B.C. looks to tree debris for power

UK Energy Price Cap aims to protect consumers on gas and electricity bills, tackling Big Six overcharging on default and standard variable tariffs, with Ofgem and MPs pushing urgent reforms to the broken market.

Key Points

A temporary absolute limit on default energy tariffs to shield consumers from overcharging on gas and electricity bills.

✅ Caps standard variable and default tariffs to protect loyalty.

✅ Targets Big Six pricing; oversight by Ofgem and BEIS MPs.

✅ Aims for winter protection while maintaining competition.

MPs are calling for a cap on the price of gas and electricity, with questions over the expected cost of a UK price cap amid fears consumers are being ripped off.

The Business, Energy and Industrial Strategy (BEIS) Select Committee says the Big Six energy companies have been overcharging for years.

MPs on the committee backed plans for a temporary absolute cap, noting debates over EU gas price cap strategies to fix what they called a "broken" energy market.

Labour's Rachel Reeves, who chairs the committee, said: "The energy market is broken. Energy is an essential good and yet millions of customers are ripped off for staying loyal to their energy provider.

"An energy price cap is now necessary and the Government must act urgently to ensure it is in place to protect customers next winter.

"The Big Six energy companies might whine and wail about the introduction of a price cap but they've been overcharging their customers on default and SVTs (standard variable tariffs) for years and their recent feeble efforts to move consumers off these tariffs has only served to highlight the need for this intervention."

The Committee also criticised Ofgem for failing to protect customers, especially the most vulnerable.

Draft legislation for an absolute cap on energy tariffs was published by the Government last year, and later developments like the Energy Security Bill have kept reform on the agenda.

But Business Secretary Greg Clark refused to guarantee that the flagship plans would be in place by next winter, despite warnings about high winter energy costs for households.

Committee members said there was a "clear lack of will" on the part of the Big Six to do what was necessary, including exploring decoupling gas and electricity prices, to deal with pricing problems.

A report from the committee found that customers are paying £1.4bn a year more than they should be under the current system.

Around 12 million households are stuck on poor-value tariffs, according to the report.

National assistance charity Citizens Advice said "loyal and vulnerable" customers had been "ripped off" for too long.

Chief executive Gillian Guy said: "An absolute cap, as recommended by the committee, is crucial to securing protection for the largest number of customers while continuing to provide competition in the market. This should apply to all default tariffs."

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U.S. Offshore Wind Capacity is set to exceed 1 GW by 2024, driven by BOEM approvals, federal leases, and resilient supply chains, with eastern states scaling renewable energy, turbines, and content despite COVID-19 disruptions.

Key Points

Projected gigawatt-scale offshore wind growth enabled by BOEM approvals, federal leases, and East Coast state demand.

✅ 17+ GW leased; only 1,870 MW in announced first phases.

✅ BOEM approvals are critical to reach >1 GW by 2024.

✅ Local supply chains mitigate COVID-19 impacts and lower costs.

Offshore wind in the U.S. will exceed 1 GW of capacity by 2024 and add more than 1 GW annually by 2027, a trajectory consistent with U.S. offshore wind power trends, according to a report released last week by Navigant Research.

The report calculated over 17 GW of offshore state and federal leases for wind production, reflecting forecasts that $1 trillion offshore wind market growth is possible. However, the owners of those leases have only announced first phase plans for 1,870 MW of capacity, leaving much of the projects in early stages with significant room to grow, according to senior research analyst Jesse Broehl.

The Business Network for Offshore Wind (BNOW) believes it is possible to hit 1 GW by 2023-24, according to CEO Liz Burdock. While the economy has taken a hit from the coronavirus pandemic, she said the offshore wind industry can continue growing as "the supply chain from Asia and Europe regains speed this summer, and the administration starts clearing" plans of construction.

BNOW is concerned with the economic hardship imposed on secondary and tertiary U.S. suppliers due to the global spread of COVID-19.

Offshore wind has been touted by many eastern states and governors as an opportunity to create jobs, with U.S. wind employment expected to expand, according to industry forecasts. Analysts see the growing momentum of projects as a way to further lower costs by creating a local supply chain, which could be jeopardized by a long-term shutdown and recession.

"The federal government must act now — today, not in December — and approve project construction and operation plans," a recent BNOW report said. Approving any of the seven projects before BOEM, which has recently received new lease requests, currently would allow small businesses to get to work "following the containment of the coronavirus," but approval of the projects next year "may be too late to keep them solvent."

The prospects for maintaining momentum in the industry falls largely to the Department of the Interior's Bureau of Ocean Energy Management (BOEM). The industry cannot hit the 1 GW milestone without project approvals by BOEM, which is revising processes to analyze federal permit applications in the context of "greater build out of offshore wind capacity," according to its website.

