against Site C While there are benefits to the project, there has also been vocal opposition.
In a statement released following the announcement that the project would go ahead, the Union of B.C. Indian Chiefs suggested the decision violated the premier's commitment to a UN declaration.
"The Site C dam has never had the free, prior and informed consent of all impacted First Nations, and proceeding with the project is a clear infringement of the treaty rights of the West Moberly First Nation," the UBCIC's secretary treasurer said.
Kukpi7 Judy Wilson said the UN's Committee on the Elimination of Racial Discrimination has called for a suspension of the project until it has the consent of Indigenous peoples.
"B.C. did not even attempt to engage First Nations about the safety risks associated with the stability of the dam in the recent reviews," she said.
"It is unfathomable that such clear human rights violations are somehow OK by this government."
Chief Roland Wilson of the West Moberly First Nation said he was disappointed the province didn’t consult his and other communities prior to making this announcement. In an interview with CTV News, he said he was offered an opportunity to join a call this morning.
“We signed a treaty in 1814,” he said. “Our treaty rights are being trampled on.”
Wilson said his nation has ongoing concerns about safety issues and the plans to flood the Peace Valley. West Moberly is in a bitter court battle with the province.
At the BC Legislature, Green Party Leader Sonia Furstenau slammed the government’s decision.
“It is an astonishingly terrible business case in any circumstances, but considering that we lose the agricultural land, the biodiversity, the traditional treaty lands of Treaty 8, this is particularly catastrophic,” she told reporters.
She went on to accuse the NDP government of keeping bad news from the public. She alleged the NDP knew of serious problems before last fall’s unscheduled election, but chose not to release information.
Prior to the decision former BC Hydro president and a former federal fisheries minister are among those who added their voices to calls to halt work on the dam.
They were among 18 Canadians who wrote an open letter to the province calling for an independent team of experts to explore geotechnical problems at the site.
In the letter, signed in September, the group that also included Grand Chief Stewart Phillip of the UBCIC wrote that going ahead would be a "costly and potentially catastrophic mistake."
According to Friday's update, independent experts have confirmed the site is safe, though improvements have been recommended to enhance oversight and risk management.
Earlier in the project, a B.C. First Nation claimed it was a $1-billion treaty violation, though an agreement was reached in 2020 after the province promised to improve land management and restore traditional place names in areas of cultural significance.
The Prophet River First Nation will also receive payments while the site is operating, and some Crown land will be transferred to the nation as part of the agreement.
Additionally, residents of a tiny community not far from the site is suing the province over two slow-moving landslides they claim caused property values to plummet.
Nearly three dozen residents of Old Fort are behind the allegations of negligence and breach of their charter right to security of person. The claim is tied to two landslides, in 2018 and 2020, that the group alleges were caused by ground destabilization from construction related to Site C.
One of the landslides damaged the only road into the community, leaving residents under evacuation for a month.
California Wildfire Power Shut-Offs escalate as PG&E imposes blackouts amid high winds, Getty and Kincade fires, mass evacuations, Sonoma County threats, and a state of emergency, drawing regulatory scrutiny over grid safety and outage scope.
Key Points
Planned utility outages to curb wildfire risk during extreme winds, prompting evacuations and regulatory scrutiny.
✅ PG&E preemptive blackouts under regulator inquiry
✅ Getty and Kincade fires drive mass evacuations
✅ Sonoma County under threat amid high winds
Pacific Gas & Electric (PG&E) already faces an investigation by regulators after cutting supplies to 970,000 homes and businesses amid California blackouts that raised concerns.
It announced that another 650,000 properties would face precautionary shut-offs.
Wildfires fanned by the strong winds are raging in two parts of the state.
Thousands of residents near the wealthy Brentwood neighbourhood of Los Angeles have been told to evacuate because of a wildfire that began early on Monday.
Further north in Sonoma County, a larger fire has forced 180,000 people from their homes.
California's governor has declared a state-wide emergency.
What about the power cuts?
On Monday regulators announced a formal inquiry into whether energy utilities broke rules by pre-emptively cutting power to an estimated 2.5 million people, amid a blackouts policy debate that intensified, as wildfire risks soared.
They did not name any utilities but analysts said PG&E was responsible for the bulk of the "public safety power shut-offs", and later faced a Camp Fire guilty plea that underscored its liabilities.
