Syria sees generation shortfall

Irving Oil hydrogen electrolyzer expands green hydrogen capacity at the Saint John refinery with Plug Power technology, cutting carbon emissions, enabling clean fuel for buses, and supporting Atlantic Canada decarbonization and renewable grid integration.

Key Points

A 5 MW Plug Power unit at Irving's Saint John refinery producing low-carbon hydrogen via electrolysis.

✅ Produces 2 tonnes/day, enough to fuel about 60 hydrogen buses

✅ Uses grid power; targets cleaner supply via renewables and nuclear

✅ First Canadian refinery investing in electrolyzer technology

Irving Oil is expanding hydrogen capacity at its Saint John, N.B., refinery in a bid to lower carbon emissions and offer clean energy to customers.

The family-owned company said Tuesday it has a deal with New York-based Plug Power Inc. to buy a five-megawatt hydrogen electrolyzer that will produce two tonnes of hydrogen a day — equivalent to fuelling 60 buses with hydrogen — using electricity from the local grid and drawing on examples such as reduced electricity rates proposed in Ontario to grow the hydrogen economy.

Hydrogen is an important part of the refining process as it's used to lower the sulphur content of petroleum products like diesel fuel, but most refineries produce hydrogen using natural gas, which creates carbon dioxide emissions and raises questions explored in hydrogen's future for power companies in the energy sector.

"Investing in a hydrogen electrolyzer allows us to produce hydrogen in a very different way," Irving director of energy transition Andy Carson said in an interview.

"Instead of using natural gas, we're actually using water molecules and electricity through the electrolysis process to produce ... a clean hydrogen."

Irving plans to continue to work with others in the province to decarbonize the grid amid pressures like Ontario's push into energy storage as electricity supply tightens and ensure the electricity being used to power its hydrogen electrolyzer is as clean as possible, he said.

N.B. Power's electrical system includes 14 generating stations powered by hydro, coal, oil, wind, nuclear and diesel. The utility has committed to increasing its renewable energy sources and exploring innovations such as EV-to-grid integration piloted in Nova Scotia.

Irving said it will be the first oil refinery in Canada to invest in electrolyzer technology, as Ontario's Hydrogen Innovation Fund supports broader deployment nationwide.

The company said its goal is to offer hydrogen fuelling infrastructure in Atlantic Canada, complementing N.L.'s fast-charging network for EV drivers in the region.

"This kind of investment allows us to not just move to a cleaner form of hydrogen in the refinery. It also allows us to store and make hydrogen available to the marketplace," Carson said.

Federal watchdog warns Canada's 2030 emissions target may not be achievable
The hydrogen technology will help Irving "unlock pent up demand for hydrogen as an energy transition fuel for logistics organizations," he said.

Alberta also aims to expand its hydrogen production over the coming years, alongside British Columbia's $900 million hydrogen project moving ahead on the West Coast. 

Those plans lean on the development of carbon capture and storage (CCS) technology that aims to trap the emissions created when producing hydrogen from natural gas.

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Duration Portfolio Energy Storage aligns layered peak demand with right-sized batteries, enabling peak shaving, gas peaker replacement, and solar-plus-storage synergy while improving grid flexibility, reliability, and T&D deferral through two- to four-hour battery durations.

Key Points

An approach that layers battery durations to match peaks, cut costs, replace peakers, and boost grid reliability.

✅ Layers 2- to 4-hour batteries by peak duration

✅ Enables solar-plus-storage and peak shaving

✅ Cuts T&D upgrades, emissions, and fuel costs

The debate over energy storage replacing gas-fired peakers has raged for years, but a new approach that shifts the terms of the argument could lead to an acceleration of storage deployments.

Rather than looking at peak demand as a single mountainous peak, some analysts now advocate a layered approach that allows energy storage to better match peak needs and complement ongoing efforts to improve solar and wind power across the grid.

"You don’t have to have batteries that run to infinity."

