Infrastructure needs $15 billion annually: study

Nova Scotia Power Renewable Energy delivers 30% in 2018, led by wind power, hydroelectric and biomass, with coal and natural gas declining, as Muskrat Falls imports from Labrador target 40% renewables to cut emissions.

Key Points

It is the utility's 30% 2018 renewable mix and plan to reach 40% via Muskrat Falls while reducing carbon emissions.

✅ 18% wind, 9% hydro and tidal, 3% biomass in 2018

✅ Coal reliance fell from 76% in 2007 to 52% in 2018

✅ 58% carbon emissions cut from 2005 levels projected by 2030

Nova Scotia's private utility says it has hit a new milestone in its delivery of electricity from renewable resources, a trend highlighted by Summerside wind generation in nearby P.E.I.

Nova Scotia Power says 30 per cent of the electricity it produced in 2018 came from renewable sources such as wind power.

The utility says 18 per cent came from wind turbines, nine per cent from hydroelectric and tidal turbines and three per cent by burning biomass.

However, over half of the province's electrical generation still comes from the burning of coal or petroleum coke. Another 13 per cent come from burning natural gas and five per cent from imports, even as U.S. renewable generation hits record shares.

The utility says that since 2007, the province's reliance on coal-fired plants has dropped from 76 per cent of electricity generated to 52 per cent last year, as Prairie renewables growth accelerates nationally.

It says it expects to meet the province's legislated renewable target of 40 per cent in 2020, when it begins accessing hydroelectricity from the Muskrat Falls project in Labrador.

"We have made greener, cleaner energy a priority," utility president and CEO Karen Hutt said in a news release.

"As we continue to achieve new records in renewable electricity, we remain focused on ensuring electricity prices stay predictable and affordable for our customers, including solar customers across the province."

Nova Scotia Power also projects achieving a 58 per cent reduction in carbon emissions from 2005 levels by 2030.

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India Industrial Output Slowdown deepens as power demand slumps, IIP contracts, and electricity, manufacturing, and mining weaken; capital goods plunge while RBI rate cuts struggle to lift GDP growth, infrastructure, and fuel demand.

Key Points

A downturn where IIP contracts as power demand, manufacturing, mining, and capital goods fall despite RBI rate cuts.

✅ IIP fell 4.3% in Sep, worst since Feb 2013.

✅ Power demand dropped for a third month, signaling weak industry.

✅ Capital goods output plunged 20.7%, highlighting weak investment.

India's power demand fell at the fastest pace in at least 12 years in October, signalling a continued decline in the industrial output, mirroring how China's power demand dropped when plants were shuttered, according to government data. Electricity has about 8% weighting in the country's index for industrial production.

India needs electricity to fuel its expanding economy and has at times rationed coal supplies when demand surged, but a third decline in power consumption in as many months points to tapering industrial activity in a nation that aims to become a $5 trillion economy by 2024.

India's industrial output fell at the fastest pace in over six years in September, adding to a series of weak indicators that suggests that the country’s economic slowdown is deep-rooted and interest rate cuts alone may not be enough to revive growth.

Annual industrial output contracted 4.3% in September, government data showed on Monday. It was the worst performance since a 4.4% contraction in February 2013, according to Refinitiv data.

Analysts polled by Reuters had forecast industrial output to fall 2% for the month.

“A contraction of industrial production by 4.3% in September is serious and indicative of a significant slowdown as both investment and consumption demand have collapsed,” said Rupa Rege Nitsure, chief economist of L&T Finance Holdings.

The industrial output figure is the latest in a series of worrying economic data in Asia's third largest economy, which is also the world's third-largest electricity producer as well.

Economists say that weak series of data could mean economic growth for July-September period will remain near April-June quarter levels of 5%, which was a six-year low, and some analysts argue for rewiring India's electricity to bolster productivity. The Indian government is likely to release April-September economic growth figures by the end of this month.

