Declining industrial electricity demand and an abundance of cheap natural gas will threaten coal's status as the dominant U.S. fuel to generate electric power, even after the economic recession ends.
Power companies are reducing use of coal plants because of declining demand from heavy industry, the economic sector hardest hit by the recession. The loss of industrial "baseload" looks long term, analysts and executives say.
Natural gas-fired plants, easier to stop and start, have remained busy serving commercial and household power demand, which varies hour by hour and has been less affected by the recession.
"The recession's impact on our industrial customers has been significant," said Lonnie Carter, chief executive of Santee Cooper, South Carolina's state-owned power and water utility. "We anticipate that as the economy recovers from this economic downturn, long-term power needs will be lower."
Meanwhile, generators' reasons for preferring coal for baseload — lower cost and more reliable supply — weaken with every shale gas discovery, which drives gas prices down and suggests gas will be plentiful for years to come.
"We may be in a situation where we are redefining how much coal-fired generation we need," added Nick Akins, executive vice president of American Electric Power Co, one of the country's biggest coal burners.
Coal's share of U.S. power generation has fallen from 49 percent in 2007 to 45 percent this year, said Luther Lu of FBR Capital Markets.
Coal-fired generation fell 12.7 percent from June 2008 to June 2009, while gas-fired power remained steady, down only 0.3 percent, according to U.S. Energy Information Administration figures.
The decline occurred despite the fact that coal remains cheaper than natural gas. Average gas prices have fallen to $3.83 per MMBtu in second quarter 2009 from $11.73 in the year-ago quarter, according to EIA data.
Coal prices soared last year, but year-over-year have held steady at $2.24 per MMBtu in the second quarter of 2009 versus $2.04 in the second quarter of 2008, according to the EIA.
Total electricity sales in June were 7.3 percent below the same month last year, but industrial consumption fell 14.6 percent, U.S. government data show.
And industrial electricity demand growth will be the laggard out to 2030 in a generally slow-growth period for U.S. power, EIA data show.
U.S. demand is expected to grow 26 percent between 2007 and 2030, while industrial demand should grow 7 percent. In the same period, commercial demand will grow 38 percent and residential 20 percent, according to government estimates.
Beyond the fundamentals of supply and demand, power company executives face government action to slow global warming, which will discourage use of coal in favor of gas. Gas emits about 50 percent less greenhouse gas than coal.
"In a carbon-constrained world, there will be a fairly major shift toward gas," Matt Preston, senior coal analyst at Hill & Associates, said in an email.
This array of factors has caused Santee Cooper, American Electric Power and other power companies to trim plans to expand coal-fired generation, and some companies, such as Progress Energy, are replacing coal plants with gas units.
Coal may enjoy a brief curtain call, if the economy and industry rebound quickly, overwhelming the ability of natural gas, nuclear power and alternate energy sources to quickly respond to a demand surge, said Brian Gamble of Simmons & Co.
But long term, coal's share will be eroded by cleaner energy sources, Gamble predicted.
Coal executives and many analysts say low gas prices are temporary and President Barack Obama's commitment to America's most plentiful fuel, and the technology to burn it cleanly, guarantee coal's future.
"We firmly believe the stage is set for coal to outperform other fuels, once manufacturing activity begins even a slightly sustained increase," said Steve Leer, CEO of Arch Coal Inc, a leading U.S. coal producer.
But gas can serve industrial baseload, too, and utility executives increasingly are exploring it along with expanded nuclear, solar and wind power, Lu said.
"My sources tell me some utilities have actually gone out and spoken to gas producers to gain comfort whether this long-term supply picture is reliable," Lu said.
Many say it will be. Electric Power Research Institute recently forecast coal's share of the power market will shrink to 38 percent by 2030, with gas and alternatives' shares growing. That's considerably less than the latest EIA forecast, which puts coal-fired generation at 45.7 percent in 2030.
"Nothing is going to dominate like coal does today," said Revis James, director of EPRI's Energy Technology Assessment Center.
Powering Ontario's Growth accelerates clean electricity, pairing solar, wind, and hydro with energy storage, efficiency investments, and new nuclear, including SMRs, to meet rising demand and net-zero goals while addressing supply planning across the province.