Some developers of solar-plus-storage projects, bolstered by cheap batteries, say they can already compete head-to-head with gas-fired peakers. "I can beat a gas peaker anywhere in the country today with a solar-plus-storage power plant," Tom Buttgenbach, president and CEO of developer 8minutenergy Renewables, recently told S&P Global.

Customers are very busy these days and rebate programs need to fit the speed of their life. Participation should be quick, easy, and accessible anywhere.

Others disagree. Storage is not disruptive for generation, but will be disruptive for transmission and distribution, Kris Zadlo, executive vice president and chief development officer at Invenergy, told the audience at a Bloomberg New Energy Finance conference last spring. Invenergy, like many renewable power developers, develops generation, energy storage and transmission projects.

But there is another path that avoids the pitfalls of positions on either end of the all-or-none approach. "Do the analysis of the need itself," Ray Hohenstein, market applications director at Fluence, told Utility Dive. If the need is only two hours in duration, it may be best served by a two-hour battery. "You don’t have to have batteries that run to infinity."

Storage vs. fossil fuel peakers

Energy storage has several benefits over traditional fossil fuel peaking plants, Hohenstein said. It is instantaneous, it has no emissions and requires no fuel, and has limited infrastructure needs. It can also help the grid absorb higher levels of renewable generation by soaking up excess output, such as solar power at noon, and many planned storage additions will be paired with solar in the next few years. But the one thing energy storage cannot do, he said, is provide limitless energy.

So, instead of looking at replacing an individual peaker, Hohenstein advocated a "duration portfolio" approach that uses energy storage to shave peak load.

If the need is for 150 MW of resources that will never need to run for more than two hours at a time, then a battery is "quite cheap," significantly less than a four or eight-hour battery, said Hohenstein. "If you fill up your peak by duration layer, it could be more cost effective."

NREL research driver

Fluence’s approach is informed by research by Paul Denholm and Robert Margolis at the National Renewable Energy Laboratory (NREL), released last spring.

The NREL researchers looked at the California market where they said 11 GW of fossil fuel capacity is expected to be retired by 2029 because of new once-through-cooling requirements that are taking effect. A lot of that capacity is peaking capacity and, according to NREL’s analysis, a large fraction could be replaced with four-hour energy storage, assuming continued storage cost reductions and growth in solar installations.

The key in NREL’s research was the level of solar power penetration. There is a "synergistic" relationship between solar penetration and storage deployment, the researchers wrote, and other studies suggest wind and solar could meet 80% of U.S. demand as these trends continue.

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Renewable Energy Cost Trends highlight IRENA data showing solar and wind undercut coal, as utility-scale projects drive lower levelized electricity costs worldwide, with the Middle East and UAE advancing mega solar parks.

Key Points

They track how solar and wind undercut new fossil fuels as utility-scale costs drop and investment accelerates.

✅ IRENA reports renewables cheapest for new installations

✅ Solar and wind LCOE fell sharply since 2010

✅ Middle East and UAE scale mega utility projects

Renewable energy is now the cheapest option for new electricity installation in most of the world, a report from the International Renewable Energy Agency (IRENA) on Tuesday said.

Renewable power projects have undercut traditional coal fuel plants, with solar and wind power costs in particular falling as record-breaking growth continues worldwide.

“Installing new renewables increasingly costs less than the cheapest fossil fuels. With or without the health and economic crisis, dirty coal plants were overdue to be consigned to the past, said Francesco La Camera, director-general of IRENA said in the report.

In 2019, renewables accounted for around 72 percent of all new capacity added worldwide, IRENA said, following a 2016 record year that highlighted the momentum, with lowering costs and technological improvements in solar and wind power helping this dynamic. For solar energy, IRENA notes that the cost for electricity from utility-scale plants fell by 82 percent in the decade between 2010 and 2019, as China's solar PV growth underscored in 2016.

“More than half of the renewable capacity added in 2019 achieved lower electricity costs than new coal, while new solar and wind projects are also undercutting the cheapest and least sustainable of existing coal-fired plants,” Camera added.

