Issue 97 - Risk and Safety Management

Consultancy

Projects and Modifications

Asset IMR/ Repair Orders

— TAR and Campaign Management

Asset Management

— Late Life and Decommissioning

Asset Specialist Services

Welcome to the October issue of ‘OGV Energy Magazine’, where this month we focus on the theme of ‘Risk and Safety Management’.

A big thank you to our front cover partner Safelift, for featuroing a compelling article from their CEO on pages 4–5, exploring the critical role of safety leadership in high-risk energy operations.

We are also delighted to feature contributions from Drager, LHR Marine, QHSE, Tess, and Sureclean, offering expert insights on safety protocols, risk mitigation, and best practices across the industry.

As always, the rest of this month’s magazine provides a comprehensive review of the energy sector in the North Sea, Europe, Norway, the Middle East, the US, and Australia, along with in-depth analysis, project updates, and practical guidance for operators, contractors, and safety professionals.

Thanks as always to our corporate partners, and we hope you enjoy this issue of OGV Energy.

PAST EXPERIENCE FUTURE ENERGY TOTAL SAFETY

Safety and quality to the fore on Aberdeenshire company’s growth journey

Delivering a culture of excellence

“We have developed an agile, customer-focused structure, which enables us to provide comprehensive, safety-led solutions which are customised for each specific environment, from clients’ industrial operations to greenfield developments.”

That’s according to Steven Simpson, managing director of Aberdeenshire-based inspection, lifting and manual handling provider, Safelift Offshore.

The company, which designs, supplies and manufactures equipment across the energy sector, has grown into a market leader through its unwavering commitment to safety and quality. This is reflected in the high levels of trust that clients hold Safelift in to deliver business-critical operations, where protecting lives is paramount.

A positive workplace culture is evident among all employees, including apprentices, who continue to play a pivotal role in the company’s continued evolution.

With a history dating back more than 30 years’, Safelift provides specialist services to oil and gas operators and EPC contractors active in the upstream development of major energy projects worldwide.

The North Sea is often viewed as the global benchmark for HSE and technical excellence. Increasingly, Safelift is exporting the skills perfected in this challenging environment with numerous projects underway or completed in Africa, the Middle East and south-east Asia.

“We have a deep understanding of the oftenharsh environments in which our equipment is deployed, and, to that end, we design and fabricate items to the highest standards of safety and efficacy.

It’s that dedication to quality which has forged our reputation as the go-to company for manual handling and lifting solutions,” explained Steven

Everything the company designs, supplies and manufactures has safety at the forefront. This approach has played a major role in Safelift’s success to date, while its in-house design and engineering team prioritises safety alongside bespoke, project-specific requirements to ensure that every solution is fit-for-purpose.

Drawing on over three decades of knowledge and experience, the company’s mission goes beyond manufacturing: delivering a complete wraparound service that not only improves daily operations but ensures the safety of the offshore workforce.

Key player in emerging renewables sector

Safelift Offshore played a key role in a landmark renewables project which is helping to power more than a million homes. The largest renewables project in Scotland, Seagreen Offshore Wind Farm is located 27km off the Angus coast in the North Sea.

Seagreen has 114 turbines with a total generating capacity of 1,075MW – enough to power more than 1.6million homes, equivalent to two-thirds of all Scottish homes. It is expected to offset approximately 900,000 tonnes of carbon dioxide every year.

Safelift provided a full manual handling and access package for the newly-built substation at Tealing, near Dundee, and worked collaboratively with alliance partners, including operator SSE Renewables, to provide a complete solution that prioritises safety and will deliver lasting benefits to stakeholders and local communities.

Steven Simpson

This project showcased the breadth and depth of technical capabilities possessed by the Safelift team. Faced with access issues due to the compact nature of substations, Safelift used its knowledge base to provide a complete package for lifting, manual handling and access.

With an increasing number of large renewables projects coming on stream over the coming years around Scotland and further afield, this creates opportunities for the company to develop its expertise in this fast-developing industry.

Technical package services

Safelift Offshore is a respected market leader in the design, supply and manufacture of all types of lifting and handling equipment for the energy industry, while its team understands the requirements faced by products operating in a harsh offshore environment.

In addition to Safelift’s own, high-quality branded products, the company supplies a select range of approved manual handling products from other UK and European manufacturers. This includes powered and non-powered access solutions, electric tugs, gantry cranes, and hoists from trusted partners.

