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ABL has secured a contract for the UK Subsea Power Link, highlighting ABL Group’s marine warranty role in Eastern Green Link 2, a 2 GW offshore electricity superhighway connecting Scotland and England to enhance grid reliability and renewable energy transmission.

Key Points: ABL Group’s contract for the UK Subsea Power Link

ABL Group has been appointed to provide marine warranty survey services for the 2 GW Eastern Green Link 2 subsea interconnector between Scotland and England.

✅ Manages vessel suitability checks, installation oversight, and DP assurance

✅ Strengthens UK grid reliability and advances the clean energy transition

✅ Sizeable contract valued between USD 1 million and 3 million

Energy and marine consultancy ABL, a subsidiary of ABL Group, has been awarded a contract by Eastern Green Link 2 (EGL2) to provide marine warranty survey (MWS) services for the installation of a new 2 GW subsea power connection between Scotland and England.

EGL2 is one of the United Kingdom’s most significant energy-infrastructure projects, involving the creation of a 505-kilometre “electricity superhighway” that will enable simultaneous power transfer between Peterhead in Aberdeenshire and Drax in North Yorkshire, mirroring a renewable power link announced for the same corridor recently. The project is designed to strengthen grid resilience, integrate renewable energy from Scotland’s offshore resources, and advance the UK’s broader energy transition goals.

Under the terms of the contract, ABL will be responsible for the technical review and approval of the project and procedural documentation, as well as conducting suitability surveys of the proposed fleet for marine transportation and installation operations. The company will also provide dynamic positioning (DP) assurance where required and will review and approve all warranted operations through on-site attendances, reflecting practices used on projects like the Great Northern Transmission Line in North America.

Cable-laying operations for the link are scheduled to take place between January and September 2028, amid wider efforts to fast-track grid connections across the UK. According to ABL, the engagement represents a “sizeable” contract, valued between USD 1 million and 3 million.

“This appointment reflects ABL's reputation as a trusted MWS partner for major power transmission infrastructure development and reinforces our position at the forefront of supporting the UK's energy transition,” said Hege Norheim, CEO of ABL Group. “We look forward to contributing to this strategic initiative.”

The subsea interconnector, known as Eastern Green Link 2, will transmit up to 2 gigawatts of electricity—enough to power approximately 2 million homes. It forms part of the Great Grid Upgrade, National Grid’s nationwide program to modernize and expand the transmission network in preparation for a low-carbon future, alongside a recent 2 GW substation milestone.

By linking renewable-rich northern Scotland with high-demand regions in England, EGL2 is expected to reduce congestion on the existing grid by leveraging HVDC technology to improve transfer efficiency, enhance security of supply, and facilitate the more efficient flow of surplus renewable energy south. The connection will also support the UK government’s target of decarbonizing the electricity system by 2035.

ABL’s appointment follows a period of intensive marine and geotechnical surveys along the proposed cable route to assess seabed conditions and environmental sensitivities. The company’s marine warranty oversight will ensure that transportation and installation operations meet strict safety, technical, and environmental standards demanded by insurers and project partners, as seen in a recent cross-border transmission approval in North America.

For ABL Group, which provides engineering and risk services to the offshore energy and marine industries worldwide, the contract marks another milestone in its expanding portfolio of subsea power and transmission projects across Europe. With operations set to begin in 2028, the Eastern Green Link 2 initiative represents both a major engineering challenge and a key enabler of the UK’s offshore energy ambitions, echoing a recent offshore wind power milestone in the U.S.

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Offshore Wind-to-Hydrogen Integration enables green hydrogen by embedding an electrolyzer in offshore turbines. Siemens Gamesa and Siemens Energy align under H2Mare to decarbonize industry, advance the Paris Agreement, and unlock scalable, off-grid renewable production.

Key Points

A method integrating electrolyzers into offshore wind turbines to generate green hydrogen and reduce carbon emissions.