Costs for solar and wind power also fell year-on-year by 13 and 9 percent, respectively, with offshore wind costs showing steep declines as well. In 2019, more than half of all newly commissioned utility-scale renewable power plants provided electricity cheaper than the lowest cost of a new fossil fuel plant.

The Middle East

In mid-May, a report by UK-based law firm Ashurst suggested the Middle East is the second most popular region for renewable energy investment after North America, at a time when clean energy investment is outpacing fossil fuels.

The region is home to some of the largest renewable energy bets in the world, with Saudi wind expansion gathering pace. The UAE, for instance, is currently developing the Mohammed Bin Rashid Solar Park, the world’s largest concentrated solar power project in the world.

Around 26 percent of Middle East respondents in Ashurst’s survey said that they were presently investing in energy transition, marking the region as the most popular for current investment in renewables, while 11 percent added that they were considering investing.

In North America, the most popular region, 28 percent said that they were currently investing, with 11 percent stating they are considering investing.

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Europe 2023 Energy Shortfall underscores how weak hydro and nuclear offset record solar and wind, tightening grids as natural gas supplies shrink and demand rebounds, heightening risks of electricity shortages across key economies.

Key Points

A regional gap as weak hydro and nuclear offset record solar and wind, straining supply as gas stays tight.

✅ Hydro and nuclear output fell sharply in early 2023

✅ Record solar and wind could not offset the deficit

✅ Industrial demand rebound pressures limited gas supplies

Shortfalls in Europe's hydro and nuclear output have more than offset record electricity generation from wind and solar power sites over the first quarter of 2023, leaving the region vulnerable to acute energy shortages for the second straight year.

European countries fast-tracked renewable energy capacity development in 2022 in the wake of Russia's invasion of Ukraine last February, which upended natural gas flows to the region and sent power prices soaring.

Europe lifted renewable energy supply capacity by a record 57,290 megawatts in 2022, or by nearly 9%, according to the International Energy Agency (IRENA), amid a scramble to replace imported Russian gas with cleaner, home-grown energy.

However, steep drops in both hydro and nuclear output - two key sources of non-emitting energy - mean Europe's power producers have limited ways to lift overall electricity generation, as the region is losing nuclear power at a critical moment, just as the region's economies start to reboot after last year's energy shock.

POWER PLATEAU
Europe's total electricity generation over the first quarter of 2023 hit 1,213 terawatt hours, or roughly 6.4% less than during the same period in 2022, according to data from think tank Ember.

At the same time, European power hits records during extreme heat as plants struggle to cool, exacerbating supply risks.

As Europe's total electricity demand levels were in post-COVID-19 expansion mode in early 2022 before Russia's so-called special operation sent power costs to record highs amid debates over how electricity is priced in Europe, it makes sense that overall electricity use was comparatively stunted in early 2023.

However, efforts are now underway to revive activity at scores of European factories, industrial plants and production lines that were shuttered or curtailed in 2022, so Europe's collective electricity consumption totals are set to trend steadily higher over the remainder of 2023.

With Russian natural gas unavailable in the previous quantities due to sanctions and supply issues, Europe's power producers will need to deploy alternative energy sources, including renewables poised to eclipse coal globally, to feed that increase in power demand.

And following the large jump in renewable capacity brought online in 2022, utilities can deploy more low-emissions energy than ever before across Europe's electricity grids.

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Manitoba Hydro Rate Increase sets electricity rates up 2.5% annually for three years via Bill 35, bypassing PUB hearings, citing Crown utility debt and pandemic impacts, with legislature debate and a multi-year regulatory review ahead.

Key Points

A government plan to lift electricity rates 2.5% annually over three years via Bill 35, bypassing PUB hearings.

✅ 2.5% annual hikes for three years set in legislation

✅ Bypasses PUB rate hearings during pandemic recovery

✅ Targets Crown utility debt; multi-year review planned

The Manitoba government is planning to raise electricity rates, with Manitoba Hydro scaling back next year, by 2.5 per cent a year over the next three years.

