U.S. drops research into fuel cells for cars

California Income-Based Electricity Rates propose a fixed monthly fee set by income as utilities and the CPUC weigh progressive pricing, aiming to cut low-income bills while PG&E, SCE, and SDG&E retain usage-based charges.

Key Points

CPUC plan adds income-tiered fixed fees to lower low-income bills while keeping per-kWh usage charges.

✅ Adds fixed monthly fees by income to complement per-kWh charges

✅ Cuts bills for low-income households; higher earners pay more

✅ Utilities say revenue neutral; conservation signals preserved

California’s electric bills — already some of the highest in the nation — are rising as electricity prices soar across the state, but regulators are debating a new plan to charge customers based on their income level. 

Typically what you pay for electricity depends on how much you use. But the state’s three largest electric utilities — Southern California Edison Company, Pacific Gas and Electric Company and San Diego Gas & Electric Company — have proposed a plan to charge customers not just for how much energy they use, but also based on their household income, moving toward income-based flat-fee utility bills over time. Their proposal is one of several state regulators received designed to accommodate a new law to make energy less costly for California’s lowest-income customers.

Some state Republican lawmakers are warning the changes could produce unintended results, such as weakening incentives to conserve electricity or raising costs for customers using solar energy, and some have introduced a plan to overturn the charges in the Legislature.

But the utility companies say the measure would reduce electricity bills for the lowest income customers. Those residents would save about $300 per year, utilities estimate.

California households earning more than $180,000 a year would end up paying an average of $500 more a year on their electricity bills, according to the proposal from utility companies. 

The California Public Utilities Commission’s deadline for deciding on the suggested changes is July 1, 2024, as regulators face calls for action from consumers and advocates. The proposals come at a time when many moderate and low-income families are being priced out of California by rising housing costs.  

Who wants to change the fee structure?
Lawmakers passed and Gov. Gavin Newsom signed a comprehensive energy bill last summer that mandates restructuring electricity pricing across the state. 

The Legislature passed the measure in a “trailer-bill” process that limited deliberation. Included in the 21,000-word law are a few sentences requiring the public utilities commission to establish a “fixed monthly fee” based on each customer’s household income. 

A similar idea was first proposed in 2021 by researchers at UC Berkeley and the nonprofit thinktank Next 10. Their main recommendation was to split utility costs into two buckets. Fixed charges, which everyone has to pay just to be connected to the energy grid, would be based on income levels. Variable charges would depend on how much electricity you use.

Utilities say that part of customers’ bills still will be based on usage, but the other portion will reduce costs for lower- and middle-income customers, who “pay a greater percentage of their income towards their electricity bill relative to higher income customers,” the utilities argued in a recent filing. 

They said the current billing system is unjust, regressive and fails to recognize differences in energy usage among households,

“When we were putting together the reform proposal, front and center in our mind were customers who live paycheck to paycheck, who struggle to pay for essentials such as energy, housing and food,” Caroline Winn, CEO of San Diego Gas & Electric in a statement. 

The utilities say in their proposal that the changes likely would not reduce or increase their revenues.

James Sallee, an associate professor at UC Berkeley, said the utilities’ prior system of billing customers mostly by measuring their electric use to pay for what are essentially fixed costs for power is inefficient and regressive. 

The proposed changes “will shift the burden, on average, to a more progressive system that recovers more from higher income households and less from lower income households,” he said.

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Canada Power Grid Climate Resilience integrates extreme weather planning, microgrids, battery storage, renewable energy, vegetation management, and undergrounding to reduce outages, harden infrastructure, modernize utilities, and safeguard reliability during storms, ice events, and wildfires.

Key Points

Canada's grid resilience hardens utilities against extreme weather using microgrids, storage, renewables, and upgrades.

✅ Grid hardening: microgrids, storage, renewable integration

✅ Vegetation management reduces storm-related line contact

✅ Selective undergrounding where risk and cost justify

The increasing intensity of storms that lead to massive power outages highlights the need for Canada’s electrical utilities to be more robust and innovative, climate change scientists say.

“We need to plan to be more resilient in the face of the increasing chances of these events occurring,” University of New Brunswick climate change scientist Louise Comeau said in a recent interview.

The East Coast was walloped this week by the third storm in as many days, with high winds toppling trees and even part of a Halifax church steeple, underscoring the value of storm-season electrical safety tips for residents.

