Premier warns NDP, Greens that delaying Site C dam could cost $600M


Proposed Site C Dam graphic

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Site C Project Delay raises BC Hydro costs as Christy Clark warns $600 million impact; NDP and Greens seek BCUC review of the hydroelectric dam on the Peace River, challenging evictions and construction contracts.

 

Key Points

A potential slowdown of B.C.'s Site C dam, risking $600M overruns, evictions, and schedule delays pending a BCUC review.

✅ Clark warns $600M cost if river diversion slips a year

✅ NDP-Green seek BCUC review; request to pause contracts, evictions

✅ Peace River hydro dam; schedule critical to budget, ratepayers

 

Premier Christy Clark is warning the NDP and Greens that delaying work on the Site C project in northeast British Columbia could cost taxpayers $600 million.

NDP Leader John Horgan wrote to BC Hydro last week asking it to suspend the evictions of two homeowners and urging it not to sign any new contracts on the $8.6-billion hydroelectric dam until a new government has gained the confidence of the legislature.

But Clark says in letters sent to Horgan and Green Leader Andrew Weaver on Tuesday that the evictions are necessary as part of a road and bridge construction project that are needed to divert a river in September 2019.

Any delay could postpone the diversion by a year and cost taxpayers hundreds of millions of dollars, she says.

“With a project of this size and scale, keeping to a tight schedule is critical to delivering a completed project on time and on budget,” she says. “The requests contained in your letter are not without consequences to the construction schedule and ultimately have financial ramifications to ratepayers.”

The premier has asked Horgan and Weaver to reply by Saturday on whether they still want to put the evictions on hold.

She also asks whether they want the government to issue a “tools down” request to BC Hydro on other decisions that she says are essential to maintaining the budget and construction schedule.

An agreement between the NDP and Green party was signed last week that would allow the New Democrats to form a minority government, ousting Clark's Liberals.

The agreement includes a promise to refer the Site C project to the B.C. Utilities Commission to determine its economic viability.

Some analysts argue that better B.C.-Alberta power integration could improve climate outcomes and market flexibility.

But Clark says the project is likely to progress past the “point of no return” before a review can be completed.

Clark did not define what she meant by “point of no return,” nor did she explain how she reached the $600-million figure. Her press secretary Stephen Smart referred questions to BC Hydro, which did not immediately respond.

During prolonged drought conditions, BC Hydro has had to adapt power generation across the province, affecting planning assumptions.

In a written response to Clark, Weaver says before he can comment on her assertions he requires access to supporting evidence, including signed contracts, the project schedule and potential alternative project timelines.

“Please let me express my disappointment in how your government is choosing to proceed with this project,” he says.

“Your government is turning a significant capital project that potentially poses massive economic risks to British Columbians into a political debate rather than one informed by evidence and supported by independent analysis.”

The dam will be the third on the Peace River, flooding an 83-kilometre stretch of valley, and local First Nations, landowners and farmers have fiercely opposed the project.

Construction began two years ago.

A report written by University of British Columbia researchers in April argued it wasn't too late to press pause on the project and that the electricity produced by Site C won't be fully required for nearly a decade after it's complete.

 

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Vancouver adopts 100 per cent EV-ready policy

Vancouver 100% EV-Ready Policy mandates EV charging in new multi-unit residential buildings, expands DC fast charging, and supports zero-emission vehicles, reducing carbon pollution and improving air quality with BC Hydro and citywide infrastructure upgrades.

 

Key Points

A city rule making new multi-unit homes EV-ready and expanding DC fast charging to accelerate zero-emission adoption.

✅ 100% EV-ready stalls in all new multi-unit residential builds

✅ Citywide DC fast charging within 10 minutes by 2021

✅ Preferential parking policies for zero-emission vehicles

 

Vancouver is now one of the first cities in North America to adopt a 100 per cent Electric Vehicle (EV)-ready policy for all new multi-unit residential buildings, aligning with B.C.'s EV expansion efforts across the province.

Vancouver City Council approved the recommendations made in the EV Ecosystem Program Update last week. The previous requirement of 20 per cent EV parking spots meant a limited number of residents had access to an outlet, reflecting charging challenges in MURBs across Canada. The actions will help reduce carbon pollution and improve air quality by increasing opportunities for residents to move away from fossil fuel vehicles.

