Coal plants ordered to reduce emissions

Labor National Electricity Market Reform aims to rebalance NEM rules, support a fair-dinkum clean energy target, enable renewable zones, bolster storage and grid reliability, empower households, and unlock CEFC investment via the Finkel review.

Key Points

Labor's plan to overhaul NEM rules for households, clean energy targets, renewable zones, storage, and CEFC investment.

✅ Revises NEM rules to curb big generators' market power

✅ Backs a clean energy target informed by the Finkel review

✅ Expands renewable zones, storage, and CEFC finance

Australia's Labor leader Bill Shorten has called for significant changes to the rules governing the national electricity market, saying they are biased in favour of big energy generators, leaving households worse off even with measures like a WA electricity bill credit in place.

He said the national electricity market (NEM) rules are designed to help the big companies recoup the money they spent on purchasing government assets, a dynamic echoed in debates like a Calgary market overhaul dispute unfolding in Canada, rather than encourage households to generate their own power, and they need to change faster to adapt to consumer needs.

His comments hint at a possible overhaul of the NEM’s governance structure under a future Labor government, because the current rule-making process is too cumbersome and slow, with suggested rules changes taking years to be introduced.

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Labor had promoted a similar idea in the lead-up to the 2016 election, with its call for an electricity modernization review, but now the Finkel review has been released it would be used to guide such a review.

In a speech to the Australian Financial Review’s National Energy Summit in Sydney on Monday, Shorten recommitted Labor to negotiating a “fair-dinkum” clean energy target with the Turnbull government, amid modelling that a strong clean energy target can lower electricity prices, saying “it’s time to put away the weapons of the climate change wars” and work together to find a way forward.

He said the media and business can all share the blame for Australia’s lost decade of energy policy development, with examples abroad showing how leadership steers change, such as in Alberta where Kenney's influence on power policy has been pronounced, but “we need to stop spoiling for a fight and start seeking a solution”.

“The scare campaigns and hyper-partisanship that got Australia into this mess, will not get us out of it,” he will say.

“That’s why, a bit over four months ago, before the chief scientist released his report, I wrote to the prime minister offering an olive branch.

“I said Labor was prepared to move from our preferred position of an emissions intensity scheme and negotiate a fair-dinkum clean energy target.

“That offer was greeted with some cynicism in the media. But let me be crystal clear – I made that offer in good faith, and that offer still stands.”

Shorten said Australia needs to resolve the current “gas crisis” and do more to drive investment in renewable energy that delivers more reliable electricity, a priority underscored by the IEA's warning that falling global energy investment risks shortages, and if Labor wins the next election it will organise Australia into a series of renewable energy zones – as recommended by the chief scientist, Alan Finkel – that identify wind, solar, pumped hydro and geothermal resources, and connect them to the existing network.

“These zones would be based on both existing generation and storage in the area – and the potential for future development,” he said.

Australia's politics only barrier to clean energy system, report finds

“Identifying these zones – from eastern Queensland, north-east New South Wales, west Victoria, the Eyre Peninsula in South Australia and the entire state of Tasmania – will also plant a flag for investors – signalling future sites for job-creating projects.”

Shorten also said Labor will free up the Clean Energy Finance Corporation to invest in more generation and more storage.

“Under Labor, the return benchmark for the CEFC was set at the weighted average of the Australian government bond rate.

“Under this government, it was initially increased to the weighted average plus 4% to 5% and is now set at the average plus 3% to 4%.

“Setting the return benchmark too high defeats the driving purpose of the CEFC and it holds back the crucial investment Australia needs – right now – in new generation and storage.

“This is why a Labor government would restore the original benchmark return of the Clean Energy Finance Corporation, to invest in more generation, more storage and more jobs.”

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Saskatchewan Solar Net Metering Program lets rooftop solar users offset at retail rate while earning 7.5 cents/kWh credits for excess energy; rebates are removed, SaskPower balances grid costs with a 100 kW cap.

Key Points

An updated SaskPower plan crediting rooftop solar at 7.5 cents/kWh, offsetting usage at retail rate, without rebates.