✅ Integrated electrolyzer at turbine base for off-grid operation

✅ Enables scalable, cost-efficient green hydrogen production

✅ Supports decarbonization targets under Paris Agreement

To reach the Paris Agreement goals, the world will need vast amounts of green hydrogen and, with offshore wind growth accelerating, wind will provide a large portion of the power needed for its production.

Siemens Gamesa and Siemens Energy announced today that they are joining forces combining their ongoing wind-to-hydrogen developments to address one of the major challenges of our decade - decarbonizing the economy to solve the climate crisis.

The companies are contributing with their developments to an innovative solution that fully integrates an electrolyzer into an offshore wind turbine as a single synchronized system to directly produce green hydrogen. The companies intend to provide a full-scale offshore demonstration of the solution by 2025/2026. The German Federal Ministry of Education and Research, reflecting Germany's clean energy progress, announced today that the developments can be implemented as part of the ideas competition 'Hydrogen Republic of Germany'.

'Our more than 30 years of experience and leadership in the offshore wind industry, coupled with Siemens Energy's expertise in electrolyzers, brings together brilliant minds and cutting-edge technologies to address the climate crisis. Our wind turbines play a huge role in the decarbonization of the global energy system, and the potential of wind to hydrogen means that we can do this for hard-to-abate industries too. It makes me very proud that our people are a part of shaping a greener future,' said Andreas Nauen, Siemens Gamesa CEO.

Christian Bruch, CEO of Siemens Energy, explains: 'Together with Siemens Gamesa, we are in a unique position to develop this game changing solution. We are the company that can leverage its highly flexible electrolyzer technology and create and redefine the future of sustainable offshore energy production. With these developments, the potential of regions with abundant offshore wind, such as the UK offshore wind sector, will become accessible for the hydrogen economy. It is a prime example of enabling us to store and transport wind energy, thus reducing the carbon footprint of economy.'

Over a time frame of five years, Siemens Gamesa plans to invest EUR 80 million and Siemens Energy is targeting to invest EUR 40 million in the developments. Siemens Gamesa will adapt its development of the world's most powerful turbine, the SG 14-222 DD offshore wind turbine to integrate an electrolysis system seamlessly into the turbine's operations. By leveraging Siemens Gamesa's intricate knowledge and decades of experience with offshore wind, electric losses are reduced to a minimum, while a modular approach ensures a reliable and efficient operational set-up for a scalable offshore wind-to-hydrogen solution. Siemens Energy will develop a new electrolysis product to not only meet the needs of the harsh maritime offshore environment and be in perfect sync with the wind turbine, but also to create a new competitive benchmark for green hydrogen.

The ultimate fully integrated offshore wind-to-hydrogen solution will produce green hydrogen using an electrolyzer array located at the base of the offshore wind turbine tower, blazing a trail towards offshore hydrogen production. The solution will lower the cost of hydrogen by being able to run off grid, much like solar-powered hydrogen in Dubai showcases for desert environments, opening up more and better wind sites. The companies' developments will serve as a test bed for making large-scale, cost-efficient hydrogen production a reality and will prove the feasibility of reliable, effective implementation of wind turbines in systems for producing hydrogen from renewable energy.

The developments are part of the H2Mare initiative which is a lighthouse project likely to be supported by the German Federal Ministry of Education and Research ideas competition 'Hydrogen Republic of Germany'. The H2mare initiative under the consortium lead of Siemens Energy is a modular project consisting of multiple sub-projects to which more than 30 partners from industry, institutes and academia are contributing. Siemens Energy and Siemens Gamesa will contribute to the H2Mare initiative with their own developments in separate modular building blocks.

About hydrogen and its role in the green energy transition

Currently 80 million tons of hydrogen are produced each year and production is expected to increase by about 20 million tons by 2030. Just 1% of that hydrogen is currently generated from green energy sources. The bulk is obtained from natural gas and coal, emitting 830 million tons of CO2 per year, more than the entire nation of Germany or the global shipping industry. Replacing this current polluting consumption would require 820 GW of wind generating capacity, 26% more than the current global installed wind capacity. Looking further ahead, many studies suggest that by 2050 production will have grown to about 500 million tons, with a significant shift to green hydrogen already signaled by projects like Brazil's green hydrogen plant now underway. The expected growth will require between 1,000 GW and 4,000 GW of renewable capacity by 2050 to meet demand, and in the U.S. initiatives like DOE hydrogen hubs aim to catalyze this build-out, which highlights the vast potential for growth in wind power.