Subdued inflation and an economic slowdown have prompted the Reserve Bank of India (RBI) to cut interest rates by a total of 135 basis points this year, while coal and electricity shortages eased in recent months.

“These are tough times for the RBI, as it cannot do much about it but there will be pressures on it to act ...Blunt tools like monetary policy may not be effective anymore,” Nitsure said.

Data showed in September mining sector fell 8.5%, while manufacturing and electricity fell 3.9% and 2.6% respectively, even as imported coal volumes rose during April-October. Capital goods output during the month fell 20.7%, indicating sluggish demand.

“IIP (Index of Industrial Production) growth in October 2019 is also likely to be in negative territory and only since November 2019 one can expect mild IIP expansion, said Devendra Kumar Pant, Chief Economist and Senior Director, Public Finance, India Ratings & Research (Fitch Group).

Infrastructure output, which comprises eight main sectors, in September showed a contraction of 5.2%, the worst in 14 years, even as global daily electricity demand fell about 15% during pandemic lockdowns.

India's fuel demand fell to its lowest in more than two years in September, with consumption of diesel to its lowest levels since January 2017. Diesel and gasoline together make up over 7.4% of the IIP weightage.

In 2019/20 India's fuel demand — also seen as an indicator of economic and industrial activity — is expected to post the slowest growth in about six years.

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Renewables' Impact on US Wholesale Electricity Prices is clear: DOE analysis shows wind and solar, capacity gains, and natural gas lowering rates, shifting daily patterns, and triggering occasional negative pricing in PJM and ERCOT.

Key Points

DOE data show wind and solar lower wholesale prices, reshape price curves, and cause negative pricing in markets.

✅ Natural gas price declines remain the largest driver of cheaper power

✅ Wind and solar shift seasonal and time-of-day price patterns

✅ Negative wholesale prices appear near high wind and solar output

One of the arguments that's consistently been raised against doing anything about climate change is that it will be expensive. On the more extreme end of the spectrum, there have been dire warnings about plunging standards of living due to skyrocketing electricity prices. The plunging cost of renewables like solar cheaper than gas has largely silenced these warnings, but a new report from the Department of Energy suggests that, even earlier, renewables were actually lowering the price of electricity in the United States.

Plunging prices
The report focuses on wholesale electricity prices in the US. Note that these are distinct from the prices consumers actually pay, which includes taxes, fees, payments to support the grid that delivers the electricity, and so on. It's entirely possible for wholesale electricity prices to drop even as consumers end up paying more, and market reforms determine how those changes are passed through. That said, large changes in the wholesale price should ultimately be passed on to consumers to one degree or another.

The Department of Energy analysis focuses on the decade between 2008 and 2017, and it includes an overall analysis of the US market, as well as large individual grids like PJM and ERCOT and, finally, local prices. The decade saw a couple of important trends: low natural gas prices that fostered a rapid expansion of gas-fired generators and the rapid expansion of renewable generation that occurred concurrently with a tremendous drop in price of wind and solar power.

Much of the electricity generated by renewables in this time period would be more expensive than that generated by wind and solar installed today. Not only have prices for the hardware dropped, but the hardware has improved in ways that provide higher capacity factors, meaning that they generate a greater percentage of the maximum capacity. (These changes include things like larger blades on wind turbines and tracking systems for solar panels.) At the same time, operating wind and solar is essentially free once they're installed, so they can always offer a lower price than competing fossil fuel plants.

With those caveats laid out, what does the analysis show? Almost all of the factors influencing the wholesale electricity price considered in this analysis are essentially neutral. Only three factors have pushed the prices higher: the retirement of some plants, the rising price of coal, and prices put on carbon, which only affect some of the regional grids.

In contrast, the drop in the price of natural gas has had a very large effect on the wholesale power price. Depending on the regional grid, it's driven a drop of anywhere from $7 to $53 per megawatt-hour. It's far and away the largest influence on prices over the past decade.