Significant weather events have consistently increased over the last five years, according to the Canadian Electricity Association (CEA), which has tracked such events since 2003.

#google#

Nearly a quarter of total outage hours nationally in 2016 – 22 per cent – were caused by two ice storms, a lightning storm, and the Fort McMurray fires, which the CEA said may or may not be classified as a climate event.

“It (climate change) is putting quite a lot of pressure on electricity companies coast to coast to coast to improve their processes and look for ways to strengthen their systems in the face of this evolving threat,” said Devin McCarthy, vice president of public affairs and U.S. policy for the CEA, which represents 40 utilities serving 14 million customers.

The 2016 figures – the most recent available – indicate the average Canadian customer experienced 3.1 outages and 5.66 hours of outage time.

McCarthy said electricity companies can’t just build their systems to withstand the worst storm they’d dealt with over the previous 30 years. They must prepare for worse, and address risks highlighted by Site C dam stability concerns as part of long-term planning.

“There needs to be a more forward looking approach, climate science led, that looks at what do we expect our system to be up against in the next 20, 30 or 50 years,” he said.

Toronto Hydro is either looking at or installing equipment with extreme weather in mind, Elias Lyberogiannis, the utility’s general manager of engineering, said in an email.

That includes stainless steel transformers that are more resistant to corrosion, and breakaway links for overhead service connections, which allow service wires to safely disconnect from poles and prevents damage to service masts.

Comeau said smaller grids, tied to electrical systems operated by larger utilities, often utilize renewable energy sources such as solar and wind as well as battery storage technology to power collections of buildings, homes, schools and hospitals.

“Capacity to do that means we are less vulnerable when the central systems break down,” Comeau said.

Nova Scotia Power recently announced an “intelligent feeder” pilot project, which involves the installation of Tesla Powerwall storage batteries in 10 homes in Elmsdale, N.S., and a large grid-sized battery at the local substation. The batteries are connected to an electrical line powered in part by nearby wind turbines.

The idea is to test the capability of providing customers with back-up power, while collecting data that will be useful for planning future energy needs.

Tony O’Hara, NB Power’s vice-president of engineering, said the utility, which recently sounded an alarm on copper theft, was in the late planning stages of a micro-grid for the western part of the province, and is also studying the use of large battery storage banks.

“Those things are coming, that will be an evolution over time for sure,” said O’Hara.

Some solutions may be simpler. Smaller utilities, like Nova Scotia Power, are focusing on strengthening overhead systems, mainly through vegetation management, while in Ontario, Hydro One and Alectra are making major investments to strengthen infrastructure in the Hamilton area.

“The number one cause of outages during storms, particularly those with high winds and heavy snow, is trees making contact with power lines,” said N.S. Power’s Tiffany Chase.

The company has an annual budget of $20 million for tree trimming and removal.

“But the reality is with overhead infrastructure, trees are going to cause damage no matter how robust the infrastructure is,” said Matt Drover, the utility’s director for regional operations.

“We are looking at things like battery storage and a variety of other reliability programs to help with that.”

NB Power also has an increased emphasis on tree trimming and removal, and now spends $14 million a year on it, up from $6 million prior to 2014.

O’Hara said the vegetation program has helped drive the average duration of power outages down since 2014 from about three hours to two hours and 45 minutes.

Some power cables are buried in both Nova Scotia and New Brunswick, mostly in urban areas. But both utilities maintain it’s too expensive to bury entire systems – estimated at $1 million per kilometre by Nova Scotia Power.

The issue of burying more lines was top of mind in Toronto following a 2013 ice storm, but that’s city’s utility also rejected the idea of a large-scale underground system as too expensive – estimating the cost at around $15 billion, while Ontario customers have seen Hydro One delivery rates rise in recent adjustments.

“Having said that, it is prudent to do so for some installations depending on site specific conditions and the risks that exist,” Lyberogiannis said.

Comeau said lowering risks will both save money and disruption to people’s lives.

“We can’t just do what we used to do,” said Xuebin Zhang, a senior climate change scientist at Environment and Climate Change Canada.

“We have to build in management risk … this has to be a new norm.”

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Hydro-Québec Unified Corporate Structure advances the energy transition through integrated planning, strategy, infrastructure delivery, and customer operations, aligning generation, transmission, and distribution while ensuring non-discriminatory grid access and agile governance across assets and behind-the-meter technologies.