Vancouver is also expanding charging station infrastructure across the city, and developing a preferential parking policy for zero emissions vehicles, while residents can tap EV charger rebates to support home and workplace charging. Plans are to add more DC fast charging points, which can provide up to 200 kilometres of range in an hour. The goal is to put all Vancouver residents within a 10 minute drive of a DC fast-charging station by 2021.

#google#

A DC fast charger will be installed at Science World, and the number of DC fast chargers available at Empire Fields in east Vancouver will be expanded. BC Hydro will also add DC fast chargers at their head office and in Kerrisdale, as part of a faster charging rollout across the network.

The cost of adding charging infrastructure in the construction phase of a building is much lower than retrofitting a building later on, and EV owners can access home and workplace charging rebates to offset costs, which will save residents up to $3,300 and avoid the more complex process of increasing electrical capacity in the future. Since 2014, the existing requirements have resulted in approximately 20,000 EV-ready stalls in buildings.

 

 

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UPS pre-orders 125 Tesla electric semi-trucks

UPS Tesla Electric Semi Order marks the largest pre-order of all-electric Class-8 big rigs, advancing sustainable freight logistics with lower total cost of ownership, expanded charging infrastructure support, and competitive range versus diesel trucks.

 

Key Points

UPS's purchase of 125 Tesla all-electric Class-8 semis to cut costs, emissions, and modernize long-haul freight.

✅ Largest public pre-order: 125 electric Class-8 trucks

✅ Aims lower total cost of ownership vs diesel

✅ Includes charging infrastructure consulting by Tesla

 

United Parcel Service Inc. said on Tuesday it is buying 125 Tesla Inc. all-electric semi-trucks, the largest order for the big rig so far, as the package delivery company expands its fleet of alternative-fuel vehicles, including options like the all-electric Transit cargo van now entering the market.

Tesla is trying to convince the trucking community it can build an affordable electric big rig with the range and cargo capacity to compete with relatively low-cost, time-tested diesel trucks. This is the largest public order of the big rig so far, Tesla said.

The Tesla trucks will cost around $200,000 each for a total order of about $25 million. UPS expects the semi-trucks, the big rigs that haul freight along America's highways, will have a lower total cost of ownership than conventional vehicles, which run about $120,000.

Tesla has received pre-orders from such major companies as Wal-Mart, fleet operator J.B. Hunt Transport Services Inc. and food service distributor Sysco Corp.

Prior to UPS, the largest single pre-order came from PepsiCo Inc, for 100 trucks. 

UPS said it has provided Tesla with real-world routing information as part of its evaluation of the vehicle's expected performance.

"As with any introductory technology for our fleet, we want to make sure it's in a position to succeed," Scott Phillippi, UPS senior director for automotive maintenance and engineering for international operations, told Reuters.

Phillippi said the 125 trucks will allow UPS to conduct a proper test of their abilities. He said the company was still determining their routes, but the semis will "primarily be in the United States." Tesla will provide consultation and support on charging infrastructure, as electric truck fleets will need a lot of power to operate at scale.

"We have high expectations and are very optimistic that this will be a good product and it will have firm support from Tesla to make it work," Phillippi said.

The UPS alternative fuel fleet already includes trucks propelled by electricity, natural gas, propane and other non-traditional fuels, and interest in electric mail trucks underscores how delivery fleets are evolving.

About 260,000 semis, or heavy-duty Class-8 trucks, are produced in North America annually, according to FTR, an industry economics research firm.

Including the UPS order, Tesla has at least 410 pre-orders in hand, according to a Reuters tally.

Navistar International Corp. and Volkswagen AG hope to launch a smaller, electric medium-duty truck by late 2019, while rival Daimler AG has delivered the first of a smaller range of electric trucks to customers in New York, and Volvo Trucks planned a complete range of electric trucks in Europe by 2021.

Tesla unveiled its semi last month, following earlier plans to reveal the truck in October, and expects the truck to be in production by 2019.

 

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Ontario opens first ever electric vehicle education centre in Toronto

Toronto EV Discovery Centre offers hands-on EV education, on-site test drives, and guidance on Ontario incentives, rebates, charging, and dealerships, helping drivers switch to electric vehicles and cut emissions through provincial climate programs.

 

Key Points

A public hub in Toronto for EV education, test drives, and guidance on Ontario incentives, rebates, and charging options.

✅ Free entry; neutral info on EV models and charging.

✅ On-site test drives; referrals to local dealerships.