✅ Excess energy credited at 7.5 cents/kWh

✅ Offsets on-site use at retail electricity rates

✅ Up to 100 kW generation; no program capacity cap

Saskatchewan has unveiled a new program that credits electricity customers for generating their own solar power, but it won’t pay as much as an older program did or reimburse them with rebates for their costs to buy and install equipment.

The new net metering program takes effect Nov. 1, and customers will be able to use solar to offset their own power use at the retail rate, similar to UK households' right to sell power in comparable schemes, though program details differ.

But they will only get 7.5 cents per kilowatt hour credit on their bills for excess energy they put back into the grid, as seen in Duke Energy payment changes in other jurisdictions, rather than the 14 cents in the previous program.

Dustin Duncan, the minister responsible for Crown-owned SaskPower, says the utility had to consider the interests of people wanting to use rooftop solar and everyone else who doesn’t have or can’t afford the panels, who he says would have to make up for the lost revenue.

Duncan says the idea is to create a green energy option, with wind power gains highlighting broader competitiveness, while also avoiding passing on more of the cost of the system to people who just cannot afford solar panels of their own.

Customers with solar panels will be allowed to generate up to 100 kilowatts of power against their bills.

“It’s certainly my hope that this is going to provide sustainability for the industry, as illustrated by Alberta's renewable surge creating jobs, that they have a program that they can take forward to their potential customers, while at the same time ensuring that we’re not passing onto customers that don’t have solar panels more cost to upkeep the grid,” Duncan said Tuesday.

Saskatchewan NDP leader Ryan Meili said he believes eliminating the rebate and cutting the excess power credit will kill the province’s solar energy, a concern consistent with lagging solar demand in Canada in recent national reports, he said.

“(Duncan) essentially made it so that any homeowner who wants to put up panels would take up to twice as long to pay it back, which effectively prices everybody in the small part of the solar production industry — the homeowners, the farms, the small businesses, the small towns — out of the market,” Meili said.

The province’s old net metering program hit its 16 megawatt capacity ahead of schedule, forcing the program to shut down, while disputes like the Manitoba Hydro solar lawsuit have raised questions about program management elsewhere. It also had a rebate of 20 per cent of the cost of the system, but that rebate has been discontinued.

The new net metering program won’t have any limit on program capacity, or an end date.

According to Duncan, the old program would have had a net negative impact to SaskPower of about $54 million by 2025, but this program will be much less — between $4 million and $5 million.

Duncan said other provinces either have already or are in the process of moving away from rebates for solar equipment, including Nova Scotia's proposed solar charge and similar reforms, and away from the one-to-one credits for power generation.

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Electric Vehicle Grid Integration aligns EV charging with grid capacity using smart charging, time-of-use rates, V2G, and demand response to reduce peak load, enable renewable energy, and optimize infrastructure planning.

Key Points

Aligning EV charging with grid needs via smart charging, TOU pricing, and V2G to balance load and support renewables.

✅ Time-of-use rates shift charging to off-peak hours

✅ Smart charging responds to real-time grid signals

✅ V2G turns fleets into distributed energy storage

When Seattle City Light unveiled five new electric vehicle charging stations last month in an industrial neighborhood south of downtown, the electric utility wasn't just offering a new spot for drivers to fuel up. It also was creating a way for the service to figure out how much more power it might need as electric vehicles catch on.

Seattle aims to have nearly a third of its residents driving electric vehicles by 2030. Washington state is No. 3 in the nation in per capita adoption of plug-in cars, behind California and Hawaii. But as Washington and other states urge their residents to buy electric vehicles — a crucial component of efforts to reduce carbon emissions — they also need to make sure the electric grid can handle it amid an accelerating EV boom nationwide.

The average electric vehicle requires 30 kilowatt hours to travel 100 miles — the same amount of electricity an average American home uses each day to run appliances, computers, lights and heating and air conditioning.

An Energy Department study found that increased electrification across all sectors of the economy could boost national consumption by as much as 38 percent by 2050, in large part because of electric vehicles. The environmental benefit of electric cars depends on the electricity being generated by renewables.

So far, states predict they will be able to sufficiently boost power production. But whether electric vehicles will become an asset or a liability to the grid largely depends on when drivers charge their cars.