Regional variation and negative prices
But renewables have had an influence as well. That influence has ranged from roughly neutral to a cost reduction of $2.2 per MWh in California, largely driven by solar. While the impact of renewables was relatively minor, it is the second-largest influence after natural gas prices, and the data shows that wind and solar are reducing prices rather than increasing them.

The reports note that renewables are influencing wholesale prices in other ways, however. The growth of wind and solar caused the pattern of seasonal price changes to shift in areas of high wind and solar, as seen with solar reshaping prices in Northern Europe as daylight hours and wind patterns shift with the seasons. Similarly, renewables have a time-of-day effect for similar reasons, helping explain why the grid isn't 100% renewable today, which also influences the daily timing price changes, something that's not an issue with fossil fuel power.

A map showing the areas where wholesale electricity prices have gone negative, with darker colors indicating increased frequency.
Enlarge / A map showing the areas where wholesale electricity prices have gone negative, with darker colors indicating increased frequency.

US DOE
One striking feature of areas where renewable power is prevalent is that there are occasional cases in which an oversupply of renewable energy produces negative electricity prices in the wholesale market. (In the least-surprising statement in the report, it concludes that "negative prices in high-wind and high-solar regions occurred most frequently in hours with high wind and solar output.") In most areas, these negative prices are rare enough that they don't have a significant influence on the wholesale price.

That's not true everywhere, however. Areas on the Great Plains see fairly frequent negative prices, and they're growing in prevalence in areas like California, the Southwest, and the northern areas of New York and New England, while negative prices in France have been observed in similar conditions. In these areas, negative wholesale prices near solar plants have dropped the overall price by 3%. Near wind plants, that figure is 6%.

None of this is meant to indicate that there are no scenarios where expanded renewable energy could eventually cause wholesale prices to rise. At sufficient levels, the need for storage, backup plants, and grid management could potentially offset their low costs, a dynamic sometimes referred to as clean energy's dirty secret by analysts. But it's clear we have not yet reached that point. And if the prices of renewables continue to drop, then that point could potentially recede fast enough not to matter.

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ITER Nuclear Fusion advances tokamak magnetic confinement, heating deuterium-tritium plasma with superconducting magnets, targeting net energy gain, tritium breeding, and steam-turbine power, while complementing laser inertial confinement milestones for grid-scale electricity and 2025 startup goals.

Key Points

ITER Nuclear Fusion is a tokamak project confining D-T plasma with magnets to achieve net energy gain and clean power.

✅ Tokamak magnetic confinement with high-temp superconducting coils

✅ Deuterium-tritium fuel cycle with on-site tritium breeding

✅ Targets net energy gain and grid-scale, low-carbon electricity

It sounds like the stuff of dreams: a virtually limitless source of energy that doesn’t produce greenhouse gases or radioactive waste. That’s the promise of nuclear fusion, often described as the holy grail of clean energy by proponents, which for decades has been nothing more than a fantasy due to insurmountable technical challenges. But things are heating up in what has turned into a race to create what amounts to an artificial sun here on Earth, one that can provide power for our kettles, cars and light bulbs.

Today’s nuclear power plants create electricity through nuclear fission, in which atoms are split, with next-gen nuclear power exploring smaller, cheaper, safer designs that remain distinct from fusion. Nuclear fusion however, involves combining atomic nuclei to release energy. It’s the same reaction that’s taking place at the Sun’s core. But overcoming the natural repulsion between atomic nuclei and maintaining the right conditions for fusion to occur isn’t straightforward. And doing so in a way that produces more energy than the reaction consumes has been beyond the grasp of the finest minds in physics for decades.

But perhaps not for much longer. Some major technical challenges have been overcome in the past few years and governments around the world have been pouring money into fusion power research as part of a broader green industrial revolution under way in several regions. There are also over 20 private ventures in the UK, US, Europe, China and Australia vying to be the first to make fusion energy production a reality.

“People are saying, ‘If it really is the ultimate solution, let’s find out whether it works or not,’” says Dr Tim Luce, head of science and operation at the International Thermonuclear Experimental Reactor (ITER), being built in southeast France. ITER is the biggest throw of the fusion dice yet.

