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Germany 2030 Electricity Demand Forecast projects 658 TWh, driven by e-mobility, heat pumps, and green hydrogen. BMWi and BDEW see higher renewables, onshore wind, photovoltaics, and faster grid expansion to meet climate targets.

Key Points

A BMWi outlook to 658 TWh by 2030, led by e-mobility, plus demand from heat pumps, green hydrogen, and industry.

✅ Transport adds ~70 TWh; cars take 44 TWh by 2030

✅ Heat pumps add 35 TWh; green hydrogen needs ~20 TWh

✅ BDEW urges 70% renewables and faster grid expansion

Gross electricity consumption in Germany will increase from 595 terawatt hours (TWh) in 2018 to 658 TWh in 2030. That is an increase of eleven percent. This emerges from the detailed analysis of the development of electricity demand that the Federal Ministry of Economics (BMWi) published on Tuesday. The main driver of the increase is therefore the transport sector. According to the paper, increased electric mobility in particular contributes 68 TWh to the increase, in line with rising EV power demand trends across markets. Around 44 TWh of this should be for cars, 7 TWh for light commercial vehicles and 17 TWh for heavy trucks. If the electricity consumption for buses and two-wheelers is added, this results in electricity consumption for e-mobility of around 70 TWh.

The number of purely battery-powered vehicles is increasing according to the investigation by the BMWi to 16 million by 2030, reflecting the global electric car market momentum, plus 2.2 million plug-in hybrids. In 2018 there were only around 100,000 electric cars, the associated electricity consumption was an estimated 0.3 TWh, and plug-in mileage in 2021 highlighted the rapid uptake elsewhere. For heat pumps, the researchers predict an increase in demand by 35 TWh to around 42 TWh. They estimate the electricity consumption for the production of around 12.5 TWh of green hydrogen in 2030 to be just under 20 TWh. The demand at battery factories and data centers will increase by 13 TWh compared to 2018 by this point in time. In the data centers, there is no higher consumption due to more efficient hardware despite advancing digitization.

The updated figures are based on ongoing scenario calculations by Prognos, in which the market researchers took into account the goals of the Climate Protection Act for 2030 and the wider European electrification push for decarbonization. In the preliminary estimate presented by Federal Economics Minister Peter Altmaier (CDU) in July, a range of 645 to 665 TWh was determined for gross electricity consumption in 2030. Previously, Altmaier officially said that electricity demand in this country would remain constant for the next ten years. In June, Chancellor Angela Merkel (CDU) called for an expanded forecast that would have to include trends in e-mobility adoption within a decade and the Internet of Things, for example.

Higher electricity demand
The Federal Association of Energy and Water Management (BDEW) is assuming an even higher electricity demand of around 700 TWh in nine years. In any case, a higher share of renewable energies in electricity generation of 70 percent by 2030 is necessary in order to be able to achieve the climate targets and to address electricity price volatility risks. The expansion paths urgently need to be increased and obstacles removed. This could mean around 100 gigawatts (GW) for onshore wind turbines, 11 GW for biomass and at least 150 GW for photovoltaics by 2030. Faster network expansion and renovation will also become even more urgent, as electric cars challenge grids in many regions.
 

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Ukraine Electricity Exports resume to the European grid, starting with Moldova and expanding to Poland, Slovakia, and Romania, signaling energy security, grid resilience, added megawatts, and recovery after Russian strikes with support and renewables.

Key Points

Ukraine Electricity Exports are resumed sales of surplus power to EU neighbors, reflecting grid recovery and resilience.

✅ Initial deliveries to Moldova; Poland, Slovakia, Romania to follow.

✅ Extra capacity from repairs, warmer demand, and renewables.

✅ Exports may vary amid ongoing Russian strikes risk.

Ukraine began resuming electricity exports to European countries on Tuesday, its energy minister said, a dramatic turnaround from six months ago when fierce Russian bombardment of power stations plunged much of the country into darkness in a bid to demoralize the population.

The announcement by Energy Minister Herman Halushchenko that Ukraine was not only meeting domestic consumption demands but also ready to restart exports to its neighbors was a clear message that Moscow’s attempt to weaken Ukraine by targeting its infrastructure did not work.