Electricity demand fluctuates throughout the day; demand is higher during daytime hours, peaking in the early evening. If many people buy electric vehicles and mostly try to charge right when they get home from work — as many now do — the system could get overloaded or force utilities to deliver more electricity than they are capable of producing.

In California, for example, the worry is not so much with the state’s overall power capacity, but rather with the ability to quickly ramp up production and maintain grid stability when demand is high, said Sandy Louey, media relations manager for the California Energy Commission, in an email. About 150,000 electric vehicles were sold in California in 2018 — 8 percent of all state car sales.

The state projects that electric vehicles will consume 5.4 percent of the state’s electricity, or 17,000 gigawatt hours, by 2030.

Responding to the growth in electric vehicles will present unique challenges for each state. A team of researchers from the University of Texas at Austin estimated the amount of electricity that would be required if every car on the road transitioned to electric. Wyoming, for instance, would need to nudge up its electricity production only 17 percent, while Maine would have to produce 55 percent more.

Efficiency Maine, a state trust that oversees energy efficiency and greenhouse gas reduction programs, offers rebates for the purchase of electric vehicles, part of state efforts to incentivize growth.

“We’re certainly mindful that if those projections are right, then there will need to be more supply,” said Michael Stoddard, the program’s executive director. “But it’s going to unfold over a period of the next 20 years. If we put our minds to it and plan for it, then we should be able to do it.”

A November report sponsored by the Energy Department found that there has been almost no increase in electricity demand nationwide over the past 10 years, while capacity has grown an average of 12 gigawatts per year (1 GW can power more than a half-million homes). That means energy production could climb at a similar rate and still meet even the most aggressive increase in electric vehicles, with proper planning.

Charging during off-peak hours would allow not only many electric vehicles to be added to the roads but also utilities to get more use out of power plants that run only during the limited peak times through improved grid coordination and flexible demand.

Seattle City Light and others are looking at various ways to promote charging during ideal times. One method is time-of-day rates. For the Seattle chargers unveiled last month, users will pay 31 cents per kilowatt hour during peak daytime hours and 17 cents during off-peak hours. The utility will monitor use at its charging stations to see how effective the rates are at shifting charging to more favorable times.

The utility also is working on a pilot program to study charging behavior at home. And it is partnering with customers such as King County Metro that are electrifying large vehicle fleets, including growing electric truck fleets that will demand significant power, to make sure they have both the infrastructure and charging patterns to integrate smoothly.

“Traditionally, our utility approach is to meet the load demand,” said Emeka Anyanwu, energy innovation and resources officer for Seattle City Light.

Instead, he said, the utility is working with customers to see whether they can use existing assets without the need for additional investment.

Numerous analysts say that approach is crucial.

“Even if there’s an overall increase in consumption, it really matters when that occurs,” said Sally Talberg, head of the Michigan Public Service Commission, which oversees the state’s utilities. “The encouragement of off-peak charging and other technology solutions that could come to bear could offset any negative impact.”

One of those solutions is smart charging, a system in which vehicles are plugged in but don’t charge until they receive a signal from the grid that demand has tapered off a sufficient amount. This is often paired with a lower rate for drivers who use it. Several smart-charging pilot programs are being conducted by utilities, although they have not yet been phased in widely, amid ongoing debates over charging control among manufacturers and utilities.

In many places, the increased electricity demand from electric vehicles is seen as a benefit to utilities and rate payers. In the Northwest, electricity consumption has remained relatively stagnant since 2000, despite robust population growth and development. That’s because increasing urbanization and building efficiency have driven down electricity needs.

Electric vehicles could help push electricity consumption closer to utilities’ capacity for production. That would bring in revenue for the providers, which would help defray the costs for maintaining that capacity, lowering rates for all customers.

“Having EV loads is welcome, because it’s environmentally cleaner and helps sustain revenues for utilities,” said Massoud Jourabchi, manager of economic analysis for the Northwest Power and Conservation Council, which develops power plans for the region.

Colorado also is working to promote electric cars, with the aim of putting 940,000 on the road by 2030. The state has adopted California’s zero-emission vehicles mandate, which requires automakers to reach certain market goals for their sales of cars that don’t burn fossil fuels, while extending tax credits for the purchase of such cars, investing in charging stations and electrifying state fleets.