Its $22bn (£15.9bn) build cost is being met by the governments of two-thirds of the world’s population, including the EU, the US, China and Russia, at a time when Europe is losing nuclear power and needs energy, and when it’s fired up in 2025 it’ll be the world’s largest fusion reactor. If it works, ITER will transform fusion power from being the stuff of dreams into a viable energy source.

Constructing a nuclear fusion reactor
ITER will be a tokamak reactor – thought to be the best hope for fusion power. Inside a tokamak, a gas, often a hydrogen isotope called deuterium, is subjected to intense heat and pressure, forcing electrons out of the atoms. This creates a plasma – a superheated, ionised gas – that has to be contained by intense magnetic fields.

The containment is vital, as no material on Earth could withstand the intense heat (100,000,000°C and above) that the plasma has to reach so that fusion can begin. It’s close to 10 times the heat at the Sun’s core, and temperatures like that are needed in a tokamak because the gravitational pressure within the Sun can’t be recreated.

When atomic nuclei do start to fuse, vast amounts of energy are released. While the experimental reactors currently in operation release that energy as heat, in a fusion reactor power plant, the heat would be used to produce steam that would drive turbines to generate electricity, even as some envision nuclear beyond electricity for industrial heat and fuels.

Tokamaks aren’t the only fusion reactors being tried. Another type of reactor uses lasers to heat and compress a hydrogen fuel to initiate fusion. In August 2021, one such device at the National Ignition Facility, at the Lawrence Livermore National Laboratory in California, generated 1.35 megajoules of energy. This record-breaking figure brings fusion power a step closer to net energy gain, but most hopes are still pinned on tokamak reactors rather than lasers.

In June 2021, China’s Experimental Advanced Superconducting Tokamak (EAST) reactor maintained a plasma for 101 seconds at 120,000,000°C. Before that, the record was 20 seconds. Ultimately, a fusion reactor would need to sustain the plasma indefinitely – or at least for eight-hour ‘pulses’ during periods of peak electricity demand.

A real game-changer for tokamaks has been the magnets used to produce the magnetic field. “We know how to make magnets that generate a very high magnetic field from copper or other kinds of metal, but you would pay a fortune for the electricity. It wouldn’t be a net energy gain from the plant,” says Luce.

One route for nuclear fusion is to use atoms of deuterium and tritium, both isotopes of hydrogen. They fuse under incredible heat and pressure, and the resulting products release energy as heat

The solution is to use high-temperature, superconducting magnets made from superconducting wire, or ‘tape’, that has no electrical resistance. These magnets can create intense magnetic fields and don’t lose energy as heat.

“High temperature superconductivity has been known about for 35 years. But the manufacturing capability to make tape in the lengths that would be required to make a reasonable fusion coil has just recently been developed,” says Luce. One of ITER’s magnets, the central solenoid, will produce a field of 13 tesla – 280,000 times Earth’s magnetic field.

The inner walls of ITER’s vacuum vessel, where the fusion will occur, will be lined with beryllium, a metal that won’t contaminate the plasma much if they touch. At the bottom is the divertor that will keep the temperature inside the reactor under control.

“The heat load on the divertor can be as large as in a rocket nozzle,” says Luce. “Rocket nozzles work because you can get into orbit within minutes and in space it’s really cold.” In a fusion reactor, a divertor would need to withstand this heat indefinitely and at ITER they’ll be testing one made out of tungsten.

Meanwhile, in the US, the National Spherical Torus Experiment – Upgrade (NSTX-U) fusion reactor will be fired up in the autumn of 2022, while efforts in advanced fission such as a mini-reactor design are also progressing. One of its priorities will be to see whether lining the reactor with lithium helps to keep the plasma stable.

Choosing a fuel
Instead of just using deuterium as the fusion fuel, ITER will use deuterium mixed with tritium, another hydrogen isotope. The deuterium-tritium blend offers the best chance of getting significantly more power out than is put in. Proponents of fusion power say one reason the technology is safe is that the fuel needs to be constantly fed into the reactor to keep fusion happening, making a runaway reaction impossible.