"It is heavily dependent on the project approval success," Burdock told Utility Dive.

Currently, seven projects are awaiting determinations from BOEM on their construction operation plans in Massachusetts, New York, where a major offshore wind farm was recently approved, New Jersey and Maryland, with more to be added soon, a BNOW spokesperson told Utility Dive.

To date, only one project has received BOEM approval for development in federal waters, a 12 MW pilot by Dominion Energy and Ørsted in Virginia. The two-turbine project is a stepping stone to a commercial-scale 2.6 GW project the companies say could begin installation as soon as 2024, and gave the developers experience with the permitting process.

In the U.S., developers have the capacity to develop 16.9 GW of offshore wind in federal U.S. lease areas, even as wind power's share of the electricity mix surges nationwide, Broehl told Utility Dive, but much of that is in early stages. The Navigant report did not address any impacts of coronavirus on offshore wind, he said.

Although Massachusetts has legislation in place to require utilities to purchase 1.6 GW of wind power by 2026, and several other projects are in early development stages, Navigant expects the first large offshore wind projects in the U.S. (exceeding 200 MW) will come online in 2022 or later, and the first projects with 400 MW or more capacity are likely to be built by 2024-2025, and lessons from the U.K.'s experience could help accelerate timelines. The U.S. would add about 1.2 GW in 2027, Broehl said.

The federal leasing activities along with the involvement from Eastern states and utilities "virtually guarantees that a large offshore wind market is going to take off in the U.S.," Broehl said.

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Fukushima Daiichi decommissioning delay highlights TEPCO's revised timeline, spent fuel removal at Units 1 and 2, safety enclosures, decontamination, fuel debris extraction by robot arm, and contaminated water management under stricter radiation control.

Key Points

A government revised schedule pushing back spent fuel removal and decommissioning milestones at Fukushima Daiichi.

✅ TEPCO delays spent fuel removal at Units 1 and 2 for safety.

✅ Enclosures, decontamination, and robotics mitigate radioactive risk.

✅ Contaminated water cut target: 170 tons/day to 100 by 2025.

The Japanese government decided Friday to delay the removal of spent fuel from the Fukushima Daiichi nuclear power plant's Nos. 1 and 2 reactors by as much as five years, casting doubt on whether it can stick to its timeframe for dismantling the crippled complex.

The process of removing the spent fuel from the units' pools had previously been scheduled to begin in the year through March 2024.

In its latest decommissioning plan, the government said the plant's operator, Tokyo Electric Power Company Holdings Inc., will not begin the roughly two-year process (a timeline comparable to major reactor refurbishment programs seen worldwide) at the No. 1 unit at least until the year through March 2028 and may wait until the year through March 2029.

Work at the No. 2 unit is now slated to start between the year through March 2025 and the year through March 2027, it said.

The delay is necessary to take further safety precautions such as the construction of an enclosure around the No. 1 unit to prevent the spread of radioactive dust, and decontamination of the No. 2 unit, even as authorities have begun reopening previously off-limits towns nearby, the government said. It is the fourth time it has revised its schedule for removing the spent fuel rods.

"It's a very difficult process and it's hard to know what to expect. The most important thing is the safety of the workers and the surrounding area," industry minister Hiroshi Kajiyama told a press conference.

The government set a new goal of finishing the removal of the 4,741 spent fuel rods across all six of the plant's reactors by the year through March 2032, amid ongoing debates about the consequences of early nuclear plant closures elsewhere.

Plant operator TEPCO has started the process at the No. 3 unit and already finished at the No. 4 unit, which was off-line for regular maintenance at the time of the disaster. A schedule has yet to be set for the Nos. 5 and 6 reactors.

While the government maintained its overarching timeframe of finishing the decommissioning of the plant 30 to 40 years from the 2011 crisis triggered by a magnitude 9.0 earthquake and tsunami, there may be further delays, even as milestones at other nuclear projects are being reached worldwide.

The government said it will begin removing fuel debris from the three reactors that experienced core meltdowns in the year through March 2022, starting with the No. 2 unit as part of broader reactor decommissioning efforts.

The process, considered the most difficult part of the decommissioning plan, will involve using a robot arm, reflecting progress in advanced reactors technologies, to initially remove small amounts of debris, moving up to larger amounts.

The government also said it will aim to reduce the pace at which contaminated water at the plant increases. Water for cooling the melted cores, mixed with underground water, amounts to around 170 tons a day. That number will be brought down to 100 tons by 2025, it said.

The water is being treated to remove the most radioactive materials and stored in tanks on the plant's grounds, but already more than 1 million tons has been collected and space is expected to run out by the summer of 2022.