The company filed for bankruptcy in January after facing hundreds of lawsuits from victims of wildfires in 2017 and 2018.
Of the 970,000 properties hit by the most recent cuts, under half had their services back by Monday, and some sought help through wildfire assistance programs, the Associated Press reported.
Despite criticism that the precautionary blackouts were too widespread and too disruptive, PG&E said more would come on Tuesday and Wednesday because further strong winds were expected.
The company said it had logged more than 20 preliminary reports of damage to its network from the most recent windstorm.
In a video posted to Twitter on Saturday, Governor Gavin Newsom said the power cuts were "infuriating everyone, and rightfully so".
Where are the fires now?
In Los Angeles, the Getty Fire has burned over 600 acres (242 ha) and about 10,000 buildings are in the mandatory evacuation zone.
At least eight homes have been destroyed and five others damaged.
"If you are in an evacuation zone, don't screw around," Mr Schwarzenegger tweeted. "Get out."
LA fire chief Ralph Terrazas said fire crews had been "overwhelmed" by the scale of the fires.
"They had to make some tough decisions on which houses they were able to protect," he said.
"Many times it depends on where the ember lands. I saw homes that were adjacent to homes that were totally destroyed, without any damage."
In northern California, schools remain closed in Sonoma County, where tens of thousands of homes and businesses are under threat.
Sonoma has been ravaged by the Kincade Fire, which started on Wednesday and has burned through 50,000 acres of land, fanned by the winds.
The Kincade Fire began seven minutes after a nearby power line was damaged, and power lines may have started fires according to reports, but PG&E has not yet confirmed if the power glitch started the blaze.
About 180,000 people have been ordered to evacuate, with roads around Santa Rosa north of San Francisco packed with cars as people tried to flee.
There are fears the flames could cross the 101 highway and enter areas that have not seen wildfires since the 1940s.
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.
Ontario Electricity Rate Changes lower OEB Regulated Price Plan costs, adjust Time-of-Use winter hours and tiered thresholds, and modify the Ontario Electricity Rebate, affecting off-peak, mid-peak, and on-peak pricing for households and small businesses.
Key Points
OEB updates lowering RPP prices, shifting TOU hours, adjusting tiers, and modifying the Ontario Electricity Rebate.
On November 1, households and small businesses will see their electricity rates go down under the Ontario Energy Board's (OEB) Regulated Price Plan framework.
Customer's on the OEB's tiered pricing plan will also see their bills lowered on November 1, a shift from the 2021 increase when fixed pricing ended, as winter time-of-use hours and the seasonal change in the killowatt-hour threshold take effect.
Off-peak time-of-use hours will run from 7 p.m. to 7 a.m. during weekdays, including the ultra-low overnight rates option for some customers, and all day on weekends and holidays. On-peak hours will be from 7 a.m. to 11 a.m. and 5 p.m. to 7 p.m. on weekdays, and mid-peak hours from 11 a.m. to 5 p.m. on weekdays.
The winter-tier threshold provides residential customers with an extra 400 kilowatt-hours per month at a lower price during the colder weather, alongside the off-peak price freeze in effect.
The Ontario Electricity Rebate - a pre-tax credit that shows up at the bottom of electricity bills - will also see changes as a hydro rate change takes effect on November 1. Starting next month, the rebate will drop from 17 per cent to 11.7 per cent.
For a typical residential customer, the credit will decrease electricity bills by about $13.91 per month, according to the OEB.
Under the board's winter disconnection ban, electricity providers can't turn off a residential customer's power between November 15, 2022 and April 30, 2023 for failing to pay, and earlier pandemic relief included a fixed COVID-19 hydro rate for customers.
Ontario Hydrogen Strategy accelerates green hydrogen via electrolysis, reduced electricity rates, and IESO pilots, leveraging ICI, interruptible rates, and surplus power to grow clean tech, low-carbon energy, and export markets across Ontario.
Key Points
A provincial plan to scale green hydrogen with electricity costs, IESO pilots, and surplus power to boost tech.
✅ Amends ICI to admit hydrogen producers from 50 kW demand
✅ Enables co-located electrolysers to use surplus curtailed power
✅ Offers interruptible rates via IESO pilot for flexible loads
The Ontario Ministry of Energy is seeking input on accelerating Ontario’s hydrogen economy. The province has been promoting growth in the clean tech sector, including low-carbon energy production and the Hydrogen Innovation Fund, as an avenue for post-COVID-19 economic recovery. Hydrogen produced through electrolysis (or “green hydrogen”) has been central to these efforts, complimenting both federal and provincial initiatives to create vibrant domestic and export markets for the energy as a principal alternative to conventional fossil fuels.