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California Nuclear Renewable Bill AB 2898 seeks to add nuclear to the Renewables Portfolio Standard, impacting Diablo Canyon, PG&E compliance, carbon-free targets, and potential license extensions while addressing climate goals and natural gas reliance.

Key Points

A bill to add nuclear to California's RPS, influencing Diablo Canyon, PG&E planning, and carbon-free climate targets.

✅ Reclassifies nuclear as renewable in California's RPS.

✅ Could influence Diablo Canyon license extension and ownership.

✅ Targets carbon-free goals while limiting natural gas reliance.

Although he admits it's a long shot, a member of the California Legislature from the district that includes the Diablo Canyon nuclear plant has introduced a bill that would add nuclear power to the state's list of renewable energy sources.

"I think that nuclear power is an important component of generating large-scale electricity that's good for the environment," said Jordan Cunningham, R-San Luis Obispo. "Without nuclear as part of the renewable portfolio, we're going to have tremendous difficulty meeting the state's climate goals without a significant cost increase on electricity ratepayers."

Established in 2002, California's Renewables Portfolio Standard spells out the power sources eligible to count toward the state's goals to wean itself of fossil fuels. The list includes solar, wind, biomass, geothermal, small hydroelectric facilities and even tidal currents. The standard has been updated, currently calling for 60 percent of California's electricity to come from renewables by 2030 and 100 percent from carbon-free sources by 2045, even as some analyses argue net-zero emissions may be difficult to achieve without nuclear power.

Nuclear power is not part of the portfolio standard and Diablo Canyon — the only remaining nuclear plant in California — is scheduled to stop producing electricity by 2025, even as some Southern California plant closures face postponement to maintain grid reliability.

Pacific Gas & Electric, the operators of Diablo Canyon, announced in 2016 an agreement with a collection of environmental and labor groups to shut down the plant, often framed as part of a just transition for workers and communities. PG&E said Diablo will become uneconomical to run due to changes in California's power grid — such as growth of renewable energy sources, increased energy efficiency measures and the migration of customers from traditional utilities to community choice energy programs.

But Cunningham thinks the passage of Assembly Bill 2898, which he introduced last week, — as innovators like Bill Gates' mini-reactor venture tout new designs — could give the plant literally a new lease on life.

"If PG&E were able to count the power produced (at Diablo) toward its renewable goals, it might — I'm not saying it will or would, but it might — cause them to reconsider applying to extend the operating license at Diablo," Cunningham said.

Passing the bill, supporters say, could also make Diablo Canyon attractive to an outside investor to purchase and then apply to the Nuclear Regulatory Commission for a license extension.

But nuclear power has long generated opposition in California and AB 2898 will face long odds in Sacramento, and similar efforts elsewhere have drawn opposition from power producers as well. The Legislature is dominated by Democrats, who have expressed more interest in further developing wind and solar energy projects than offering a lifeline to nuclear.

And if the bill managed to generate momentum, anti-nuclear groups will certainly be quick to mobilize, reflecting a national energy debate over Three Mile Island and whether to save struggling plants.

When told of Cunningham's bill, David Weisman, outreach coordinator for the Alliance for Nuclear Responsibility, said flatly, "Diablo Canyon has become a burdensome, costly nuclear white elephant."

Critics say nuclear power by definition cannot be considered renewable because it leaves behind waste in the form of spent nuclear fuel that then has to be stored, while supporters point to next-gen nuclear designs that aim to improve safety and costs. The federal government has not found a site to deposit the waste that has built up over decades from commercial nuclear power plants.

Even though Diablo Canyon is the only nuclear plant left in the Golden State, it accounts for 9 percent of California's power mix. Cunningham says if the plant closes, the state's reliance on natural gas — a fossil fuel — will increase, pointing to what happened when the San Onofre Nuclear Generating Station closed.