This integrated approach offers clients a comprehensive technical procurement service: from front-end engineering to daily operations onboard their assets.

Moreover, Safelift has wide-ranging experience in adapting these solutions for different sectors and specific geographic locations.

“We provide a comprehensive range of standard products but also design and manufacture custom-built items for specialist applications,” said Steven.

He added: “With renewables, we have had to create bespoke adaptations to make equipment smaller or lighter to cater for specific conditions, such as designs to overcome access restrictions when working with substations for offshore wind.”

Safelift sources and procures an extensive range of reputable third-party products in addition to building its own quality equipment. The company is now expanding its technical services and project management capabilities to provide a comprehensive end-to-end procurement solution for clients operating in the energy, marine and renewables sectors.

Historically, the company has largely worked alongside operators and EPCs to develop

custom-built products and equipment, while providing project management from start to finish that helps streamline clients’ supply chain and technical procurement processes.

Exciting next chapter

Despite a growing international client base, Safelift Offshore remains fiercely proud of its roots in rural Aberdeenshire as demonstrated through its clear commitment to local recruitment, procurement and the supply chain.

The company has invested around £1million in the past year to enhance facilities at its Kemnay headquarters and expand the team, with a view to fulfilling more complex projects across the energy sector.

This includes the opening of a state-of-theart fabrication facility earlier this year, which increases capacity for large-scale projects in the global offshore wind and renewables sectors.

Supported by the ETZ Challenge Fund, the new facility’s increased floorspace will allow the team to work with larger pieces of equipment, frames and container solutions, while providing additional storage to support projects. 

Hot work barriers and localised hydrostatic testing to verify the integrity of welds or ttings, reducing system downtime, minimising environmental impact and increasing worksite safety.

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COMMUNITY news

RWE awards frame agreement for maintenance of German offshore substations to Semco Maritime

Starting in September 2025, RWE Offshore Wind GmbH (RWE) has awarded Semco Maritime GmbH with an offshore services frame agreement until end of 2027, with an option for a 2-year extension.

The agreement covers scheduled and unscheduled maintenance above water and troubleshooting services of the auxiliary equipment at offshore substations of RWE in Germany.

The project scope currently spans the offshore wind farms in the North Sea: Amrumbank West, Nordsee Ost and Kaskasi near the island of Heligoland and Arkona in the Baltic Sea. When the Nordseecluster projects are fully commissioned by RWE and its partner Norges Bank Investment Management, those can be covered under the frame agreement in the same way.

Direct Travel Acquires ATPI Creates Modern Global Travel Management Powerhouse

Denver, CO – September 22, 2025 – Direct Travel, Inc., a leader in corporate travel management, has announced the acquisition of its long-time strategic partner, ATPI, creating one of the world’s largest travel management companies. Together, the two companies will drive over $6 billion in annual total travel volume and offer leading technologies and unparalleled service across global corporate, leisure, events, and specialized travel sectors.

The acquisition of ATPI, one of the most experienced and long-established international travel and event management companies, serves as a natural progression of the companies’ multi-year collaboration to serve the business travel needs of global corporate clients. The union will also help accelerate the international rollout of Avenir Travel Edition, Direct Travel’s next-generation platform designed to delight business travelers, empower travel managers with real-time intelligence and create new value for travel suppliers.

Partners with Funk Futures for Strategic Expansion in the US Energy Market

Houston, TX – 09/17/2025: Funk Futures, a leading growth consultancy for energy companies, today announced a strategic partnership with KCI, a specialist in well integrity, intervention and leak sealing for brownfield and greenfield assets, to expand their presence in the North American energy market.

Since its founding in 2002, KCI has built a strong reputation by tackling some of the industry’s toughest engineering challenges across subsea, topside, pipeline, downhole, and process environments. From chemical leak sealing to isolation gels, KCI’s solutions are trusted to minimize downtime, cut costs, and extend the operating life of production assets. Their expertise lies in a holistic approach: rigorous asset assessment, customized procedures, and precise execution that enable operators to protect production and ensure longterm well integrity.

Quickflange™, ICR’s weldless connector technology, has received new third-party certifications and endorsements from the LRQA and Lloyd’s Register (LR).