Finance Minister Scott Fielding says the increases, to be presented in a bill before the legislature, are the lowest in a decade and will help keep rates among the lowest in Canada, even as SaskPower's 8% hike draws scrutiny in a neighbouring province.

Crown-owned Manitoba Hydro had asked for a 3.5 per cent increase this year, similar to BC Hydro's 3% rise, to help pay off billions of dollars in debt.

“The way we figured this out, we looked at the rate increases that were approved by PUB (Public Utilities Board) over the last ten years, (and) we went to 75 per cent of that,” Fielding said during a Thursday morning press conference.

“It’s a pandemic, we know that there’s a lot of people that are unemployed, that are struggling, we know that businesses need to recharge after the business (sic), so this will provide them an appropriate break.”

Electricity rates are normally set by the Public Utilities Board, a regulatory body that holds rate hearings and examines the Crown corporation’s finances.

The Progressive Conservative government has temporarily suspended the regulatory process and has set rates itself, while Ontario rate legislation to lower rates moved forward in its jurisdiction.

Manitoba Liberal leader Dougald Lamont was quick to condemn the move, noting parallels to Ontario price concerns before saying in a news release the PCs “are abusing their power and putting Hydro’s financial future at risk by fixing prices in the hope of buying some political popularity.”

“Hydro’s rates should be set by the PUB after public hearings, not figured out on the back of a napkin in the Premier’s office,” Lamont wrote.

Fielding noted the increase would appear as an amendment to Bill 35, which will appear in the legislature this fall, as BC Hydro plans multi-year increases proceed elsewhere.

“All members of the legislative assembly will vote and debate this rate increase on Bill 35,” Fielding said.

“This will give the PUB time to implement reforms, and allow the utilities to prepare a more rigorous, multi-year review application process.”

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2019 Grid Edge Trends highlight evolving demand response, DER orchestration, real-time operations, AMI data, and EV charging, as wholesale markets seek flexibility and resiliency amid tighter reserve margins and fossil baseload retirements.

Key Points

Shifts toward DER-enabled demand response and real-time, behind-the-meter flexibility.

✅ Real-time DER dispatch enhances reliability during tight reserves

✅ AMI and ICT improve forecasting, monitoring, and control of resources

✅ Demand response shifts toward aggregated behind-the-meter orchestration

Which grid edge trends will continue into 2019 as the digital grid matures and what kind of disruption is on the horizon in the coming year?

From advanced metering infrastructure endpoints to electric-vehicle chargers, grid edge venture capital investments to demand response events, hundreds of data points go into tracking new trends at the edge of the grid amid ongoing grid modernization discussions across utilities.

Trends across these variables tell a story of transition, but perhaps not yet transformation. Customers hold more power than ever before in 2019, with utilities and vendors innovating to take advantage of new opportunities behind the meter. Meanwhile, external factors can always throw things off-course, including the data center boom that is posing new power challenges, and reliability is top of mind in light of last year's extreme weather events. What does the 2018 data say about 2019?

For one thing, demand response evolved, enabled by new information and communications technology. Last year, wholesale market operators increasingly sought to leverage the dispatch of distributed energy resource flexibility in close to real time. Three independent system operators and regional transmission organizations called on demand response five times in total for relief in the summer of 2018, including the NYISO.

The demand response events called in the last 18 months send a clear message: Grid operators will continue to call events year-round. This story unfolds as reserve margins continue to tighten, fossil baseload generation retirements continue, and system operators are increasingly faced with proving the resiliency and reliability of their systems while efforts to invest in a smarter electricity infrastructure gain momentum across the country.

In 2019, the total amount of flexible demand response capacity for wholesale market participation will remain about the same. However, the way operators and aggregators are using demand response is changing as information and communications technology systems improve and utilities are using AI to adapt to electricity demands, allowing the behavior of resources to be more accurately forecasted, monitored and controlled.

These improvements are allowing customer-sited resources to offer  flexibility services closer to real-time operations and become more reactive to system needs. At the same time, traditional demand response will continue to evolve toward the orchestration of DERs as an aggregate flexible resource to better enable growing levels of renewable energy on the grid.

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