Key Points
Ontario's clean energy plan adds renewables, storage, efficiency, and nuclear to meet rising electricity demand.
✅ Over $1B for energy-efficiency programs through 2030+
✅ Largest clean power procurement in Canadian history
✅ Mix of solar, wind, hydro, storage, nuclear, and SMRs
Energy Minister Todd Smith has announced a new plan that outlines the actions the government is taking to address the province's growing demand for electricity.
The government is investing over a billion dollars in "energy-efficiency programs" through 2030 and beyond, Smith said in Windsor.
Experts at Ontario's Independent Electricity System recommended the planning start early to meet demand they predict will require the province to be able to generate 88,000 megawatts (MW) in 20 years.
"That means all of our current supply ... would need to double to meet the anticipated demand by 2050," he said during the announcement.
"While we may not need to start building today, government and those in the energy sector need to start planning immediately, so we have new clean, zero emissions projects ready to go when we need them."
The project is called Powering Ontario's Growth and will advance new clean energy generation from a number of sources, including solar, hydroelectric and wind.
Smith made the announcement at Hydro One's Keith Transmission Station.
He said the new planned procurement of green power will pair well with recent energy storage procurements, so that power generated by solar panels, for example, can be stored and injected into the system when needed.
NDP Opposition Leader Marit Stiles said Monday's announcement lacks specifics.
"It's light on details, including key questions of cost, climate impact, waste management and financial risk," said Stiles.
"Ford's Conservatives should be playing catch-up after undermining clean energy in their first term. Instead, they're offering generalities and a vague sense of what they might do."
The Green Party criticized the move Monday afternoon, noting that clean, affordable electricity remains a key Ontario election issue today.
"Ontario is facing an energy crunch – and the Ford government is making it worse by choosing more expensive, dirtier options," said MPP for Guelph Mike Schreiner in the statement.
He said Premier Doug Ford has "grossly" mismanaged the province's energy supply by cancelling 750 renewable energy projects and slashing efficiency programs.
"Now, faced with an opportunity to become a leader in a world that's rapidly embracing renewable energy, this government has chosen to funnel taxpayer dollars into polluting fossil gas plants and expensive new nuclear that will take decades to come online," said Schreiner.
Smith announced last week the plan for three more small modular reactors at the site of the Darlington nuclear power plant. The province also shared its intention to add a third nuclear generating station to Bruce Power near Kincardine.
"With this backwards approach, the Ford government is squandering a once-in-a-generation opportunity to make Ontario a global leader in attracting investment dollars and creating better jobs in the trillion-dollar clean energy sector," said Schreiner.
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.
Australia Clean Energy Target drives renewables in the National Electricity Market, with RepuTex modelling and the Finkel Review showing lower wholesale prices and emissions as gas generators set prices less often under ambitious targets.
Key Points
Policy boosting low emissions generation to cut electricity emissions and lower wholesale prices across Australia.
✅ Ambitious targets lower wholesale prices through added generation
✅ RepuTex modelling shows renewables displace costly gas peakers
✅ Finkel Review suggests CET cuts emissions and boosts reliability
The more ambitious a clean energy target is, the lower Australian wholesale electricity prices will be, according to new modelling by energy analysis firm RepuTex.
The Finkel review, released last month recommended the government introduce a clean energy target (CET), which it found would cut emissions from the national electricity market and put downward pressure on both wholesale and retail prices, aligning with calls to favor consumers over generators in market design.
The Finkel review only modelled a CET that would cut emissions from the electricity sector by 28% below 2005 levels by 2030. But all available analysis has demonstrated that such a cut would not be enough to meet Australia’s overall emissions reductions made as part of the Paris agreement, which themselves were too weak to help meet the central aim of that agreement – to keep global warming to “well below 2C”.
RepuTex modelled the effect of a CET that cut emissions from the electricity sector by 28% – like that modelled in the Finkel Review – as well as one it said was consistent with 2C of global warming, which would cut emissions from electricity by 45% below 2005 levels by 2030.
It found both scenarios caused wholesale prices to drop significantly compared to doing nothing, despite IEA warnings on falling energy investment that could lead to shortages, with the more ambitious scenario resulting in lower wholesale prices between 2025 and 2030.