In 2011, the final full year operations for San Onofre, nuclear accounted for 18.2 percent of in-state generation and natural gas made up 45.4 percent. The following year, nuclear dropped to 9.3 percent and gas shot up to 61.1 percent of in-state generation.

"If we're going to get serious about being a national leader as California has been on dealing with climate change, I think nuclear is part of the answer," Cunningham said.

But judging from the response to an email from the Union-Tribune, PG&E isn't exactly embracing Cunningham's bill.

"We remain focused on safely and reliably operating Diablo Canyon Power Plant until the end of its current operating licenses and planning for a successful decommissioning," said Suzanne Hosn, a PG&E senior manager at Diablo Canyon. "The Assemblyman's proposal does not change any of PG&E's plans for the plant."

Cunningham concedes AB 2898 is "a Hail Mary pass" but said "it's an important conversation that needs to be had."

The second-term assemblyman introduced a similar measure late last year that sought to have the Legislature bring the question before voters as an amendment to the state constitution. But the legislation, which would require a two-thirds majority vote in the Assembly and the Senate, is still waiting for a committee assignment.

AB 2898, on the other hand, requires a simple majority to move through the Legislature. Cunningham said he hopes the bill will receive a committee assignment by the end of next month.
 

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Great Britain electricity generation spans renewables and baseload: wind, solar, nuclear, gas, and biomass, supported by National Grid interconnectors, embedded energy estimates, and BMRS data for dynamic imports and exports across Europe.

Key Points

A diverse, weather-driven mix of renewables, gas, nuclear, and imports coordinated by National Grid.

✅ Baseload from nuclear and biomass; intermittent wind and solar

✅ Interconnectors trade zero carbon imports via subsea cables

✅ Data from BMRS and ESO covers embedded energy estimates

Great Britain has one of the most diverse ranges of electricity generation in Europe, with everything from windfarms off the coast of Scotland to a nuclear power station in Suffolk tasked with keeping the lights on. The increasing reliance on renewable energy sources, as part of the country’s green ambitions, also means there can be rapid shifts in the main source of electricity generation. On windy days, most electricity generation comes from record wind generation across onshore and offshore windfarms. When conditions are cold and still, gas-fired power stations known as peaking plants are called into action.

The electricity system in Great Britain relies on a combination of “baseload” power – from stable generators such as nuclear and biomass plants – and “intermittent” sources, such as wind and solar farms that need the right weather conditions to feed energy into the grid. National Grid also imports energy from overseas, through subsea cables known as interconnectors that link to France, Belgium, Norway and the Netherlands. They allow companies to trade excess power, such as renewable energy created by the sun, wind and water, between different countries. By 2030 it is hoped that 90% of the energy imported by interconnectors will be from zero carbon energy sources, though low-carbon electricity generation stalled in 2019 for the UK.

The technology behind Great Britain’s power generation has evolved significantly over the last century, and at times wind has been the main source of electricity. The first integrated national grid in the world was formed in 1935 linking seven regions of the UK. In the aftermath of industrialisation, coal provided the vast majority of power, before oil began to play an increasingly important part in the 1950s. In 1956, the world’s first commercial nuclear reactor, Calder Hall 1 at Windscale (later Sellafield), was opened by Queen Elizabeth II. Coal use fell significantly in the 1990s while the use of combined cycle gas turbines grew, and in 2016 wind generated more electricity than coal for the first time. Now a combination of gas, wind, nuclear and biomass provide the bulk of Great Britain’s energy, with smaller sources such as solar and hydroelectric power also used. From October 2024, coal will no longer be used to generate electricity, following coal-free power records set in recent years.

Energy generation data is fetched from the Balancing Mechanism Reporting Service public feed, provided by Elexon – which runs the wholesale energy market – and is updated every five minutes, covering periods when wind led the power mix as well.

Elexon’s data does not include embedded energy, which is unmetered and therefore invisible to Great Britain’s National Grid. Embedded energy comprises all solar energy and wind energy generated from non-metered turbines. To account for these figures we use embedded energy estimates from the National Grid electricity system operator, which are published every 30 minutes.