✅ Backed by Ontario's cap-and-trade, utilities, and partners.

 

A centre where people can learn about electric vehicles and take them for a test drive has opened in Toronto, as similar EV events in Regina highlight growing public interest.

Ontario's Environment Minister Glen Murray says the Plug'n Drive Electric Vehicle Discovery Centre is considered the first of its kind and his government has pitched in $1 million to support it, alongside efforts to expand charging stations across Ontario.

Ontario's Environment Minister Glen Murray helps cut the ribbon on the first ever electric vehicle discovery centre. (CBC News)

Murray says the goal of the centre is to convince people to switch to electric vehicles in order to fight climate change, a topic gaining momentum in southern Alberta as well.

Visitors to the centre learn about how electric vehicles work and about Ontario government subsidies and rebates for electric car owners, as well as the status of the provincial charging network and infrastructure.

Visitors can test-drive vehicles from different companies and those who see something they like will receive a referral to an electric car dealership in their area.

The province hopes to have electric vehicles make up five per cent of all new vehicles sold by 2020. (Oliver Walters/CBC)

The Ontario government's Climate Change Action Plan includes a goal to have electric vehicles make up five per cent of all new vehicles sold by 2020, amid debate over whether the next wave will run on clean power in Ontario, and the discovery centre is part of that plan.

The centre is free for visitors. It's a public-private partnership funded from the provincial government's cap-and-trade revenue, with other funding from TD Bank Group, Ontario Power Generation, Power Workers' Union, Toronto Hydro and Bruce Power.

 

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California regulators weigh whether the state needs more power plants

California Natural Gas Plant Rethink signals a shift toward clean energy, renewables, distributed solar, battery storage, and grid modernization as LADWP and regulators pause repowering plans amid an electricity oversupply and rising ratepayer costs.

 

Key Points

California pauses new gas plants to assess renewables, storage, and grid solutions for reliability.

✅ LADWP delays $2.2B gas repowers to study clean alternatives

✅ CEC weighs halting Oxnard plant amid grid oversupply

✅ Distributed solar, batteries, demand response boost reliability

 

California energy officials are, for the first time, rethinking plans to build expensive natural gas power plants in the face of an electricity glut and growing use of cleaner and cheaper energy alternatives.

The Los Angeles Department of Water and Power announced Tuesday that it has put a hold on a $2.2-billion plan to rebuild several old natural gas power plants while it studies clean energy alternatives to meet electricity demands. And the California Energy Commission may decide as early as Thursday to halt a natural gas project in Ventura County.

The scrutiny comes after an investigation found that the state is operating with an oversupply of electricity, driven largely by the construction of gas-fueled generating plants, leading to higher rates as regulators consider a rate overhaul to clean the grid. The state’s power plants are on track to be able to produce at least 21% more electricity than needed by 2020, according to the Times report.

Californians are footing a $40-billion annual bill while using less electricity, paying $6.8 billion more than they did in 2008 when power use in the state was at its all-time high. Electricity consumption has since fallen and remained largely flat.

Utilities in California have been on a years-long building binge, adding new natural gas plants even as the nation’s electricity system has undergone significant change, including consumer choice reforms that are reshaping the market.

Where utilities once delivered all electrical services from huge power plants along miles of transmission lines, the industry now must consider power delivered to the electric grid not only from its own sources, but also from solar systems and batteries at homes and businesses.

At the same time, utilities have been aggressively upgrading or rebuilding their aging natural gas plants — a move critics have said is unnecessary because consumers are using less power and clean energy technology is making those plants obsolete.

The DWP and energy commission moves involve as many as seven natural gas plant projects proposed for Southern California, despite warnings about a looming shortage if capacity is retired too fast, from Oxnard to Carlsbad, at a cost of more than $6 billion.

Reiko Kerr, the DWP’s senior assistant general manager of power systems, said given the changes in the energy world, the assessment is necessary to protect ratepayer dollars and the environment.

“The whole utility paradigm has shifted,” Kerr said in an interview. “We really are doing our ratepayers a disservice by not considering all viable options.

“We’re just looking at everything,” she said. “What can help us solve this reliability, renewable and greenhouse gas challenge that we all have?”

State and local governments have felt a heightened sense of urgency to deal with climate change after President Trump decided last week to withdraw the United States from the Paris climate accord.