Auto dealers have opposed the mandate, saying it infringes on consumer freedom.

“We think it should be a customer choice, a consumer choice and not a government mandate,” said Tim Jackson, president and chief executive of the Colorado Automobile Dealers Association.

Jackson also said that there’s not yet a strong consumer appetite for electric vehicles, meaning that manufacturers that fail to sell the mandated number of emission-free vehicles would be required to purchase credits, which he thinks would drive up the price of their other models.

Republicans in the state have registered similar concerns, saying electric vehicle adoption should take place based on market forces, not state intervention.

Many in the utility community are excited about the potential for electric cars to serve as mobile energy storage for the grid. Vehicle-to-grid technology, known as V2G, would allow cars charging during the day to take on surplus power from renewable energy sources.

Then, during peak demand times, electric vehicles would return some of that stored energy to the grid. As demand tapers off in the evening, the cars would be able to recharge.

In practice, V2G technology could be especially beneficial if used by heavy-duty fleets, such as school buses or utility vehicles. Those fleets would have substantial battery storage and long periods where they are idle, such as evenings and weekends — and even longer periods such as summer and the holiday season when school is out. The batteries on a bus, Jourabchi said, could store as much as 10 times the electricity needed to power a home for a day.

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BC Energy Debate: Nuclear Power and LNG divides British Columbia, as a new survey weighs zero-emission clean energy, hydroelectric capacity, the Site C dam, EV mandates, energy security, rising costs, and blackout risks.

Key Points

A BC-wide debate on power choices balancing nuclear, LNG, hydro, costs, climate goals, EVs, and grid reliability.

✅ Survey: 43% support nuclear, 40% oppose in BC

✅ 55% back LNG expansion, led by Southern BC

✅ Hydro at 90%; Site C adds 1,100 MW by 2025

There is a long-term need to produce more electricity to meet population and economic growth needs and, in particular, create new clean energy sources, with two new BC generating stations recently commissioned contributing to capacity.

Increasingly, in the worldwide discourse on climate change, nuclear power plants are being touted as a zero-emission clean energy source, with Ontario exploring large-scale nuclear to expand capacity, and a key solution towards meeting reduced emissions goals. New technological advancements could make nuclear power far safer than existing plant designs.

When queried on whether British Columbia should support nuclear power for electricity generation, respondents in a new province-wide survey by Research Co. were split, with 43% in favour and 40% against.

Levels of support reached 46% in Metro Vancouver, 41% in the Fraser Valley, 44% in Southern BC, 39% in Northern BC, and 36% on Vancouver Island.

The closest nuclear power plant to BC is the Columbia Generating Station, located in southern Washington State.

The safe use of nuclear power came to the forefront following the 2011 Fukushima nuclear disaster when the most powerful earthquake ever recorded in Japan triggered a large tsunami that damaged the plant’s emergency generators. Japan subsequently shut off many of its nuclear power plants and increased its reliance on fossil fuel imports, but in recent years there has been a policy reversal to restart shuttered nuclear plants to provide the nation with improved energy security.

Over the past decade, Germany has also been undergoing a transition away from nuclear power. But in an effort to replace Russian natural gas, Germany is now using more coal for power generation than ever before in decades, while Ontario’s electricity outlook suggests a shift to a dirtier mix, and it is looking to expand its use of liquefied natural gas (LNG).

Last summer, German chancellor Olaf Scholz told the CBC he wants Canada to increase its shipments of LNG gas to Europe. LNG, which is greener compared to coal and oil, is generally seen as a transitionary fuel source for parts of the world that currently depend on heavy polluting fuels for power generation.

When the Research Co. survey asked BC residents whether they support the further development of the province’s LNG industry, including LNG electricity demand that BC Hydro says justifies Site C, 55% of respondents were supportive, while 29% were opposed and 17% undecided.

Support for the expansion of the LNG is highest in Southern BC (67%), followed by the Fraser Valley (56%), Metro Vancouver (also 56%), Northern BC (55%), and Vancouver Island (41%).