Key Points

A cross-functional model aligning strategy, planning, and operations to accelerate Quebec's low-carbon transition.

✅ Four groups: strategy, planning, infrastructure, operations.

✅ Ensures non-discriminatory transmission access compliance.

✅ No staff reductions; staged implementation from Feb 28.

As Hydro-Que9bec prepares to play a key role in the transition to a low-carbon economy, the complexity of the work to be done in the coming decade requires that it develop a global vision of its operations and assets, from the drop of water entering its turbines to the behind-the-meter technologies marketed by its subsidiary Hilo. This has prompted the company to implement a new corporate structure that will maximize cooperation and agility, including employee-led pandemic support that builds community trust, making it possible to bring about the energy transition efficiently with a view to supporting the realization of Quebecers’ collective aspirations.

Toward a single, unified Hydro

Hydro-Québec’s core mission revolves around four major functions that make up the company’s value chain, alongside policy choices like peak-rate relief during emergencies. These functions consist of:

1. Developing corporate strategies based on current and future challenges and business opportunities
2. Planning energy needs and effectively allocating financial capital, factoring in pandemic-related revenue impacts on demand and investment timing
3. Designing and building the energy system’s multiple components
4. Operating assets in an integrated fashion and providing the best customer experience by addressing customer choice and flexibility expectations across segments.

Accordingly, Hydro-Québec will henceforth comprise four groups respectively in charge of strategy and development; integrated energy needs planning; infrastructure and the energy system; and operations and customer experience, including billing accuracy concerns that can influence satisfaction. To enable the company to carry out its mission, these groups will be able to count on the support of other groups responsible for corporate functions.

Across Canada, leadership changes at other utilities highlight the need to rebuild ties with governments and investors, as seen with Hydro One's new CEO in Ontario.

“For over 20 years, Hydro-Québec has been operating in a vertical structure based on its main activities, namely power generation, transmission and distribution. This approach must now give way to one that provides a cross-functional perspective allowing us to take informed decisions in light of all our needs, as well as those of our customers and the society we have the privilege to serve,” explained Hydro-Québec’s President and Chief Executive Officer, Sophie Brochu.

In terms of gender parity, the management team continues to include several men and women, thus ensuring a diversity of viewpoints.

Hydro-Québec’s new structure complies with the regulatory requirements of the North American power markets, in particular with regard to the need to provide third parties with non-discriminatory access to the company’s transmission system. The frameworks in place ensure that certain functions remain separate and help coordinate responses to operational events such as urban distribution outages that challenge continuity of service.

These changes, which will be implemented gradually as of Monday, February 28, do not aim to achieve any staff reductions.

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Germany Hydrogen Import Strategy outlines reliance on green hydrogen imports, expanded electrolysis capacity, IPCEI-funded pipelines, and industrial decarbonization for steel and chemicals to reach climate-neutral goals by 2045, meeting 2030 demand of 95-130 TWh.

Key Points

A plan to import 50-70% of hydrogen by 2030, backing green hydrogen, electrolysis, pipelines, and decarbonization.

✅ Imports cover 50-70% of 2030 hydrogen demand

✅ 10 GW electrolysis target with state aid and IPCEI

✅ 1,800 km H2 pipelines to link hubs by 2030

Germany will have to import up to 70% of its hydrogen demand in the future as Europe's largest economy aims to become climate-neutral by 2045, an updated government strategy published on Wednesday showed.

The German cabinet approved a new hydrogen strategy, setting guidelines for hydrogen production, transport infrastructure and market plans.

Germany is seeking to expand reliance on hydrogen as a future energy source to bolster energy resilience and cut greenhouse emissions for highly polluting industrial sectors that cannot be electrified such as steel and chemicals and cut dependency on imported fossil fuel.

Produced using solar and wind power, green hydrogen is a pillar of Berlin's plan to build a sustainable electric planet and transition away from fossil fuels.

But even with doubling the country's domestic electrolysis capacity target for 2030 to at least 10 gigawatts (GW), Germany will need to import around 50% to 70% of its hydrogen demand, forecast at 95 to 130 TWh in 2030, the strategy showed.

"A domestic supply that fully covers demand does not make economic sense or serve the transformation processes resulting from the energy transition and the broader global energy transition overall," the document said.

The strategy underscores the importance of diversifying future hydrogen sources, including potential partners such as Canada's clean hydrogen sector, but the government is working on a separate strategy for hydrogen imports whose exact date is not clear, a spokesperson for the economy ministry said.