Deuterium can be extracted from seawater, so there’s a virtually limitless supply of it. But only 20kg of tritium are thought to exist worldwide, so fusion power plants will have to produce it (ITER will develop technology to ‘breed’ tritium). While some radioactive waste will be produced in a fusion plant, it’ll have a lifetime of around 100 years, rather than the thousands of years from fission.

At the time of writing in September, researchers at the Joint European Torus (JET) fusion reactor in Oxfordshire were due to start their deuterium-tritium fusion reactions. “JET will help ITER prepare a choice of machine parameters to optimise the fusion power,” says Dr Joelle Mailloux, one of the scientific programme leaders at JET. These parameters will include finding the best combination of deuterium and tritium, and establishing how the current is increased in the magnets before fusion starts.

The groundwork laid down at JET should accelerate ITER’s efforts to accomplish net energy gain. ITER will produce ‘first plasma’ in December 2025 and be cranked up to full power over the following decade. Its plasma temperature will reach 150,000,000°C and its target is to produce 500 megawatts of fusion power for every 50 megawatts of input heating power.

“If ITER is successful, it’ll eliminate most, if not all, doubts about the science and liberate money for technology development,” says Luce. That technology development will be demonstration fusion power plants that actually produce electricity, where advanced reactors can build on decades of expertise. “ITER is opening the door and saying, yeah, this works – the science is there.”

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British Columbia Green Grid Constraints underscore BC Hydro's rising imports, peak demand, electrification, hydroelectric variability, and transmission bottlenecks, challenging renewable energy expansion, energy security, and CleanBC targets across industry and zero-emission transportation.

Key Points

They are capacity and supply limits straining B.C.'s clean electrification, driving imports and risking reliability.

✅ Record 25% imports in FY2024 raise emissions and costs

✅ Peak demand and transmission limits delay new connections

✅ Drought reduces hydro output; diversified generation needed

British Columbia's ambitious green energy initiatives are encountering significant hurdles due to a strained electrical grid and increasing demand, with a EV demand bottleneck adding pressure. The province's commitment to reducing carbon emissions and transitioning to renewable energy sources is being tested by the limitations of its current power infrastructure.

Rising Demand and Dwindling Supply

In recent years, B.C. has experienced a surge in electricity demand, driven by factors such as population growth, increased use of electric vehicles, and the electrification of industrial processes. However, the province's power supply has struggled to keep pace, and one study projects B.C. would need to at least double its power output to electrify all road vehicles. In fiscal year 2024, BC Hydro imported a record 13,600 gigawatt hours of electricity, accounting for 25% of the province's total consumption. This reliance on external sources, particularly from fossil-fuel-generated power in the U.S. and Alberta, raises concerns about energy security and sustainability.

Infrastructure Limitations

The current electrical grid is facing capacity constraints, especially during peak demand periods, and regional interties such as a proposed Yukon connection are being discussed to improve reliability. A report from the North American Electric Reliability Corporation highlighted that B.C. could be classified as an "at-risk" area for power generation as early as 2026. This assessment underscores the urgency of addressing infrastructure deficiencies to ensure a reliable and resilient energy supply.

Government Initiatives and Investments

In response to these challenges, the provincial government has outlined plans to expand the electrical system. Premier David Eby announced a 10-year, $36-billion investment to enhance the grid's capacity, including grid development and job creation measures to support local economies. The initiative focuses on increasing electrification, upgrading high-voltage transmission lines, refurbishing existing generating facilities, and expanding substations. These efforts aim to meet the growing demand and support the transition to clean energy sources.

The Role of Renewable Energy

Renewable energy sources, particularly hydroelectric power, play a central role in B.C.'s energy strategy. However, the province's reliance on hydroelectricity has its challenges. Drought conditions in recent years have led to reduced water levels in reservoirs, impacting the generation capacity of hydroelectric plants. This variability underscores the need for a diversified energy mix, with options like a hydrogen project complementing hydro, to ensure a stable and reliable power supply.