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BC Hydro Deferred Regulatory Assets detail $5.5 billion in costs under rate-regulated accounting, to be recovered from ratepayers, highlighting B.C. Utilities Commission oversight, audit scrutiny, financial reporting impacts, and public utility governance.

Key Points

BC Hydro defers costs as regulatory assets to recover from ratepayers, influencing rates and financial reporting.

✅ $5.5B in deferred costs recorded as net regulatory assets

✅ Rate impacts tied to B.C. Utilities Commission oversight

✅ Auditor General to assess accounting and governance

Auditor General Carol Bellringer says BC Hydro has deferred $5.5 billion in expenses that it plans to recover from ratepayers in the future, as rates to rise by 3.75% over two years.

Bellringer focuses on the deferred expenses in a report on the public utility's use of rate-regulated accounting to control electricity rates for customers.

"As of March 31, 2018, BC Hydro reported a total net regulatory asset of $5.455 billion, which is what ratepayers owe," says the report. "BC Hydro expects to recover this from ratepayers in the future. For BC Hydro, this is an asset. For ratepayers, this is a debt."

She says rate-regulated accounting is used widely across North America, but cautions that Hydro has largely overridden the role of the independent B.C. Utilities Commission to regulate rates.

"We think it's important for the people of B.C. and our members of the legislative assembly to better understand rate-regulated accounting in order to appreciate the impact it has on the bottom line for BC Hydro, for government as a whole, for ratepayers and for taxpayers, especially following a three per cent rate increase in April 2018," Bellringer said in a conference call with reporters.

Last June, the B.C. government launched a two-phase review of BC Hydro to find cost savings and look at the direction of the Crown utility, amid calls for change from advocates.

The review came shortly after a planned government rate freeze was overturned by the utilities commission, which resulted in a three per cent rate increase in April 2018.

A statement by BC Hydro and the government says a key objective of the review due this month is to enhance the regulatory oversight of the commission.

Bellringer's office will become BC Hydro's auditor next year — and will be assessing the impact of regulation on the utility's financial reporting.

"It is a complex area and confidence in the regulatory system is critical to protect the public interest," wrote Bellringer.

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Ontario Hydro Rate Relief Plan delivers short-term electricity bill cuts, while leaked cabinet forecasts show inflation-linked hikes, borrowing costs, and a Clean Energy Adjustment under the province's long-term energy plan.

Key Points

A provincial plan that cuts bills now but defers costs, projecting rate hikes and adding a Clean Energy Adjustment.

✅ 25% cut now, after 8% HST relief; extra 17% reduction applied.

✅ Forecast: inflation-linked hikes later; borrowing adds long-term costs.

✅ Clean Energy Adjustment line to repay deferred system costs.

The short-term gain of a 25 per cent hydro rate cut this summer could lead to long-term pain as a leaked cabinet document forecasts prices jumping again in five years.

In the briefing materials leaked and obtained by the Progressive Conservatives, rates will start rising 6.5 per cent a year in 2022 and top out at 10.5 per cent in 2028, when average monthly bills hit $215.

That would be up from $123 this year once the rate cut — the subject of long-awaited legislation to lower electricity rates unveiled Thursday by Energy Minister Glenn Thibeault — takes full effect. There will be another 17-per-cent cut in addition to the 8 per cent taken off bills in January when the provincial portion of the HST was waived.

The leaked papers overshadowed Thibeault’s efforts to tout the price break, which will be followed with four years of hydro rate increases at 2 per cent, roughly the rate of inflation.

Thibeault charged that the Conservatives used an “outdated” document to distract from the fact that they are the only major party without a plan for dealing with skyrocketing hydro rates, with a year to go until next June’s provincial election.

“It’s not a coincidence,” he told reporters, denying any plans for an eventual 10.5-per-cent rate hike and promising the government’s new long-term energy plan, due in a few months, will have better numbers.

“We are working hard right now to continue to pull costs out of the system.”

Opposition parties said the Liberal plan doesn’t deal with the underlying problems that have made electricity expensive and simply borrows money to spread the costs over a longer period of time, with $25 billion in interest charges over 30 years.

Some observers also noted that a deal with Quebec would not reduce hydro bills, highlighting concerns about lasting affordability.

“The price of electricity is going to skyrocket after the next election,” warned Conservative MPP Todd Smith (Prince Edward—Hastings).

“The government isn’t being honest with the people of Ontario when it comes to the price of electricity.”

The documents show average monthly bills peaking at $231 in the year 2047, before falling back to $210 the following year once the 30 years of interest payments are over.