"Instead of relying on domestic potential for the production of green hydrogen, the federal government's strategy is primarily aimed at imports by ship," Simone Peter, the head of Germany's renewable energy association, said.

Under the strategy, state aid is expected to be approved for around 2.5 GW of electrolysis projects in Germany this year and the government will earmark 700 million euros ($775 million) for hydrogen research to optimise production methods, research minister Bettina Stark-Watzinger said.

But Germany's limited renewable energy space will make it heavily dependent on imported hydrogen from emerging export hubs such as Abu Dhabi hydrogen exports gaining scale, experts say.

"Germany is a densely populated country. We simply need space for wind and photovoltaic to be able to produce the hydrogen," Philipp Heilmaier, an energy transition researcher at Germany energy agency, told Reuters.

The strategy allows the usage of hydrogen produced through fossil energy sources preferably if the carbon is split off, but said direct government subsidies would be limited to green hydrogen.

Funds for launching a hydrogen network with more than 1,800 km of pipelines in Germany are expected to flow by 2027/2028 through the bloc's Important Projects of Common European Interest (IPCEI) financing scheme, as the EU plans to double electricity use by 2050 could raise future demand, with the goal of connecting all major generation, import and storage centres to customers by 2030.

Transport Minister Volker Wissing said his ministry was working on plans for a network of hydrogen filling stations and for renewable fuel subsidies.

Environmental groups said the strategy lacked binding sustainability criteria and restriction on using hydrogen for sectors that cannot be electrified instead of using it for private heating or in cars, calling for a plan to eventually phase-out blue hydrogen which is produced from natural gas.

Germany has already signed several hydrogen cooperation agreements with countries such as clean energy partnership with Canada and Norway, United Arab Emirates and Australia.

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Alberta Electricity Market Reform reshapes policy under the UCP, weighing a capacity market versus energy-only design, AESO reliability rules, renewables targets, coal phase-out, carbon pricing, consumer rates, and investment certainty before AUC decisions.

Key Points

Alberta Electricity Market Reform is the UCP plan to reassess capacity vs energy-only, renewables, and carbon pricing.

✅ Reviews capacity market timeline and AESO procurement

✅ Alters subsidies for renewables; slows wind and solar growth

✅ Adjusts industrial carbon levy; audits Balancing Pool losses

Hearings kicked off this week into the future of the province’s electricity market design, amid an electricity market reshuffle pledged by the province, but a high-stakes decision about the industry’s fate — affecting billions of dollars in investment and consumer costs — won’t be made inside the meeting room of the Alberta Utilities Commission.

Instead, it will take place in the office of Jason Kenney, as the incoming premier prepares to pivot away from the seismic reforms to Alberta’s electricity sector introduced by the Notley government.

The United Conservative Party has promised to adopt market-based policies, reflecting changes to how Alberta produces and pays for power, that will reset how the sector operates, from its approach to renewable energy and carbon pricing to re-evaluating the planned transition to an electricity “capacity market.”

“Every ball in electricity is up in the air right now,” Vittoria Bellissimo, of the Industrial Power Consumers Association of Alberta, said Tuesday during a break in the commission hearings.

Industry players are uncertain how quickly the UCP will change direction on power policies, but there’s little doubt Kenney’s government will take a strikingly different approach to the sector that keeps the lights on in Alberta.

“There’s some things they are going to change that are going to impact the electricity industry significantly,” said Duane Reid-Carlson, chief executive of consultancy EDC Associates.

“But I don’t think it’s going to be upheaval. I think the new government will proceed with caution because electricity is the foundation of our economy.”

Alberta’s electricity market has been turned on its head in recent years due to the recession, power prices dropping to near two-decade lows and several transformative policies initiated by the NDP.

The Notley government’s climate plan included an accelerated phase-out of all coal-fired generation and set targets for more renewable energy.

The most significant, but least-understood, move has been the planned shift to an electricity capacity market in 2021.

Under the strategy, generators will no longer solely be paid for the power produced and sold into the market; they will also receive payments for having electricity capacity available to the grid on demand.

The change was recommended by the Alberta Electric System Operator (AESO) as a way to reduce price volatility and provide more reliability than the current energy-only market, which some argue needs more competition to deliver better outcomes.