In the “business as usual scenario”, RepuTex found wholesale prices would hover roughly around the current price of $100 per MWh.
Under a CET that reduced electricity emissions by 28%, prices would drop to under $40 around 2023, and then rise to nearly $60 by 2030.
The more ambitious CET had a broadly similar effect on wholesale prices. But RepuTex found it would drive prices down a little slower, but then keep them down for longer, stabilising at about $40 to $50 for most of the 2020s.
It found a CET would drive prices down by incentivising more generation into the market. The more ambitious CET would further suppress prices by introducing more renewable energy, resulting in expensive gas generators less often being able to set the price of electricity in the wholesale market, a dynamic seen with UK natural gas price pressures recently.
The downward pressure of a CET on wholesale prices was more dramatic in the RepuTex report than in Finkel’s own modelling. But that was largely because, as Alan Finkel himself acknowledged, the estimates of the costs of renewable energy in the Finkel review modelling were conservative.
Speaking at the National Press Club, Finkel said: “We were conservative in our estimates of wind and large-scale solar generator prices. Indeed, in recent months the prices for wind generation have already come in lower than what we modelled.”
The RepuTex modelling also found the economics of the national electricity market no longer supported traditional baseload generation – such as coal power plants that were unable to respond flexibly to demand, with debates over power market overhauls in Alberta underscoring similar tensions – and so they would not be built without the government distorting the market.
“With a premium placed on flexible generation that can ramp up or down, baseload only generation – irrespective of how clean or dirty it is – is likely to be too inflexible to compete in Australia’s future electricity system,” the report said.
“In this context, renewable energy remains attractive to the market given it is able to deliver energy reliability, with no emissions, at low cost prices, with clean grid and battery trends in Canada informing the shift for policymakers. This affirms that renewables are a lay down misere to out-compete traditionally fossil-fuel sources in Australia for the foreseeable future.”
BC Hydro Electricity Imports shape CleanBC claims as Powerex trades cross-border electricity, blending hydro with coal and gas supplies, affecting emissions, grid carbon intensity, and how electric vehicles and households assess "clean" power.
Key Points
Powerex buys power for BC Hydro, mixing hydro with coal and gas, shifting emissions and affecting CleanBC targets.
✅ Powerex trades optimize price, not carbon intensity
✅ Imports can include coal- and gas-fired generation
✅ Emissions affect EV and CleanBC decarbonization claims
British Columbians naturally assume they’re using clean power when they fire up holiday lights, juice up a cell phone or plug in a shiny new electric car.
That’s the message conveyed in advertisements for the CleanBC initiative launched by the NDP government, amid indications that residents are split on going nuclear according to a survey, which has spent $3.17 million on a CleanBC “information campaign,” including almost $570,000 for focus group testing and telephone town halls, according to the B.C. finance ministry.
“We’ll reduce air pollution by shifting to clean B.C. energy,” say the CleanBC ads, which feature scenic photos of hydro reservoirs. “CleanBC: Our Nature. Our Power. Our Future.”
Yet despite all the bumph, British Columbians have no way of knowing if the electricity they use comes from a coal-fired plant in Alberta or Wyoming, a nuclear plant in Washington, a gas-fired plant in California or a hydro dam in B.C.
Here’s why.
BC Hydro’s wholly-owned corporate subsidiary, Powerex Corp., exports B.C. power when prices are high and imports power from other jurisdictions when prices are low.
In 2018, for instance, B.C. imported more electricity than it exported — not because B.C. has a power shortage (it has a growing surplus due to the recent spate of mill closures and the commissioning of two new generating stations in B.C.) but because Powerex reaps bigger profits when BC Hydro slows down generators to import cheaper power, especially at night.
“B.C. buys its power from outside B.C., which we would argue is not clean,” says Martin Mullany, interim executive director for Clean Energy BC.
“A good chunk of the electricity we use is imported,” Mullany says. “In reality we are trading for brown power” — meaning power generated from conventional ‘dirty’ sources such as coal and gas.
Wyoming, which generates almost 90 per cent of its power from coal, was among the 12 U.S. states that exported power to B.C. last year. (Notably, B.C. did not export any electricity to Wyoming in 2018.)