Conservative sources say they obtained the papers stamped “confidential cabinet document” from a whistleblower after Thibeault’s rate cut plan was presented to cabinet ministers at a meeting in early March.

There is no date on the document, which the energy minister alternately dismissed as “inaccurate” or possibly one of many that have been prepared with different options in mind.

“We’ve had hundreds of briefings with hundreds of documents … I can’t comment on one graph when we’ve been looking at hundreds of scenarios.”

New Democrats, who have proposed a scheme to cut rates, if elected, also called the government plan an election ploy with Liberals lagging in the polls.

“We’re going to take on a huge debt so (Premier) Kathleen Wynne can look good on the hustings in the next few months, and for decades we’re going to pay for it,” said MPP Peter Tabuns (Toronto-Danforth).

Thibeault acknowledged the Liberal plan will start repaying borrowed money in the mid- or late 2020s and it will show up separately on hydro bills as the “Clean Energy Adjustment”, a kind of electricity recovery rate that could raise costs.

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Manitoba-Minnesota Transmission Project faces NEB certificate review, with public hearings, Indigenous consultation, and cross-border approval weighing permit vs certificate timelines, potential land expropriation, and Hydro's 2020 in-service date for the 308-MW intertie.

Key Points

A cross-border hydro line linking Manitoba and Minnesota, now under NEB review through a permit or certificate process.

✅ NEB recommends certificate with public hearings and cabinet approval

✅ Stakeholders cite land, health, and economic impacts along route

✅ Hydro targets May-June 2020 in-service despite review

A recommendation from the National Energy Board could push back the construction start date of a $453-million hydroelectric transmission line from Manitoba to Minnesota.

In a letter to federal Natural Resources Minister Jim Carr, the regulatory agency recommends using a "certificate" approval process, which could take more time than the simpler "permit" process Manitoba Hydro favours.

The certificate process involves public hearings, reflecting First Nations intervention seen in other power-line debates, to weigh the merits of the project, which would then go to the federal cabinet for approval.

The NEB says this process would allow for more procedural flexibility and "address Aboriginal concerns that may arise in the circumstances of this process."

The Manitoba-Minnesota Transmission Project would provide the final link in a chain that brings hydroelectricity from generating stations in northern Manitoba, through the Bipole III transmission line and, like the New England Clean Power Link project, across the U.S. border as part of a 308-megawatt deal with the Green Bay-based Wisconsin Public Service.

When Hydro filed its application in December 2016, it had expected to have approval by the end of August 2017 and to begin construction on the line in mid-December, in order to have the line in operation by May or June 2020.  

Groups representing stakeholders along the proposed route of the transmission line had mixed reactions to the energy board's recommendation.

A lawyer representing a coalition of more than 120 landowners in the Rural Municipality of Taché and around La Broquerie, Man., welcomed the opportunity to have a more "fulsome" discussion about the project.

"I think it's a positive step. As people become more familiar with the project, the deficiencies with it become more obvious," said Kevin Toyne, who represents the Southeast Stakeholders Coalition.

Toyne said some coalition members are worried that Hydro will forcibly expropriate land in order to build the line, while others are worried about potential economic and health impacts of having the line so close to their homes. They have proposed moving the line farther east.

When the Clean Environment Commission — an arm's-length provincial government agency — held public hearings on the proposed route earlier this year, the coalition brought their concerns forward, echoing Site C opposition voiced by northerners, but Toyne says both the commission and Hydro ignored them.

Hydro still aiming for 2020 in-service date

The Manitoba Métis Federation also participated in those public hearings. MMF president David Chartrand worries about the impact a possible delay, as seen with the Site C work halt tied to treaty rights, could have on revenue from sales of hydroelectric power to the U.S.

"I know that a lot of money, billions have been invested on this line. And if the connection line is not done, then of course this will be sitting here, not gaining any revenue, which will affect every Métis in this province, given our Hydro bill's going to go up," Chartrand said.The NEB letter to Minister Carr requests that he "determine this matter in an expedited manner."

Manitoba Hydro spokesperson Bruce Owen said in an email that the Crown corporation will participate in whatever process, permit or certificate, the NEB takes.

"Manitoba Hydro does not have any information at this point in time that would change the estimated in-service date (May-June 2020) for the Manitoba-Minnesota Transmission Project," he said.

The federal government "is currently reviewing the NEB's recommendation to designate the project as subject to a certificate, which would result in public hearings," said Alexandre Deslongchamps, a spokesperson for Carr.

"Under the National Energy Board Act, an international power line requires either the approval by the NEB through a permit or approval by the Government of Canada by a certificate. Both must be issued by the NEB," he wrote in an email to CBC News.

By law, the certificate process is not to take longer than 15 months.

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