Ukraine’s domestic energy demand is “100%” supplied, he told The Associated Press in an interview, and it has reserves to export due to the “titanic work” of its engineers and international partners.

Russia ramped up infrastructure attacks in September, when waves of missiles and exploding drones destroyed about half of Ukraine’s energy system. Power cuts were common across the country as temperatures dropped below freezing and tens of millions struggled to keep warm.

Moscow said the strikes were aimed at weakening Ukraine’s ability to defend itself, and has also moved to reactivate the Zaporizhzhia plant through new power lines, while Western officials said the blackouts that caused civilians to suffer amounted to war crimes. Ukrainians said the timing was designed to destroy their morale as the war marked its first anniversary.

Ukraine had to stop exporting electricity in October to meet domestic needs.

Engineers worked around the clock, often risking their lives to come into work at power plants and keep the electricity flowing. Kyiv’s allies also provided help. In December, U.S. Secretary of State Antony Blinken announced $53 million in bilateral aid to help the country acquire electricity grid equipment, and USAID mobile gas turbine plant support, on top of $55 million for energy sector support.

Much more work remains to be done, Halushchenko said. Ukraine needs funding to repair damaged generation and transmission lines, and revenue from electricity exports would be one way to do that.

The first country to receive Ukraine’s energy exports will be Moldova, he said.

Besides the heroic work by engineers and Western aid, warmer temperatures are enabling the resumption of exports by making domestic demand lower, even as Germany’s coal generation shapes regional power flows.

Renewables like solar and wind power also come into play as temperatures rise, taking some pressure off nuclear and coal-fired power plants.

But it’s unclear if Ukraine can keep up exports amid the constant threat of Russian bombardment, with any potential agreement on power plant attacks still uncertain.

“Unfortunately now a lot of things depend on the war,” Halushchenko said. “I would say we feel quite confident now until the next winter.”

Exports to Poland, Slovakia and Romania are also on schedule to resume, he said.

“Today we are starting with Moldova, and we are talking about Poland, we are talking about Slovakia and Romania,” Halushchenko added, noting that how much will depend on their needs.

“For Poland, we have only one line that allows us to export 200 megawatts, but I think this month we will finish another line which will increase this to an additional 400 MW, so these figures could change,” he said.

Export revenue will depend on fluctuating electricity prices in Europe, where stunted hydro and nuclear output may affect recovery. In 2022, while Ukraine was still able to export energy, Ukrainian companies averaged 40 million to 70 million euros a month depending on prices, Halushchenko said.
 

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Utility Renewable Investment Gap highlights Oxford study in Nature Energy: most electric utilities favor fossil fuels over clean energy transition, expanding coal and gas, risking stranded assets and missing climate targets despite global decarbonization commitments.

Key Points

Most utilities grow fossil capacity over renewables, slowing decarbonization and jeopardizing climate goals.

✅ Only 10% expand renewables faster than coal and gas growth

✅ 60% still add fossil plants; 15% actively cut coal and gas

✅ Risks: stranded assets, missed climate targets, policy backlash

Only one in 10 of the world’s electric utility companies are prioritising clean energy investment over growing their capacity of fossil fuel power plants, according to research from the University of Oxford.

The study of more than 3,000 utilities found most remain heavily invested in fossil fuels despite international efforts to reduce greenhouse gas emissions and barriers to 100% renewables in the US that persist, and some are actively expanding their portfolio of polluting power plants.

The majority of the utility companies, many of which are state owned, have made little change to their generation portfolio in recent years.

Only 10% of the companies in the study, published in the research journal Nature Energy, are expanding their renewable energy capacity, mirroring global wind and solar growth patterns, at a faster rate than their gas- or coal-fired capacity.

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Of the companies prioritising renewable energy growth, 60% have not stopped concurrently expanding their fossil fuel portfolio and only 15% of these companies are actively reducing their gas and coal capacity.

Galina Alova, the author of the report, said the research highlighted “a worrying gap between what is needed” to tackle the climate crisis, with calls for a fossil fuel lockdown gaining attention, and “what actions are being taken by the utility sector”.

The report found 10% of utilities were favouring growth in gas-fired power plants. This cluster is dominated by US utilities, even as renewables surpass coal in US generation in the broader market, eager to take advantage of the country’s shale gas reserves, followed by Russia and Germany.