California already has mandated that at least 50% of the state’s electricity come from clean energy sources by 2030. Senate leader Kevin de León (D-Los Angeles) wants to increase that to 100% by 2045.

Building or overhauling natural gas plants throughout Southern California, environmentalists argue, isn’t helping achieve those goals, even as some contend the state can't keep the lights on without gas during the transition.

The DWP’s move to delay plans for the fossil fuel plants, which seemed all but set to be built, came as a surprise to clean-energy advocates, who hailed the decision.

“This is a great first step toward smart energy investments that save customers money, ensure the lights stay on and protect our health and environment,” Graciela Geyer of the Sierra Club said.

The environmental group said that if the utility had moved ahead with the $2.2-billion investment in repowering natural gas plants, it “would have blown an irreparable hole in the city and the state’s hopes to achieve 100% generation” from clean energy sources.

Angela Johnson Meszaros, attorney at EarthJustice, said in a statement: "As our city struggles with the worst smog we’ve seen in years, we appreciate that LADWP is taking some much-needed time to reassess its plans to build fossil fuel power plants. We look forward to the day that LADWP announces that we are going to power our city with 100% clean energy.”

The gas-fired generating units slated for demolition and rebuilding are at the Scattergood, Haynes and Harbor electricity plants, which range from 34 to 67 years old.

As a group, the three plants have generated less than 20% of their combined capacity since 2001. The Harbor facility has operated on the low end at just 7%, while Haynes ran on the high end at 22%.

“The old model, the old legacy clunkers, won’t get us into the future we want,” DWP’s Kerr said.

DWP staff members told the utility’s’ commissioners Tuesday that their analysis of possible alternatives would be completed no later than early 2018.

Separately, the California Energy Commission this week is evaluating whether to halt a natural gas project in Ventura County after the state’s electric grid operator offered to conduct a study of clean energy alternatives to the roughly $250-million project on Mandalay Bay in Oxnard.

An energy commission committee has been deliberating since a hearing Monday during which Southern California Edison and the project’s developer, NRG Energy, argued that a study is simply a delay tactic that probably would kill a project needed to ensure reliable electric service and to avoid blackouts during peak demand.

The California Independent System Operator, which runs the state’s electric grid, told the energy commission that it would take three to four weeks to conduct its study on alternatives to the Oxnard natural gas project.

“Here we have an actual offer by the ISO to do such an analysis,” Ellison Folk, a lawyer representing the city of Oxnard, told the energy commission as she pushed for the study. “Its view that this is an analysis worth doing is something worth taking seriously.”

Energy commission members reviewing the study proposal are scheduled to meet again Thursday to consider the offer.

The board of governors for the California Independent System Operator made the unusual offer at its May 1 meeting to conduct a eleventh-hour study of clean-energy alternatives to building a new natural gas plant.

“If we’re going to be moving forward with a gas plant at this time, in this juncture, in the context of everything that’s going on, not evaluating other alternatives that are viable, noncombustion alternatives, is a missed opportunity,” Angelina Galetiva. a commission board member, said during the May 1 meeting.

 

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How Hedge Funds May Be Undermining the Electric Car Boom

Cobalt Supply Chain for EV Batteries faces shortages as lithium-ion demand surges; Tesla gigafactories, ethical sourcing, Idaho cobalt mining, and DRC risks intensify pricing, logistics, and procurement challenges for manufacturers and investors.

 

Key Points

A network supplying cobalt for lithium-ion cathodes, strained by EV demand, ethical sourcing pressures, and DRC risk.

✅ EV growth outpaces cobalt supply, widening deficits

✅ DRC reliance drives ESG scrutiny and sourcing shifts

✅ Idaho projects and stockpiling reshape U.S. supply

 

A perfect storm is brewing in the 21st Century battery market.

More specifically, it's about what goes into those batteries - and it's not just lithium.

The other element that makes up 35 percent of the lithium-ion batteries mass produced at Tesla's Nevada gigafactory and at a dozen of other behemoths slated to come on line, is cobalt. And it's already in dramatically short supply. A part of the answer to the cobalt deficit is 100 percent American, and this little-known miner is sitting on a prime Idaho cobalt project that is one of only two that looks likely to come online in the U.S. and it's right in Tesla's backyard.