Utah, where coal-fired power plants produce 70 per cent of the state’s energy amid debate over the costs of scrapping coal-fired electricity, and Montana, which derives about 55 per cent of its power from coal, also exported power to B.C. last year.
So did Nebraska, which gets 63 per cent of its power from coal, 15 per cent from nuclear plants, 14 per cent from wind and three per cent from natural gas.
Coal is responsible for about 23 per cent of the power generated in Arizona, another exporter to B.C., while gas produces about 44 per cent of the electricity in that state.
In 2017, the latest year for which statistics are available, electricity imports to B.C. totalled just over 1.2 million tonnes of carbon dioxide emissions, according to the B.C. environment ministry — roughly the equivalent of putting 255,000 new cars on the road, using the U.S. Environmental Protection Agency’s calculation of 4.71 tonnes of annual carbon emissions for a standard passenger vehicle.
These figures far outstrip the estimated local and upstream emissions from the contested Woodfibre LNG plant in Squamish that is expected to release annual emissions equivalent to 170,000 new cars on the road.
Import emissions cast a new light on B.C.’s latest “milestone” announcement that 30,000 electric cars are now among 3.7 million registered vehicles in the province.
BC Electric Vehicles Announcement Horgan Heyman Mungall Weaver
In November of 2018 the province announced a new target to have all new light-duty cars and trucks sold to be zero-emission vehicles by the year 2040. Photo: Province of B.C. / Flickr
“Making sure more of the vehicles driven in the province are powered by BC Hydro’s clean electricity is one of the most important steps to reduce [carbon] pollution,” said the November 28 release from the energy ministry, noting that electrification has prompted a first call for power in 15 years from BC Hydro.
Mullany points out that Powerex’s priority is to make money for the province and not to reduce emissions.
“It’s not there for the cleanest outcome,” he said. “At some time we have to step up to say it’s either the money or the clean power, which is more important to us?”
Electricity bought and sold by little-known, unregulated Powerex
These transactions are money-makers for Powerex, an opaque entity that is exempt from B.C.’s freedom of information laws.
Little detailed information is available to the public about the dealings of Powerex, which is overseen by a board of directors comprised of BC Hydro board members and BC Hydro CEO and president Chris O’Reilly.
According to BC Hydro’s annual service plan, Powerex’s net income ranged from $59 million to $436 million from 2014 to 2018.
“We will never know the true picture. It’s a black box.”
Powerex’s CEO Tom Bechard — the highest paid public servant in the province — took home $939,000 in pay and benefits last year, earning $430,000 of his executive compensation through a bonus and holdback based on his individual and company performance.
“The problem is that all of the trade goes on at Powerex and Powerex is an unregulated entity,” Mullany says.
“We will never know the true picture. It’s a black box.”
In 2018, Powerex exported 8.7 million megawatt hours of electricity to the U.S. for a total value of almost $570 million, according to data from the Canada Energy Regulator. That same year, Powerex imported 9.6 million megawatt hours of electricity from the U.S. for almost $360 million.
Powerex sold B.C.’s publicly subsidized power for an average of $87 per megawatt hour in 2018, according to the Canada Energy Regulator. It imported electricity for an average of $58 per megawatt hour that year.
In an emailed statement in response to questions from The Narwhal, BC Hydro said “there can be a need to import some power to meet our electricity needs” due to dam reservoir fluctuations during the year and from year to year.
‘Impossible’ to determine if electricity is from coal or wind power
Emissions associated with electricity imports are on average “significantly lower than the emissions of a natural gas generating plant because we mostly import electricity from hydro generation and, increasingly, power produced from wind and solar,” BC Hydro claimed in its statement.
But U.S. energy economist Robert McCullough says there’s no way to distinguish gas and coal-fired U.S. power exports to B.C. from wind or hydro power, noting that “electrons lack labels.”
Similarly, when B.C. imports power from Alberta, where generators are shifting to gas and 48.5 per cent of electricity production is coal-fired and 38 per cent comes from natural gas, there’s no way to tell if the electricity is from coal, wind or gas, McCullough says.
“It really is impossible to make that determination.”