Balancing Environmental Goals and Energy Needs

B.C.'s commitment to environmental sustainability is evident in its policies, such as the CleanBC initiative, which aims to phase out natural gas heating in new homes by 2030 and achieve 100% zero-emission vehicle sales by 2035, supported by networks like B.C.'s Electric Highway that expand charging access. While these goals are commendable, they place additional pressure on the electrical grid. The increased demand from electric vehicles and electrified heating systems necessitates a corresponding expansion in power generation and distribution infrastructure.

British Columbia's green energy ambitions are commendable and align with global efforts to combat climate change. However, achieving these goals requires a robust and resilient electrical grid capable of meeting the increasing demand for power. The province's reliance on external power sources and the challenges posed by climate variability highlight the need for strategic investments in infrastructure and a diversified energy portfolio, guided by BC Hydro review recommendations to keep electricity affordable. By addressing these challenges proactively, B.C. can pave the way for a sustainable and secure energy future.

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BC Utilities Commission Site C Dam Questions press BC Hydro on geotechnical risks, stability issues, cost overruns, oversight gaps, seeking transparency for ratepayers and clarity on contracts, mitigation, and the powerhouse and spillway foundations.

Key Points

Inquiry seeking explanations from BC Hydro on geotechnical risks, costs, timelines and oversight for Site C.

✅ Timeline of studies, monitoring, and mitigation actions

✅ Rationale for contracts, costs, and right bank construction

✅ Implications for ratepayers, oversight, and project stability

The watchdog B.C. Utilities Commission has sent BC Hydro 70 questions about the troubled Site C dam, asking when geotechnical risks were first identified and when the project’s assurance board was first made aware of potential issues related to the dam’s stability. 

“I think they’ve come to the conclusion — but they don’t say it — that there’s been a cover-up by BC Hydro and by the government of British Columbia,” former BC Hydro CEO Marc Eliesen told The Narwhal. 

On Oct. 21, The Narwhal reported that two top B.C. civil servants, including the senior bureaucrat who prepares Site C dam documents for cabinet, knew in May 2019 that the project faced serious geotechnical problems due to its “weak foundation” and the stability of the dam was “a significant risk.” 

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“They [the civil servants] would have reported to their ministers and to the government in general,” said Eliesen, who is among 18 prominent Canadians calling for a halt to Site C work until an independent team of experts can determine if the geotechnical problems can be resolved and at what cost.  

“It’s disingenuous for Premier [John] Horgan to try to suggest, ‘Well, I just found out about it recently.’ If that’s the case, he should fire the public servants who are representing the province.” 

The public only found out about significant issues with the Site C dam at the end of July, when BC Hydro released overdue reports saying the project faces unknown cost overruns, schedule delays and, even as it achieved a transmission line milestone earlier, such profound geotechnical troubles that its overall health is classified as ‘red,’ meaning it is in serious trouble. 

“The geotechnical challenges have been there all these years.”

The Site C dam is the largest publicly funded infrastructure project in B.C.’s history. If completed, it will flood 128 kilometres of the Peace River and its tributaries, forcing families from their homes and destroying Indigenous gravesites, hundreds of protected archeological sites, some of Canada’s best farmland and habitat for more than 100 species vulnerable to extinction.

Eliesen said geotechnical risks were a key reason BC Hydro’s board of directors rejected the project in the early 1990s, when he was at the helm of BC Hydro.

“The geotechnical challenges have been there all these years,” said Eliesen, who is also the former Chair and CEO of Ontario Hydro, where Ontario First Nations have urged intervention on a critical electricity line, the former Chair of Manitoba Hydro and the former Chair and CEO of the Manitoba Energy Authority.

Elsewhere, a Manitoba Hydro line to Minnesota has faced potential delays, highlighting broader grid planning challenges.