The independent system operator and industry officials have spent more than two years planning the transition since the switch was announced in late 2016. Proposed rules for the new system, outlining market changes, are now being discussed at the Alberta Utilities Commission hearings.

However, there is no ironclad guarantee the system remake will go ahead following the UCP’s election victory last week — amid calls to scrap the overhaul from a Calgary retailer — it plans to study the issue further — while other substantive electricity changes are already in store.

The UCP has promised to end “costly subsidies” to renewable energy developments and abandon the NDP’s pledge to have such energy sources make up 30 per cent of all power generation by 2030.

It will remove the planned phase-out of coal-fired electricity generation, although federal regulations for a 2030 prohibition remain in place.

It will also ask the auditor general to conduct a special audit of the massive losses sustained by the province’s Balancing Pool due to power purchase arrangements being handed back to the agency three years ago.

While Kenney has pledged to cancel the provincewide carbon tax, a levy on large industrial greenhouse gas emitters (such has power plants) will still be charged, although at a reduced rate of $20 a tonne.

The biggest unknown remains the power market’s structure, which underpins how the entire system operates.

The UCP has promised to consult on the shift to the capacity market and report back to Albertans within 90 days.

The complex issue may sound like an eye-glazer, but it will have a profound effect on industry investment, as well as how much consumers pay on their monthly electricity bills.

A number of industry players worry the capacity market will lead AESO to procure more power than is necessary, foisting unnecessary costs onto all Albertans.

“I still have concerns for what the impact on consumers is going to be,” said energy market consultant Sheldon Fulton. “I’d love to see the capacity market go away.”

An analysis by EDC Associates found the transition to a capacity market will procure additional electricity before it’s needed, requiring consumers to pay up to 40 per cent more — an extra $1.4 billion — for power in 2021-22 than under the existing market structure.

“I don’t think there’s any prejudged outcome,” said Blake Shaffer, former head trader at TransAlta Corp. and a fellow-in-residence at the C.D. Howe Institute.

“But it really matters about getting this right.”

Evan Bahry, executive director of the Independent Power Producers Society of Alberta, said the fact the UCP’s review was confined to just 90 days is helpful, as it avoids throwing the entire industry into a prolonged period of uncertainty.

As for the greening of Alberta’s power grid, amid growing attention to clean grids and storage, the demise of the NDP’s Renewable Electricity Program will likely slow down the rapid pace of wind and solar development. But it’s unlikely to stop the growth trend as costs continue to fall for such developments.

“Renewables over the last number of years have evolved to the point that they make sense on a subsidy-free basis,” said Dan Balaban, CEO of Greengate Power Corp., which has developed 480 MW of wind power in Alberta and Ontario.

“There is a path to clean electricity ahead.”

Chris Varcoe is a Calgary Herald columnist.

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BC Hydro COVID-19 Bill Relief offers pandemic support with bill credits, rate cuts, and deferred payments for residential, small business, and industrial customers across B.C., easing utilities costs during COVID-19 economic hardship.

Key Points

COVID-19 bill credits, a rate cut, and deferred payments for eligible B.C. homes, small businesses, and industrial customers.

✅ Non-repayable credits equal to 3 months of average bills.

✅ Small businesses closed can skip bills for three months.

✅ Large industry may defer 50% of electricity costs.

B.C. residents who have lost their jobs or had their wages cut will get a three-month break on BC Hydro bills, while small businesses, amid commercial consumption plummets during COVID-19, are also eligible to apply for similar relief.

Premier John Horgan said Wednesday the credit for residential customers will be three times a household’s average monthly bill over the past year and does not have to be repaid as part of the government’s support package during the COVID-19 pandemic, as BC Hydro demand down 10% highlights the wider market pressures.

He said small businesses that are closed will not have to pay their power bills for three months, and in Ontario an Ontario COVID-19 hydro rebate complemented similar relief, and large industrial customers, including those operating mines and pulp mills, can opt to have 50 per cent of their electricity costs deferred, though a deferred costs report warned of long-term liabilities.

BC Hydro rates will be cut for all customers by one per cent as of April 1, a move similar to Ontario 2021 rate reductions that manufacturers supported lower rates at the time, after the B.C. Utilities Commission provided interim approval of an application the utility submitted last August.

Eligible residential customers can apply for bill relief starting next week and small business applications will be accepted as of April 14, while staying alert to BC Hydro scam attempts during this period, with the deadline for both categories set at June 30.

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