The successful completion of these certifications, which include a Pressure Equipment Directive (2014/68/EU) Conformity Assessment by LRQA (March 2025) and Type Approval from LR (June 2025), follows a rigorous programme of technology evaluation, testing, and third-party audits initiated in early 2024.

These approvals represent a significant milestone for Quickflange™, unlocking new growth opportunities in key markets. They also reinforce our commitment to validating our technology against internationally recognised standards and seeking external endorsements for our qualification processes.

SLB has signed a definitive agreement to acquire RESMAN Energy Technology, a global leader in wireless reservoir surveillance solutions, in a move aimed at strengthening its production and recovery portfolio.

RESMAN’s proprietary tracer technologies, already in use across oil, gas, CO₂ storage, and geothermal projects, allow operators to track fluid movement in reservoirs with precision down to parts per trillion. These insights enable faster interventions, extended well life, and optimized recovery while minimizing operational disruptions.

SLB said the acquisition will integrate RESMAN’s tracer expertise with its own subsurface knowledge, digital workflows, and production systems. The company expects the combined offering to provide operators with earlier detection of unwanted fluids, improved recovery outcomes, and enhanced monitoring of CO₂ storage sites under carbon capture initiatives.

FourPhase, a solids and production performance specialist for the oil and gas sector, has successfully performed an industry-first remote solids management operation in the North Sea. Delivered for Aker BP, the two-month programme marks a significant step forward in offshore operational efficiency and safety. FourPhase is the very first solids management specialist to perform remote operations offshore.

The project involved a coiled tubing (CT) cleanout of two wells with chalk bridges, with all returns managed topside by FourPhase. This included the provision of pipe, choke, Multiphase Flow Meter (MPFM), Surface Safety Valve (SSV), and the company’s DualFlow desander system, covering every aspect of returns handling and four-phase monitoring. This intervention was initiated to maintain and increase production from the reservoir.

Aker BP and FourPhase Deliver Industry-First Remote Solids Management

LATEST OGV COMMUNITY SIGN-UPS

ICR is a technology driven global provider of specialist maintenance, integrity and inspection solutions for the oil and gas, power, defence, nuclear, utilities and renewables industries. We are committed to the future of a low carbon economy whist transitioning to net zero and we are continuously looking at ways to enhance our longevity and assurance through our technological innovation.

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Enerion is a leading provider of products and services to the energy sector. We have extensive experience in engineering, manufacturing and service of equipment and are committed to deliver flexible and futureoriented solutions to our customers.

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UK North Sea Energy Review

By Tsvetana Paraskova

The future of the North

Sea offshore industry and the UK windfall tax on operators were the key themes in Britain’s oil and gas sector in the past few weeks.

The call for immediate action comes in the 50th anniversary year of the iconic Forties Pipeline System and as OEUK’s Economic Report 2025 highlighted the UK is now importing more than 40 percent of its energy, while Apache, Chevron, and leading firms also withdraw investment from the UK and focus on investing in jobs and projects in other countries.

“There is no time to lose – jobs are being lost today. The offer from industry is clear – reform to this tax now to protect UK jobs, investment and the economy,” said David Whitehouse, CEO of Offshore Energies UK.

“The North Sea has been the powerhouse of the UK’s industrial success and prosperity and with the right fiscal and economic policies it can be the platform for an era of economic success.”

“What happens to the North Sea does not stay in the North Sea. It ripples across sectors through Aberdeen, Grangemouth, Humberside, Teesside, Tyneside, East Anglia, the Northwest. It undermines our manufacture of fuels, chemicals, pharmaceuticals. We risk an industrial contagion,” Whitehouse added.

OEUK is urging the government to reform the EPL as practicable as possible because a stable, investment-friendly fiscal regime is critical to unlocking £200 billion in private capital across the UK’s energy mix.

If OEUK’s proposed reforms are implemented soon, the UK could add £137 billion to the economy by 2050 , secure £41 billion of extra investment in UK energy by 2050 , support 23,000 additional jobs by 2030 , and unlock £12 billion in additional tax receipts by 2050.

“Without changes to the fiscal regime, UK oil and gas could disappear within years, not decades. That’s a risk we cannot take,” OEUK’s Whitehouse commented

“By making the most of our homegrown oil and gas while accelerating renewables, the UK can turn one of its greatest assets – the waters around its coast – into a strong driver of economic growth. We need both oil and gas and renewable energy.”