The B.C. Utilities Commission is an independent watchdog that makes sure ratepayers — including BC Hydro customers — receive safe and reliable energy services, as utilities adapt to climate change risks, “at fair rates.”

The commission’s questions to BC Hydro include 14 about the “foundational enhancements” BC Hydro now says are necessary to shore up the Site C dam, powerhouse and spillways. 

The commission is asking BC Hydro to provide a timeline and overview of all geotechnical engineering studies and monitoring activities for the powerhouse, spillway and dam core areas, and to explain what specific risk management and mitigation practices were put into effect once risks were identified.

The commission also wants to know why construction activities continued on the right bank of the Peace River, where the powerhouse would be located, “after geotechnical risks materialized.” 

It’s asking if geotechnical risks played a role in BC Hydro’s decision in March “to suspend or not resume work” on any components of the generating station and spillways.

The commission also wants BC Hydro to provide an itemized breakdown of a $690 million increase in the main civil works contract — held by Spain’s Acciona S.A. and the South Korean multinational conglomerate Samsung C&T Corp. — and to explain the rationale for awarding a no-bid contract to an unnamed First Nation and if other parties were made aware of that contract. 

Peace River Jewels of the Peace Site C The Narwhal
Islands in the Peace River, known as the ‘jewels of the Peace’ will be destroyed for fill for the Site C dam or will be submerged underwater by the dam’s reservoir, a loss that opponents are sharing with northerners in community discussions. Photo: Byron Dueck

B.C. Utilities Commission chair and CEO David Morton said it’s not the first time the commission has requested additional information after receiving BC Hydro’s quarterly progress reports on the Site C dam. 

“Our staff reads them to make sure they understand them and if there’s anything in then that’s not clear we go then we do go through this, we call it the IR — information request — process,” Morton said in an interview.

“There are things reported in here that we felt required a little more clarity, and we needed a little more understanding of them, so that’s why we asked the questions.”

The questions were sent to BC Hydro on Oct. 23, the day before the provincial election, but Morton said the commission is extraordinarily busy this year and that’s just a coincidence. 

“Our resources are fairly strained. It would have been nice if it could have been done faster, it would be nice if everything could be done faster.” 

“These questions are not politically motivated,” Morton said. “They’re not political questions. There’s no reason not to issue them when they’re ready.”

The commission has asked BC Hydro to respond by Nov. 19.

Read more: Top B.C. government officials knew Site C dam was in serious trouble over a year ago: FOI docs

Morton said the independent commission’s jurisdiction is limited because the B.C. government removed it from oversight of the project. 

The commission, which would normally determine if a large dam like the Site C project is in the public’s financial interest, first examined BC Hydro’s proposal to build the dam in the early 1980s.

After almost two years of hearings, including testimony under oath, the commission concluded B.C. did not need the electricity. It found the Site C dam would have negative social and environmental impacts and said geothermal power should be investigated to meet future energy needs. 

The project was revived in 2010 by the BC Liberal government, which touted energy from the Site C dam as a potential source of electricity for California and a way to supply B.C.’s future LNG industry with cheap power.

Not willing to countenance another rejection from the utilities commission, the government changed the law, stripping the commission of oversight for the project. The NDP government, which came to power in 2017, chose not to restore that oversight.

“The approval of the project was exempt from our oversight,” Morton said. “We can’t come along and say ‘there’s something we don’t like about what you’re doing, we’re going to stop construction.’ We’re not in that position and that’s not the focus of these questions.” 

But the commission still retains oversight for the cost of construction once the project is complete, Morton said. 

“The cost of construction has to be recovered in [hydro] rates. That means BC Hydro will need our approval to recover their construction cost in rates, and those are not insignificant amounts, more than $10.7 billion, in all likelihood.” 

In order to recover the cost from ratepayers, the commission needs to be satisfied BC Hydro didn’t spend more money than necessary on the project, Morton said. 