Import figures refer to the net flow of electricity from the interconnectors with Europe and with Northern Ireland. A positive value represents import into the GB transmission system, while a negative value represents an export.

Hydro figures combine renewable run-of-the-river hydropower and pumped storage.

Biomass figures include Elexon’s “other” category, which comprises coal-to-biomass conversions and biomass combined heat and power plants.

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Shenao Power Plant Controversy intensifies as the EPA, Taipower, and New Taipei officials clash over EIA findings, a marine conservation area, fisheries, public health risks, and protests against a coal-fired plant in Rueifang.

Key Points

Dispute over coal plant EIA, marine overlap, and health risks, pitting EPA and Taipower against New Taipei and residents.

✅ EPA approved EIA changes; city cites marine conservation conflict

✅ Rueifang residents protest; 400+ signatures, wardens oppose

✅ Debate centers on fisheries, public health, and coal plant impacts

The controversy over the Shenao Power Plant heated up yesterday as Environmental Protection Administration (EPA) and New Taipei City Government officials quibbled over the project’s potential impact on a fisheries conservation area and other issues, mirroring New Hampshire hydropower clashes seen elsewhere.

State-run Taiwan Power Co (Taipower) wants to build a coal-fired plant on the site of the old Shenao plant, which was near Rueifang District’s (瑞芳) Shenao Harbor.

The company’s original plan to build a new plant on the site passed an environmental impact assessment (EIA) in 2006, similar to how NEPA rules function in the US, and the EPA on March 14 approved the firm’s environmental impact difference analysis report covering proposed changes to the project.

#google#

That decision triggered widespread controversy and protests by local residents, environmental groups and lawmakers, echoing enforcement disputes such as renewable energy pollution cases reported in Maryland.

The controversy reached a new peak after New Taipei City Mayor Eric Chu on Tuesday last week posted on Facebook that construction of wave breakers for the project would overlap with a marine conservation area that was established in November 2014.

The EPA and Taipower chose to ignore the demarcation lines of the conservation area, Chu wrote.

Dozens of residents from Rueifang and other New Taipei City districts yesterday launched a protest at 9am in front of the Legislative Yuan in Taipei, amid debates similar to the Maine power line proposal in the US, where the Health, Environment and Labor Committee was scheduled to review government reports on the project.

More than 400 Rueifang residents have signed a petition against the project, including 17 of the district’s 34 borough wardens, Anti-Shenao Plant Self-Help Group director Chen Chih-chiang said.

Ruifang residents have limited access to information, and many only became aware of the construction project after the EPA’s March 14 decision attracted widespread media coverage, Chen said,

Most residents do not support the project, despite Taipower’s claims to the contrary, Chen said.

New Power Party Executive Chairman Huang Kuo-chang, who represents Rueifang and adjacent districts, said the EPA has shown an “arrogance of power” by neglecting the potential impact on public health and the local ecology of a new coal-fired power plant, even as it moves to revise coal wastewater limits elsewhere.

Huang urged residents in Taipei, Keelung, Taoyaun and Yilan County to reject the project.

If the New Taipei City Government was really concerned about the marine conservation area, it should have spoken up at earlier EIA meetings, rather than criticizing the EIA decision after it was passed, Environmental Protection Administration Deputy Minister Chan Shun-kuei told lawmakers at yesterday’s meeting.

Chan said he wondered if Chu was using the Shenao project for political gain.

However, New Taipei City Environmental Protection Department specialist Sun Chung-wei  told lawmakers that the Fisheries Agency and other experts voiced concerns about the conservation area during the first EIA committee meeting on the proposed changes to the Shenao project on June 15 last year.

Sun was invited to speak to the legislative committee by Chinese Nationalist Party (KMT) Legislator Arthur Chen.

While the New Taipei City Fisheries and Fishing Port Affairs Management Office did not present a “new” opinion during later EIA committee meetings, that did not mean it agreed to the project, Sun said.