Wyoming Gilette coal pits NASA
The Gillette coal pits in Wyoming, one of the largest coal-producers in the U.S. Photo: NASA Earth Observatory
Neither the Canada Energy Regulator nor Statistics Canada could provide annual data on electricity imports and exports between B.C. and Alberta.
But you can watch imports and exports in real time on this handy Alberta website, which also lists Alberta’s power sources.
In 2018, California, Washington and Oregon supplied considerably more power to B.C. than other states, according to data from Canada Energy Regulator.
Washington, where about one-quarter of generated power comes from fossil fuels, led the pack, with more than $339 million in electricity exports to B.C.
California, which still gets more than half of its power from gas-fired plants even though it leads the U.S. in renewable energy with substantial investments in wind, solar and geothermal, was in second place, selling about $18.4 million worth of power to B.C.
And Oregon, which produces about 43 per cent of its power from natural gas and six per cent from coal, exported about $6.2 million worth of electricity to B.C. last year.
By comparison, Nebraska’s power exports to B.C. totalled about $1.6 million, Montana’s added up to $1.3 million, Nevada’s were about $706,000 and Wyoming’s were about $346,000.
Clean electrons or dirty electrons?
Dan Woynillowicz, deputy director of Clean Energy Canada, which co-chaired the B.C. government’s Climate Solutions and Clean Growth Advisory Council, says B.C. typically exports power to other jurisdictions during peak demand.
Gas-fired plants and hydro power can generate electricity quickly, while coal-fired power plants take longer to ramp up and wind power is variable, Woynillowicz notes.
“When you need power fast and there aren’t many sources that can supply it you’re willing to pay more for it.”
Woynillowicz says “the odds are high” that B.C. power exports are displacing dirty power.
CCUS in the U.S. Power Sector drives investments as DOE grants, 45Q tax credits, and EPA carbon rules spur carbon capture, geologic storage, and utilization, while debates persist over costs, transparency, reliability, and emissions safeguards.
Key Points
CCUS captures CO2 from power plants for storage or use, backed by 45Q tax credits, DOE funding, and EPA carbon rules.
✅ DOE grants and 45Q credits aim to de-risk project economics.
✅ EPA rules may require capture rates to meet emissions limits.
✅ Transparency and MRV guard against tax credit abuse.
New public and private funding, including DOE $110M for CCUS announced recently, and expected strong federal power plant emissions reduction standards have accelerated electricity sector investments in carbon capture, utilization and storage,’ or CCUS, projects but some worry it is good money thrown after bad.
CCUS separates carbon from a fossil fuel-burning power plant’s exhaust through carbon capture methods for geologic storage or use in industrial and other applications, according to the Department of Energy. Fossil fuel industry giants like Calpine and Chevron are looking to take advantage of new federal tax credits and grant funding for CCUS to manage potentially high costs in meeting power plant performance requirements, amid growing investor pressure for climate reporting, including new rules, expected from EPA soon, on reducing greenhouse gas emissions from existing power plants.
Power companies have “ambitious plans” to add CCUS to power plants, estimated to cause 25% of U.S. CO2 emissions. As a result, the power sector “needs CCUS in its toolkit,” said DOE Office of Fossil Energy and Carbon Management Assistant Secretary Brad Crabtree. Successful pilots and demonstrations “will add to investor confidence and lead to more deployment” to provide dispatchable clean energy, including emerging CO2-to-electricity approaches for power system reliability after 2030,| he added.
But environmentalists and others insist potentially cost-prohibitive CCUS infrastructure, including CO2 storage hub initiatives, must still prove itself effective under rigorous and transparent federal oversight.
“The vast majority of long-term U.S. power sector needs can be met without fossil generation, and better options are being deployed and in development,” Sierra Club Senior Advisor, Strategic Research and Development, Jeremy Fisher, said, pointing to carbon-free electricity investments gaining momentum in the market. CCUS “may be needed, but without better guardrails, power sector abuses of federal funding could lead to increased emissions and stranded fossil assets,” he added.