UK oil and gas industry leaders and trade bodies continue to urge the government to implement urgent fiscal reform to ensure energy investment in Britain and end one of the most burdensome tax regimes for operators.

Jim Ratcliffe’s Ineos Energy is ending its investment in the UK and is pivoting to the US, to flee what the company has described as “one of the most unstable fiscal regimes in the world.”

“We have stopped investing in Britain. Our future investment will not be in the UK. There’s no question of that,” Ineos Executive Chairman Brian Gilvary told the Telegraph in early September.

“The problem is that the UK has become one of the most unstable fiscal regimes in the world from a perspective of natural resources and energy. It means we cannot invest with any certainty because we can’t be sure what future tax rates will be,” Gilvary said.

In response to this, Offshore Energies UK, the sector’s trade body, urged the government to immediately reform the Energy Profits Levy (EPL), commonly known as the windfall tax, on operators in the UK North Sea.

A recent OEUK report showed the negative impact of the current Energy Profits Levy on the UK economy and the oil and gas sector. The UK will struggle to make 40 percent of the tax revenues originally projected as it is choking investment, OEUK said.

However, if changes are put in place by 2026 and announced in the autumn budget, this sector could contribute an additional £137 billion to the value of the economy by 2050, the report found.

OEUK proposes the government replace the current windfall structure with a progressive, profit-based model.

The proposal would mean the windfall tax would become a permanent profit-based mechanism activated only when both oil and gas prices exceed a set threshold. The headline tax rate drops from 78 percent to 40 percent but the new mechanism would still ensure additional tax revenue is generated when commodity prices are high.

This model, OEUK argues, would offer companies greater predictability, a fairer investment environment, and stronger incentives to reinvest in UK projects. All of these would unlock new developments, supporting jobs and delivering a more stable production outlook through to 2050.

Whitehouse noted that “Changing the Energy Profits Levy would allow UK oil and gas operators to continue paying higher taxes when prices are high, while giving them the confidence to invest, knowing those taxes will adjust fairly when prices drop.”

“Our 200,000-strong industry has the skills and infrastructure to build a homegrown energy future. We now need a fiscal regime and energy policy that can help us deliver it.”

Commenting on the fiscal regime, Wood Mackenzie, the energy consultancy, said in a report in early September that the UK government faces a critical fiscal challenge as it prepares to unveil its replacement for the EPL in November’s budget.

Policymakers must navigate inevitable tradeoffs between administrative simplicity and fairness to operators and the nation in the ultramature UK Continental Shelf, Wood Mackenzie’s analysis reveals.

The stakes of this policy reform are high for the UKCS, where investment attractiveness hangs in the balance, WoodMac said.

The government is considering two approaches for the new mechanism. One is a revenue-based mechanism. This offers administrative simplicity but risks penalising high-cost operators unfairly. The other is a profits-based approach, which delivers greater fairness but introduces significant complexity.

Wood Mackenzie has identified the critical determinants of the mechanism’s impact as the price thresholds that trigger “unusually high prices”, and the tax rate applied.

“The government must carefully balance all these factors, to arrive at a fair and simple mechanism, that will also be stable and predictable,” WoodMac said.

Currently, the UK is losing the competitiveness race for attracting investment, the energy consultancy says.

For example, the US Gulf of Mexico (GoM) offers marginal rates of 31-35 percent, less than half the current UK rate and below the 40 percent that will apply in the UK post-2030 under normal conditions.

Much closer to the UK, Norway’s 78-percent tax rate matches current UK levels, but the Norwegian industry is dominated by state ownership of resources and is significantly less explored than the UK or US GoM.

Wood Mackenzie has estimated that the UK government’s share of pre-tax profits sits near 40 percent at both US$80 and US$120 per barrel without the EPL. The global peer group averages 62 percent government share at US$120, indicating room for increases during high-price periods whilst maintaining competitive positioning.

“The UK’s cost disadvantage stems from operating in an ultra-mature, heavily explored basin with 90% of remaining resources already onstream or under development,” said Graham Kellas, senior vice president of fiscal research at Wood Mackenzie.

“A competitive fiscal regime becomes crucial to offset these inherent challenges and attract continued investment. And for many operators, 2030 will be too late to restore UK competitiveness.”