A larger proportion of BC residents are against any idea of the provincial government moving to ban the use of natural gas for stoves and heating in new buildings, with 45% opposed and 39% in support.

Significant majorities of BC residents are concerned that energy costs could become too expensive, and a report on coal phase-outs underscores potential cost and effectiveness concerns, with 84% expressing concern for residents and 66% for businesses. As well, 70% are concerned that energy shortages could lead to measures such as rationing and rolling blackouts.

Currently, about 90% of BC’s electricity is produced by hydroelectric dams, but this fluctuates throughout the year — at times, BC imports coal- and gas-generated power from the United States when hydro output is low.

According to BC Hydro’s five-year electrification plan released in September 2021, it is estimated BC has a sufficient supply of clean electricity only by 2030, including the capacity of the Site C dam, which is slated to open in 2025. The $16 billion dam will have an output capacity of 1,100 megawatts or enough power for the equivalent of 450,000 homes.

The provincial government’s strategy for pushing vehicles towards becoming dependent on the electrical grid also necessitates a reliable supply of power, prompting BC Hydro’s first call for power in 15 years to prepare for electrification. Most BC residents support the provincial government’s requirement for all new car and passenger truck sales to be zero-emission by 2035, with 75% supporting the goal and 21% opposed.
 

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Nunavut electricity rate increase sees QEC raise domestic electricity rates 6.6% over two years, affecting customer rates, base rates, subsidies, and kWh overage charges across communities, with public housing exempt and territory-wide pricing denied.

Key Points

A 6.6% QEC hike over 2018-2019, affecting customer rates, subsidies, and kWh overage; public housing remains exempt.

✅ 3.3% on May 1, 2018; 3.3% on Apr 1, 2019

✅ Subsidy caps: 1,000 kWh Oct-Mar; 700 kWh Apr-Sep

✅ Territory-wide base rate denied; public housing exempt

Ahead of the Nunavut government's approval of the general rate increase for the Qulliq Energy Corporation, many Nunavummiut wondered how the change would impact their electricity bills.

QEC's request for a 6.6-per-cent increase was approved by the government last week. The increase will be spread out over two years, a pattern similar to BC Hydro's two-year rate plan, with the first increase (3.3 per cent) effective May 1, 2018. The remaining 3.3 per cent will be applied on April 1, 2019.

Public housing units, however, are exempt from the government's increase altogether.

The power corporation also asked for a territory-wide rate, so every community would pay the same base rate (we'll go over specific terms in a minute if you're not familiar with them). But that request was denied, even as Manitoba Hydro scaled back increases next year, and QEC will now take the next two years reassessing each community's base rate.

#google#

So, what does this mean for your home's power bill? Well, there's a few things you need to know, which we'll get to in a second.

But in essence, as long as you don't go over the government-subsidized monthly electricity usage limit, you're paying an extra 3.61 cents per kilowatt hour (kWh).

To be clear, we're talking about non-government domestic rates — basically, private homeowners — and those living in a government-owned unit but pay for their own power.

The basics

First, some quick terminology. The "base rate" term we're going to use (and used above) in this story refers to the community rate. As in, what QEC charges customers in every community. The "customer rate" is the rate customers actually pay, after the government's subsidy.

The first thing you need to know is everyone in Nunavut starts off by paying the same customer rate, unlike jurisdictions using a price cap to limit spikes.

That's because the government subsidizes electricity costs, and that subsidy is different in every community, because the base rate is different.

For example, Iqaluit's new base rate after the 3.3 per cent increase (remember, the 6.6 per cent is being applied over two years) is 56.69 cents per kWh, while Kugaaruk's base rate rose to 112.34 cents per kWh. Those, by the way, are the territory's lowest and highest respective base rates.

However, customers in both Iqaluit and Kugaaruk will each now pay 28.35 cents per kWh because, remember, the government subsidizes the base rates in every community.

Now, remember earlier we mentioned a "government-subsidized monthly electricity usage limit?" That's where customers in various communities start to pay different amounts.

As simply as we can explain it, the government will only cover so much electricity usage in a month, in every household.

Between October and March, the government will subsidize the first 1,000 kilowatt hours, and only 700 kilowatt hours from April to September. QEC says the average Nunavut home will use about 500 kilowatt hours every month over the course of a year.