New DOE CCUS project grants, an increased $85 per metric ton, or tonne, federal 45Q tax credit, and the forthcoming EPA power plant carbon rules and the federal coal plan will do for CCUS what similar policies did for renewables, advocates and opponents agreed. But controversial past CCUS performance and tax credit abuses must be avoided with transparent reporting requirements for CO2 capture, opponents added.
Hydro-Québec $185-Billion Clean Energy Plan accelerates hydroelectric upgrades, wind power expansion, solar and battery storage, pumped storage, and 5,000 km transmission lines to decarbonize Quebec, boost grid resilience, and attract bond financing and Indigenous partnerships.
Key Points
Plan to grow renewables, harden the grid, and fund Quebec's decarbonization with major investments.
✅ $110B new generation, $50B grid resilience by 2035
✅ Triple wind, add solar, batteries, and pumped storage
✅ 5,000 km lines, bond financing, Indigenous partnerships
Hydro-Québec is in the preliminary stages of dialogue with various financiers and potential collaborators to strategize the implementation of a $185-billion initiative aimed at transitioning Quebec away from fossil fuel dependency.
As the leading hydroelectric power producer in Canada, Hydro-Québec is set to allocate up to $110 billion by 2035 towards the development of new clean energy facilities, building on its hydropower capacity expansion in recent years, with an additional $50 billion dedicated to enhancing the resilience of its power grid, as revealed in a strategy announced last November. The remainder of the projected expenditure will cover operational costs.
This ambitious initiative has garnered significant interest from the financial sector, with the province's recent electricity for industrial projects also drawing attention, as noted by CEO Michael Sabia during a conference call with journalists where the utility's annual financial outcomes were discussed. Sabia reported receiving various proposals to fund the initiative, though specific partners were not disclosed. He expressed confidence in securing the necessary capital for the project's success.
Sabia highlighted three immediate strategies to increase power output: identifying new sites for hydroelectric projects while upgrading turbines at existing facilities, such as the Carillon Generating Station upgrade now underway for enhanced efficiency, expanding wind energy production threefold, and promoting energy conservation among consumers to optimize current power usage.
Additionally, Hydro-Québec aims to augment its solar and battery energy production and is planning to establish a pumped-storage hydroelectric plant to support peak demand periods. The utility also intends to construct 5,000 kilometers of new transmission lines, address Quebec-to-U.S. transmission constraints where feasible, and is set to double its capital expenditure to $16 billion annually, a significant increase from the investment levels during the James Bay hydropower project construction in the 1970s and 1980s.
To fund part of this expansive plan, Hydro-Québec will continue to access the bond market, having issued $3.7 billion in notes to investors last year despite facing several operational hurdles due to adverse weather conditions.
For the year 2023, Hydro-Québec reported a net income of $3.3 billion, marking a 28% decrease from the previous year's record of $4.56 billion. Factors such as insufficient snow cover, reduced spring runoff, and higher temperatures resulted in lower water levels in reservoirs, leading to a reduction in power exports and a $547-million decrease in external market sales compared to the previous year.
The utility experienced its lowest export volume in a decade but managed to leverage hedging strategies to secure 10.3 cents per kWh for exported power to markets including New Brunswick via recent NB Power agreements that expand interprovincial deliveries, nearly twice the average market rate, through forward contracts that cover up to half of its export volume for about a year in advance.
The success of Sabia's plan will partly depend on the cooperation of First Nations communities, as the proposed infrastructure developments are likely to traverse their ancestral territories. Relationships with some communities are currently tense, exemplified by the Innu of Labrador's $4-billion lawsuit against Hydro-Québec for damages related to land flooding for reservoir construction, and broader regional tensions in Newfoundland and Labrador that persist in the power sector.
Sabia has committed to involving First Nations and Inuit communities as partners in clean energy ventures, offering them ongoing financial benefits rather than one-off settlements, a principle he refers to as "economic reconciliation."
Recently, the Quebec government reached an agreement with the Innu of Pessamit, pledging $45 million to support local community development. This agreement outlines solutions for managing a nearby hydropower reservoir, such as the La Romaine complex in the region, and includes commitments for wind energy development.
Sabia is optimistic about building stronger, more positive relationships with various Indigenous communities, anticipating significant progress in the coming months and viewing this year as a potential milestone in transforming these relationships for the better.
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