However, Chan said that Sun was using a fallacious argument and trying to evade responsibility, as the conservation area had been demarcated by the city government.

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Canada Clean Electricity Regulations 2050 balance net-zero goals with grid reliability and affordability, setting emissions caps, enabling offset credits, and flexible provincial pathways, including support for non-grid facilities during the clean energy transition.

Key Points

A federal plan for a net-zero grid by 2050 with emissions caps, offsets, and flexible provincial compliance.

✅ Emissions cap targeting 181 Mt CO2 from the power sector by 2050

✅ Offset credits and annual limits enable compliance flexibility

✅ Support for remote, non-grid facilities and regional pathways

In December 2024, the Government of Canada announced a significant policy shift regarding its clean electricity objectives. The initial target to achieve a net-zero electricity grid by 2035 has been extended to 2050. This decision reflects the government's response to feedback from provinces and energy industry stakeholders, who expressed concerns about the feasibility of meeting the 2035 deadline.

Revised Clean Electricity Regulations

The newly finalized Clean Electricity Regulations (CER) outline the framework for Canada's transition to a net-zero electricity grid by 2050, advancing the goal of 100 per cent clean electricity nationwide.

• Emissions Reduction Targets: The regulations set a cap on emissions from the electricity sector, targeting a reduction of 181 megatonnes of CO₂ by 2050. This is a decrease from the previous goal of 342 megatonnes, reflecting a more gradual approach to emissions reduction.

• Flexibility Mechanisms: To accommodate the diverse energy landscapes across provinces, the CER introduces flexibility measures. These include annual emissions limits and the option to use offset credits, allowing provinces to tailor their strategies while adhering to national objectives.

• Support for Non-Grid Connected Facilities: Recognizing the unique challenges of remote and off-grid communities, the regulations provide accommodations for certain non-grid connected facilities, ensuring that all regions can contribute to the national clean electricity goals.

Implications for Canada's Energy Landscape

The extension of the net-zero electricity target to 2050 signifies a strategic recalibration of Canada's energy policy. This adjustment acknowledges the complexities involved in transitioning to a clean energy future, including:

• Grid Modernization: Upgrading the electrical grid to accommodate renewable energy sources and ensure reliability is a critical component of the transition, especially as Ontario's EV wave accelerates across the province.

• Economic Considerations: Balancing environmental objectives with economic impacts is essential. The government aims to create over 400,000 clean energy jobs, fostering economic growth while reducing emissions, supported by ambitious EV goals in the transport sector.

• Regional Variations: Provinces have diverse energy profiles and resources, and British Columbia's power supply challenges highlight planning constraints. The CER's flexibility mechanisms are designed to accommodate these differences, allowing for tailored approaches that respect regional contexts.

Public and Industry Reactions

The policy shift has elicited varied responses:

• Environmental Advocates: Some environmental groups express concern that the extended timeline may delay critical climate action, while debates over Quebec's push for EV dominance underscore policy trade-offs. They emphasize the need for more ambitious targets to address the escalating impacts of climate change.

• Industry Stakeholders: The energy sector generally welcomes the extended timeline, viewing it as a pragmatic approach that allows for a more measured transition, particularly amid criticism of the 2035 EV mandate in transportation policy. The flexibility provisions are particularly appreciated, as they provide the necessary leeway to adapt to evolving market and technological conditions.

Looking Forward

As Canada moves forward with the implementation of the Clean Electricity Regulations, the focus will be on:

• Monitoring Progress: Establishing robust mechanisms to track emissions reductions and ensure compliance with the new targets.

• Stakeholder Engagement: Continuing dialogue with provinces, industry, and communities to refine strategies and address emerging challenges, including coordination on EV sales regulations as complementary measures.

• Innovation and Investment: Encouraging the development and deployment of clean energy technologies through incentives and support programs.

The extension of Canada's net-zero electricity target to 2050 represents a strategic adjustment aimed at achieving a balance between environmental goals and practical implementation considerations. The Clean Electricity Regulations provide a framework that accommodates regional differences and industry concerns, setting the stage for a sustainable and economically viable energy future.

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