 

High-Energy Batteries Need More Cobalt Than Lithium 

If you've been focusing your investment on lithium supplies lately you've been missing the even bigger story. EV batteries need about 200 grams of refined cobalt per kilowatt of battery capacity. Power walls need more than twice that. Between March 2016 and April 2017, the cost of the cobalt in that mix nearly tripled. But it isn't just the price that's got manufacturers worried. It's the shortage of availability. Keeping gigafactories stocked with enough cobalt to run at capacity is the challenge of the decade.

Tesla, now with a $50-billion market cap, launched a $5-billion battery gigafactory in Nevada in January. By the end of 2017, it will have doubled the entire global battery production capacity. By next year, it will be producing more batteries than the rest of the world combined.

It is estimated that Tesla's gigafactory alone will need anywhere between 7,000 and 17,500 tonnes of refined cobalt every year.

Tesla used to buy its finished battery cells from Panasonic, which in turn got its processed cathode powders from a Japanese company, Sumitomo was processing its own cobalt in the Philippines. However, that facility is already running at capacity and couldn't even begin to handle Tesla's gigafactory demand. In other words, Tesla's supply chain is no longer secure. And that's just Tesla.

The EV market is fifteen times larger than it was five years ago. The market has experienced a comppound annual growth rate of over 72 percent from 2011-2016, with new sources like Alberta's lithium-laced oil fields drawing investment alongside cobalt. This year, analysts expect it to gain another 25-26 percent. Last year, global EV production grew 41 percent, and sales are up more than 60 per cent year to year.

In addition,the Iron Creek project isn't a new exploration property. It has already seen major historic exploratory work, including 30,000 feet of diamond drilling. Iron Creek has historic (non 43-101 compliant) indications of 1.3 million tons grading 0.59 percent of cobalt with encouraging indications of up to 10 million tons. The 'closeology' is also brilliant. It's right next to the only advanced cobalt project in the U.S., which has a resource of 3 million-plus tonnes of cobalt.

As the battery market hits fever pitch and the supply-chain bottlenecks become unbearable, homegrown exploration is the key-first-movers and first investors will be the biggest beneficiaries.

 

A Very Precarious Supply Chain 

Supply is already in deficit, and we're also looking at an anticipated 500 percent increase in demand, making EV battery recycling an increasingly important complement to mining. Analysts at Macquarie Research project deficits of 885 tonnes of this resource next year, 3,205 in 2019 and 5,340 in 2020.

Not only is demand set to wildly outstrip supply very soon, but current supply (50 percent) comes primarily from the Democratic Republic of Congo (DRC). Buyers are coming under increasing pressure to look elsewhere for cobalt as the U.S. moves to work with allies to secure EV metals through diversified supply chains. The DRC has a horrendous record when it comes to labor practices and human rights.

Ask Apple Inc.  The tech giant recently announced it would stop buying unethical DRC cobalt for its iPhones - and as such, it has been forced to look for new suppliers.

The perfect storm continues: Some 95 percent of the world's cobalt is produced as a byproduct of copper and nickel mining, where concerns about ethical sourcing have put a spotlight on Canada's role in sustainable nickel practices worldwide. This means that cobalt supply is dependent on copper and nickel mining, and if those commodities are uneconomic to mine, there are no cobalt by-product results.

Not only is US Cobalt one of the first movers on the All-American ethical cobalt scene, but it's also financed to advance its Idaho Cobalt Belt project, and hopes to prove up 10 million tonnes of cobalt resource.

 

The Dream Team Behind Pure American Cobalt 

The CEO of US Cobalt, Wayne Tisdale, is a legend in spotting emerging trends with impeccable timing and has created billions in shareholder value. He's already done it with uranium, gold and oil and gas, and his most recent homerun was in lithium, with Pure Energy. When it launched in 2012, lithium was selling for about $5,000 per tonne. Within 18 months, it had increased 450 percent.

His next bet is on cobalt.

Tisdale and his team at Intrepid Financial have, in recent years, created $2.7 billion in value by building and financing 5 companies in completely different industries:

  • Rainy River (gold) was worth $1.2 billion at its peak
  • Xemplar (uranium) hit $1 billion at its peak
  • Ryland Oil (oil and gas) sold for $114 million
  • Webtech Wireless (tech) was worth $300 million at its peak
  • Pure Energy (lithium) is worth $65 million (and counting)

The bottom line? There is no other commodity on the market right now that we need more.