On April 14, 2022, the Ministry filed a proposal (the Proposal) on the Environmental Registry of Ontario (ERO) to gather input from stakeholders, aligning with the province’s industrial electricity pricing consultation underway. As part of Ontario’s Hydrogen Strategy, the Ministry is considering several options that would provide reduced electricity rates for green hydrogen producers to make production more economically competitive with other energies. To date, the relatively high production cost of green hydrogen has been a challenge facing its adoption, both domestically and internationally.
The Proposal features three options:
Amending the rules for the Industrial Conservation Initiative (ICI) applicable to hydrogen producers;
Enabling onsite hydrogen production using electricity that would otherwise be curtailed; and
Providing an interruptible electricity rate for hydrogen producers.
Option 1: Amending the ICI rules
Option 1 would amend the ICI rules to allow all hydrogen producers with an average monthly peak demand of 50kW to participate. Hydrogen producers’ facilities could qualify for ICI in the first year of operation with a peak demand factor determined based on a deemed consumption profile, using a method yet to be determined by the Ministry. At the end of the first year, their global adjustment (GA) charges would be reconciled based on their actual consumption pattern. As set out in our prior article, GA was introduced by the province in January 2005 to ensure reliable, sustainable and a diverse supply of power at stable and competitive prices, aligning with plans to rely on battery storage to meet rising energy demand. The Ministry’s current proposal would require hydrogen producers to place a security deposit for their facilities’ first year of operation with the Independent Electricity System Operator (IESO) or their Local Distribution Company (LDC) to ensure other consumer would not be adversely affected.
Option 2: Enable onsite hydrogen production using surplus electricity
Option 2 would allow businesses to co-locate hydrogen electrolysers at electricity generation facilities, drawing on recent electrolyzer investment trends, to make use of what would become curtailed generation. Under this option in the Proposal, the developer for the hydrogen production facility would be required to be a separate legal entity from the one that owns or operates the electricity generation facility. Based on this required level of independence, the hydrogen developer would be required to pay the electricity generator for the electricity supply.
At this stage, it is not clear whether, or how the generator would be required to share the revenue with other consumers. The next steps of the Proposal may require regulatory amendments, and/or amendments to electricity generator’s contracts, consistent with efforts enabling storage in Ontario's electricity system to integrate flexible resources.
Option 3: Interruptible electricity rates for hydrogen producers
In 2021, the Ministry posted a proposal on the ERO including an Interruptible Rate Pilot that was to be developed in conjunction with the IESO in order to address stakeholder feedback received during the 2019 Industrial Consultation specific to the challenges of identifying and responding to peak demand events while participating in the ICI. The pilot was targeted towards large electricity consumers, where participants were charged GA at a reduced rate in exchange for agreeing to reduce consumption during system or local reliability events, as identified by IESO.
Option 3 would allow for the introduction for a dedicated stream for hydrogen producers into the interruptible rate pilot, which is currently under development with the IESO. This would take into account the unique circumstances of hydrogen producers, as well as the importance of the hydrogen sector in Ontario’s Low-Carbon Hydrogen Strategy. Under the pilot, participants would be given advance notice by the IESO to reduce demand over a fixed number of hours, several times each year, and emerging vehicle-to-grid models where EV owners can sell electricity back to the grid highlight additional flexibility options. Ultimately, the pilot would support low-carbon hydrogen production by offering large electricity consumers, such as hydrogen producers, reduced electricity rates in exchange for reduces consumption during system or local reliability events.
Following this initial development work, the Ministry intends to consult with stakeholders later this year to determine design details, as well as the timing for the potential roll out of the proposed pilot.
Key takeaways
The design options are not meant to be mutually exclusive, and might be pursued by the Ministry in combination. Ultimately, Ontario is focusing on ways to reduce electricity rates in an attempt to make the province a leader in the adoption of green hydrogen, as made clear in the Ontario Hydrogen Strategy, even as an electricity supply crunch looms, underscoring the urgency. Stakeholders will want to participate in this process given its long-term implications for both the hydrogen and power sectors.