Only 2% of utilities are actively growing their coal-fired power capacity ahead of renewables or gas. This cluster is dominated by Chinese utilities – which alone contributed more than 60% of coal-focused companies – followed by India and Vietnam.

The report found the majority of companies prioritising renewable energy were clustered in Europe. Many of the industry’s biggest players are investing in low-carbon energy and green technologies, even as clean energy's dirty secret prompts debate, to replace their ageing fossil fuel power plants.

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In the UK, amid UK renewables backlog that has stalled billions, coal plants are shutting at pace ahead of the government’s 2025 ban on coal-fired power in part because the UK’s domestic carbon tax on power plants make them uneconomic to run.

“Although there have been a few high-profile examples of individual electric utilities investing in renewables, this study shows that overall, the sector is making the transition to clean energy slowly or not at all,” Alova said.

“Utilities’ continued investment in fossil fuels leaves them at risk of stranded assets – where power plants will need to be retired early – and undermines global efforts to tackle climate change.”
 

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Hertel-New York Interconnection delivers Hydro-Quebec renewable energy via a cross-border transmission line to New York City by 2025, supplying 1,250 MW through underground and underwater routes under a 25-year contract.

Key Points

A cross-border line delivering 1,250 MW of Hydro-Quebec hydropower to New York City via underground routes.

✅ 1,250 MW clean power to NYC by 2025

✅ 56.1 km underground, 1.6 km underwater in Quebec

✅ 25-year contract; Mohawk partnership revenue

Hydro-Quebec announced Thursday it has chosen the route for the Hertel-New York interconnection line, which will begin construction in the spring of 2023 in Quebec.

The project will deliver 1,250 megawatts of Quebec hydroelectricity to New York City starting in 2025, even as a recent electricity shortage report warns about rising demand at home.

It's a 25-year contract for Hydro-Quebec, the largest export contract for the province-owned company, and comes as hydrogen production investments gain traction in Eastern Canada.

The Crown corporation has not disclosed potential revenues from the project, but Premier François Legault mentioned on social media last September that a deal in principle worth more than $20 billion over 25 years was in the works.

The route includes a 56.1-kilometre underground and a 1.6-kilometre underwater section, similar to the Lake Erie Connector project planned under Lake Erie.

Eight municipalities in the Montérégie region will be affected: La Prairie, Saint-Philippe, Saint-Jacques-le-Mineur, Saint-Édouard, Saint-Patrice-de-Sherrington, Saint-Cyprien-de-Napierville, Saint-Bernard-de-Lacolle and Lacolle.

Across the country, new renewables such as wind projects in Yukon are receiving federal support, reflecting broader grid decarbonization.

The last part of the route will run along Fairbanks Creek to the Richelieu River, where it will connect with the American network.

Further south, there will be a 545-kilometre link between the Canada-U.S. border and New York City, while a separate Maine transmission approval advances a New England pathway for Quebec power.

Hydro-Quebec is holding two consultations on the project, on Dec. 8 in Lacolle and Dec. 9 in Saint-Jacques-le-Mineur.

Elsewhere in Atlantic Canada, EV-to-grid integration pilots are underway to test how vehicles can support the power system.

Once the route is in service, the Quebec line will be subject to a partnership between Hydro-Quebec and the Mohawk Council of Kahnawake, which will benefit from economic remunerations for 40 years.

To enhance reliability, grid-scale battery storage projects are also expanding in Ontario.

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Texas PUC Electricity Market Reforms aim to boost grid reliability, support ERCOT resilience, pay standby generators, require capacity procurement, and mitigate blackout risk, though analysts warn higher consumer bills and winter reserve margin deficits.

Key Points

PUC proposals to bolster ERCOT reliability via standby capacity, capacity procurement, and measures to reduce blackout risk.

✅ Pays generators for standby capacity during grid stress

✅ Requires capacity procurement to meet forecast demand

✅ Could raise consumer bills despite reliability gains

The Public Utility Commission of Texas is discussing major reforms to the state’s electricity market with the purpose to avoid a repeat of the power failures and blackouts during the February 2021 winter storm, which led to the death of more than 100 people and left over 11 million residents without electricity for days.