Just watch what the hedge funds are doing with cobalt because it's unprecedented. The run on physical cobalt started in February in the least expected corner: Major hedge funds started buying up physical cobalt and hoarding it in order to gain exposure, resulting in a major supply shortage for the blue metal. Swiss-based Pala Investments and China's Shanghai Chaos have already hoarded 17 percent of last year's global production. At today's prices that's worth around $280 million. At tomorrow's prices, it will be worth a lot more.

When hedge funds start stockpiling physical cobalt, it sends its traditional buyers into a panic to secure new shipments. Since November, cobalt prices have rallied more than 100 percent, and this is only the beginning. As the cobalt supply problem grows, and EV giants and gigafactories continue to increase demand, a home-grown solution is at hand. As a first principle of investing, where there is a supply problem, there is a massive opportunity for early investors.

 

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Seasonal power rates could cause consumer backlash

NB Power seasonal electricity rates face backlash amid smart grid delays, meter reading limits, and billing dispute risks, as consultants recommend AMI smart meters for accurate winter-summer pricing, time-of-use alignment, and consumer protection.

 

Key Points

NB Power seasonal electricity rates raise winter prices and lower summer prices to match costs, using accurate AMI metering.

✅ Requires midnight meter reads without AMI, increasing billing disputes.

✅ Shifts costs to electric-heat homes during high winter demand.

✅ Recommended to wait for smart grid AMI for time-of-use accuracy.

 

A consultant hired by NB Power is warning of significant consumer "backlash" if the utility is made to establish seasonal rates for electricity, as seen in B.C. and Quebec smart meter disputes among customers.

The consultant's report even suggests customers might have to read their own power meters at midnight twice a year — on April Fool's and Halloween — to make the system work.

"Virtually all bills will have errors ... billing disputes can be expected to increase, as seen in a $666 smart meter bill in N.S. that raised concerns, possibly dramatically, and there will be no means of resolving disputes in a satisfactory way," reads a report by Elenchus Research Associates that was commissioned by NB Power and filed with the Energy and Utilities Board on Thursday.

NB Power is in the middle of a year-long "rate design" review ordered by the EUB that is focused in part on whether the utility should charge lower prices for electricity in the summer and higher prices in the winter to better reflect the actual cost of serving customers.

New network of meters needed

Elenchus was asked to study how that might work but the company is arguing against any switch until NB Power upgrades its entire network of power meters, given old meters in N.B. have raised concerns.

Elenchus said seasonal rates require an accurate reading of every customer's power meter at midnight on March 31 and again on Oct. 31, the dates when power rates would switch between winter and summer prices.

A consultant's report says NB Power doesn't have the manpower to properly read meters if it brings in seasonal rates. (CBC)

But NB Power does not have the sophisticated infrastructure in place to read meters remotely, or the manpower to visit every customer location on the same day, so Elenchus said the utility would have to guesstimate bills or rely on the technical savvy and honesty of customers themselves.

"Customers could be asked to read their own meters late in the day on March 31 (and October 31)," suggested the report. "Aside from the obvious inconvenience and impracticality of that approach, NB Power would have no means of verifying the customers' meter reads."

Residential customers would see hike

Another looming controversy with seasonal rates is that it would raise costs for residential customers, especially to those who heat with electricity, a pressure seen with a 14% rate increase in Nova Scotia recently.

Elenchus estimated seasonal rates would add nearly $6 million to the cost of residential bills overall, with the largest increases flowing to those with baseboard heat.

Electric heat customers consume the majority of their power during the five months that would have the highest prices and Elenchus said that is another reason to wait for better power meters before proceeding.

NB Power has an ambitious plan to bring in a new meter system, and the consultant's report recommends waiting for that to happen before switching to seasonal rates. (Google Street View)

NB Power has an ambitious plan to upgrade meters and related infrastructure as part of its transformation to a "smart grid," but it is a multi-year plan.

Once in place the utility would be able to read meters remotely hour to hour, allowing power rates to be adjusted for times of the day and days of the week as well as seasonally.

Consumers will also have in-home pricing and consumption displays to help them manage their bills.

Elenchus said waiting for those meters will give electric heat customers a chance to avoid higher seasonal costs by letting them shift power consumption to lower-priced parts of the day.

"The introduction of seasonal rates would be more acceptable once AMI (advanced metering infrastructure) has been deployed," concludes the report.

A final hearing on NB Power's rate design, where seasonal rates and other changes will be considered, amid a power market overhaul debate in Alberta that industry is watching, is scheduled for next April.

 

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