“As you can imagine, that’s not a straight forward review to do after the fact, after a 10-year construction project or whatever it ends up being … so we’re using these quarterly reports as an opportunity to try to stay on top of it and to flag any areas where we think there may be areas we need to look into in the future.”

The price tag for the Site C dam was $10.7 billion before BC Hydro’s announcement at the end of July — a leap from $6.6 billion when the project was first announced in 2010 and $8.8 billion when construction began in 2015. 

Eliesen said the utilities commission should have been asking tough questions about the Site C dam far earlier. 

“They’ve been remiss in their due diligence activities … They should have been quicker in raising questions with BC Hydro, rather than allowing BC Hydro to be exceptionally late in submitting their reports.” 

BC Hydro is late in filing another Site C quarterly report, covering the period from April 1 to June 30. 

The quarterly reports provide the B.C. public with rare glimpses of a project that international hydro expert Harvey Elwin described as being more secretive than any hydro project he has encountered in five decades working on large dams around the world, including in China.

Read more: Site C dam secrecy ‘extraordinary’, international hydro construction expert tells court proceeding

Morton said the commission could have ordered regular reporting for the Site C project if it had its previous oversight capability.

“Then we would have had the ability to follow up and ultimately order any delinquent reports to be filed. In this circumstance, they are being filed voluntarily. They can file it as late as they choose. We don’t have any jurisdiction.” 

In addition to the six dozen questions, the commission has also filed confidential questions with BC Hydro. Morton said confidential information could include things such as competitive bid information. “BC Hydro itself may be under a confidentiality agreement not to disclose it.” 

With oversight, the commission would also have been able to drill down into specific project elements,  Morton said. 

“We would have wanted to ensure that the construction followed what was approved. BC Hydro wouldn’t have the ability to make significant changes to the design and nature of the project as they went along.”

BC Hydro has been criticized for changing the design of the Site C dam to an L-shape, which Eliesen said “has never been done anywhere in the world for an earthen dam.” 

Morton said an empowered commission could have opted to hold a public hearing about the design change and engage its own technical consultants, as it did in 2017 when the new NDP government asked it to conduct a fast-tracked review of the project’s economics. 

Construction Site C Dam
A recent report by a U.S. energy economist found cancelling the Site C dam project would save BC Hydro customers an initial $116 million a year, with increasing savings growing over time. Photo: Garth Lenz / The Narwhal

The commission’s final report found the dam could cost more than $12 billion, that BC Hydro had a historical pattern of overestimating energy demand and that the same amount of energy could be produced by a suite of renewables, including wind and proposed pumped storage such as the Meaford project, for $8.8 billion or less. 

The NDP government, under pressure from construction trade unions, opted to continue the project, refusing to disclose key financial information related to its decision. 

When the geotechnical problems were revealed in July, the government announced the appointment of former deputy finance minister Peter Milburn as a special Site C project advisor who will work with BC Hydro and the Site C project assurance board to examine the project and provide the government with independent advice.

Eliesen said BC Hydro and the B.C. government should never have allowed the recent diversion of the Peace River to take place given the tremendous geotechnical challenges the project faces and its unknown cost and schedule for completion. 

“It’s a disgrace and scandalous,” he said. “You can halt the river diversion, but you’ve got another four or five years left in construction of the dam. What are you going to do about all the cement you’ve poured if you’ve got stability problems?”

He said it’s counter-productive to continue with advice “from the same people who have been wrong, wrong, wrong,” without calling in independent global experts to examine the geotechnical problems. 

“If you stop construction, whether it takes three or six months, that’s the time that’s required in order to give yourself a comfort level. But continuing to do what you’ve been doing is not the right course. You should have to sit back.”

Eliesen said it reminded him of the Pete Seeger song Waist Deep in the Big Muddy, which tells the story of a captain ordering his troops to keep slogging through a river because they will soon be on dry ground. After the captain drowns, the troops turn around.

“It’s a reflection of the fact that if you don’t look at what’s new, you just keep on doing what you’ve been doing in the past and that, unfortunately, is what’s happening here in this province with this project.”

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