The regulator is discussing at a meeting on Thursday around a dozen proposals to make the grid more stable and reliable in case of emergencies. Proposals include paying power generators that are on standby when the grid needs backup, and requiring companies to pre-emptively buy capacity to meet future demand.

It is not clear yet how many and which of the proposals for electricity market reforms PUC will endorse today, while Texans vote on funding to modernize electricity generation later this year.

Analysts and consumer protection bodies warn that the measures will raise the energy bills for consumers, as some electricity market bailout ideas shift costs to ratepayers as well.

“Customers will be paying for more, but will they be getting more reliability?” Michael Jewell, an attorney with Jewell & Associates PLLC who represents clients at PUC proceedings, told Bloomberg.

“This is going to take us further down a path that’s going to increase cost to consumers, we better be darn sure these are the right choices,” Tim Morstad, Associate State Director, AARP Texas, told FOX 4 NEWS.

Last month, a report by the North American Electric Reliability Corp warned that the Texas power grid remained vulnerable to blackouts in case of a repeat of this year’s February Freeze.

Beyond Texas, electricity blackout risks have been identified across the U.S., underscoring the stakes for grid planning.

According to the 2021-2022 Winter Reliability Assessment report, Texas risks a 37-percent reserve margin deficit in case of a harsh winter, with ERCOT moving to procure capacity to address winter concerns, NERC said.

A reserve margin is the reserve of power generation capacity comparative to demand. The expected reserve margin for Texas for this winter, according to NERC, is 41.9 percent. Yet if another cold spell hits the state, it would affect this spare capacity, pushing the margin deeply into negative territory.

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Electric Ireland Electricity Price Increase stems from rising wholesale costs as energy suppliers adjust tariffs. Customers face higher electricity bills, while gas remains unchanged; switching provider could deliver savings during winter.

Key Points

A 4% increase in Electric Ireland electricity prices from 1 Feb 2018, driven by wholesale costs; gas unchanged.

✅ 4% electricity rise effective 1 Feb 2018

✅ Increase attributed to rising wholesale energy costs

✅ Switching supplier may reduce bills and boost savings

ELECTRIC IRELAND has announced that it will increase its household electricity prices by 4% from 1 February 2018.

This comes just a week after both Bord Gáis Energy and SSE Airtricity announced increases in their gas and electricity prices, while national efforts to secure electricity supplies continue in parallel.

Electric Ireland has said that the electricity price increase is unavoidable due to the rising wholesale cost of electricity, with EU electricity prices trending higher as well.

The electricity provider said it has no plans to increase residential gas prices at the moment.

Commenting on the latest announcement, Eoin Clarke, managing director of Switcher.ie, said: “This is the third largest energy supplier to announce a price increase in the last week, so the other suppliers are probably not far behind.

“The fact that the rise is not coming into effect until 1 February will be welcomed by Electric Ireland customers who are worried about the rising cost of energy as winter sets in,” he said.

However, any increase is still bad news, especially as a quarter of consumers (27%) say their energy bill already puts them under financial pressure, and EU energy inflation has disproportionately affected lower-income households.

According to Electric Ireland, this will amount to a €2.91 per month increase for an average electricity customer, amounting to €35 per year.

Meanwhile, SSE Airtricity’s change amounts to an increase of 90 cent per week or €46.80 per year for someone with average consumption on their 24hr SmartSaver standard tariff, far below the dramatic Spain electricity price surge seen recently.

Bord Gáis Energy said its announcement will increase a typical gas bill by €2.12 a month and a typical electricity bill by €4.77 a month, reflecting wider trends such as the Germany power price spike reported recently.

In a statement, Bord Gáis Energy said: “The changes, which will take effect from 1st November 2017, are due to significant increases in the wholesale cost of energy as well as higher costs associated with distributing energy on the gas and electricity networks.

“In percentage terms, the increase represents 3.4% in a typical customer’s gas bill and an increase of 5.9% in a typical customer’s electricity bill.”

Clark said that if customers haven’t switched electricity provider in over a year that they should review the deals available at the moment.

“The market is highly competitive so there are huge savings to be made by switching,” he said.

“All suppliers use the same cables to supply electricity to your home, so you don’t need to worry about any loss in service, and you could save up to 324 by switching from typical standard tariffs to the cheapest deals on the market.”

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