But if your household goes over that limit, you're at the mercy of your community's base rate for any extra electricity you use. Homes in Kugaaruk in December, for instance, will have to pay that 122.34 cents for every extra kilowatt hour it uses, while homes in Iqaluit only have to pay 56.69 cents per kWh for its extra electricity.

That's where many Nunavummiut have criticized the current rate structure, because smaller communities are paying more for their extra costs than larger communities.

QEC had hoped — as it had asked for — to change the structure so every community pays the same base rate. So regardless of if people go over their electricity usage limits for the government subsidy, everyone would pay the same overage rates.

But the government denied that request.

New rate is actually lower

The one thing we should highlight, however, is the new rate after the increase is actually lower than what customers were paying in 2014.

For the past seven months, customers have been getting power from QEC at a discount, whereas Newfoundland customers began paying for Muskrat Falls during the same period, to different effect.

That's because when QEC sets its rates, it does so based on global oil price forecasts. Since 2014, the price of oil worldwide has slumped, and so QEC was able to purchase it at less than it had anticipated.

When that happens, and QEC makes more than $1 million within a six month period thanks to the lower oil prices, it refunds the excess profits back to customers through a discount on electricity base rates — a mechanism similar to a lump-sum credit used elsewhere — the government subsidy, however, doesn't change so the savings are passed on directly to customers.

Now, the 6.6 per cent increase to electricity rates, is actually being applied to the discounted base rate from the last seven months.

So again, while customers are paying more than they have been for the last seven months, it's lower than what they were paying in 2014.

Lastly, to be clear, all the figures used in this story are only for domestic non-government rates. Commercial rates and changes have not been explored in this story, given the differences in subsidy and rate application.

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ATCO Electric administrative penalty underscores an Alberta Utilities Commission probe into a sole-sourced First Nation contract, Jasper transmission line overpayments, and nondisclosure to ratepayers, sparked by a whistleblower and pending settlement approval.

Key Points

A $31M AUC settlement over alleged overpayment, sole-sourcing, and nondisclosure tied to a Jasper transmission line.

✅ $31M administrative penalty; AUC settlement pending approval

✅ Sole-sourced First Nation contract to protect related ATCO deal

✅ Overpayment concealed when seeking recovery from ratepayers

Regulated Alberta utility ATCO Electric has agreed to pay a $31 million administrative penalty after an Alberta Utilities Commission utilities watchdog investigation found it deliberately overpaid a First Nation group for work on a new transmission line, and then failed to disclose the reasons for it when it applied to be reimbursed by ratepayers for the extra cost.

An agreed statement of facts contained in a settlement agreement between ATCO Electric Ltd. and the commission's enforcement staff says the company sole-sourced a contract in 2018 for work that was necessary for an electric transmission line to Jasper, Alta., even as BC Hydro marked a Site C transmission line milestone elsewhere.

The company that won the contract was co-owned by the Simpcw First Nation in Barriere, B.C., while debates over a First Nations electricity line in Ontario underscore related issues, and the agreement says one of the reasons for the sole-sourcing was that another of Calgary-based ATCO's subsidiaries had a prior deal with the First Nation for infrastructure projects that included the provision of work camps on the Trans Mountain Pipeline expansion project.

The statement of facts says ATCO Electric feared that if it didn't grant the contract to the First Nation group and instead put the work to tender, amid legal pressures such as a treaty rights challenge, the group might back out of its deal with ATCO Structures and Logistics and partner with another, non-ATCO company on the Trans Mountain work.

The agreed statement says ATCO Electric paid several million dollars more than market value for some of the Jasper line work, while a Manitoba-Minnesota line delay was being weighed in another jurisdiction, and staff attempted to conceal the reasons for the overpayment when they sought to recover the extra money from Alberta consumers.

It states the investigation was sparked by a whistleblower, and notes the agreement between the utility commission's enforcement staff and ATCO Electric must still be approved by the Alberta Utilities Commission, a process comparable to hearings that consider oral traditional evidence on interprovincial lines.

The commission must be satisfied the settlement is in the public interest, a consideration often informed by concerns from Site C opponents in other regions.

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