Outside the realm of UK’s fiscal policy, the North Sea Transition Authority (NSTA) has published its 2025 Emissions Monitoring Report, which showed production emissions from the UK’s offshore oil and gas industry fell by 34 percent between 2018 and 2024.

The offshore oil and gas industry has made further progress lowering its production emissions, cutting these by 7 percent in 2024 from 2023, for a fifth consecutive year of reductions.

Flaring activity, which is the second largest source of production emissions, declined by 4.8 percent in 2024 to the lowest level on record, and was 51 percent lower than in 2018, according to NSTA’s findings.

But the report also showed projected reductions are lagging behind ambitions in the longer term unless there is significant new action. The target of halving emissions by 2030, agreed by industry and government in the North Sea Transition Deal, is now well within reach.

However, without serious investment in large-scale active emissions abatement projects, industry will

UK ENERGY REVIEW

not meet the 2040 target of lowering emissions by 90 percent or achieve net zero by 2050 – in what would be a blow to its credibility.

“As such North Sea oil and gas operators must take bold and rapid action on emissions to hit key net zero targets and justify domestic production over the coming decades,” the regulator said.

“We’re encouraged that good work has begun, but there is still much more to do,” Hedvig Ljungerud, NSTA Director of Strategy, said.

“It is time to commit to serious, large-scale investments in emissions reduction, and secure a leading role in the North Sea’s transition into a clean energy powerhouse.”

Equinor and Shell announced in September the appointment of Neil McCulloch as chief executive officer and Nicoletta Giadrossi as chair of their offshore UK Incorporated Joint Venture, Adura.

The creation of Adura was announced in December 2024, after Equinor and Shell decided to combine their UK offshore oil and gas assets into a new incorporated joint venture. Adura will sustain domestic oil and gas production and security of energy supply in the UK and beyond, headquartered at the Silver Fin building in Aberdeen city centre.

McCulloch brings more than 30 years of leadership experience in the energy sector. He is currently the CEO of Spirit Energy, and has championed the role of oil and gas in supporting the UK’s energy transition.

Wood has secured a three-year contract extension to provide operations, maintenance, modifications, and support services (OMMS) on Equinor’s assets at the Mariner field in the UK North Sea.

With this extended contract, Wood will continue to support the delivery of Equinor strategic objectives through projects, upgrades and maintenance on the Mariner A platform and Mariner B floating storage unit.

Global investment firm Carlyle has agreed to acquire a diversified FPSO (Floating Production, Storage and Offloading) business from Altera Infrastructure Group, an offshore energy infrastructure company owned by Brookfield Asset Management’s private equity business.

Serica Energy plc announced in early September that the operator of the Triton FPSO, Dana Petroleum, had notified Serica of a temporary reduction in production while further maintenance takes place.

Due to a vibration issue within the compression trains on the Triton FPSO, production is currently running at a significantly reduced rate. Following the required repairs, normal production operations are expected to resume around the end of September.

In addition, Dana has also notified Serica that subsea intervention work on the Bittern field has been scheduled for November 2025.

As a result of production deferrals, Serica’s production guidance for 2025 has been reduced to 29,000 to 32,000 boepd, down from 33,000 to 35,000 boepd previously expected. 

THREE6O ENERGY A life cycle solutions company enabling a sustainable future.

Europe Energy Review

By Tsvetana Paraskova

Discoveries and drilling projects offshore Norway and Turkey, the launch of a massive European carbon capture project, and numerous solar, wind, and battery storage project updates featured in Europe’s energy industry in the past weeks.

Oil & Gas

Aker BP has successfully completed the Omega Alfa exploration campaign in the Norwegian North Sea, resulting in a significant oil discovery that adds substantial new resources to the Yggdrasil area. The recoverable volume is estimated at 96–134 million barrels of oil equivalent (mmboe).

“Omega Alfa is among the largest commercial discoveries in Norway in a decade,” said Karl Johnny Hersvik, CEO of Aker BP.

“Building on the momentum from the oil discovery at East Frigg in 2023, it marks a major step toward our ambition of producing more than one billion barrels from the Yggdrasil area.”

Yggdrasil is the largest field development project currently underway on the Norwegian Continental Shelf. The Plan for Development and Operation (PDO) was approved by the Norwegian authorities in 2023, and the project is progressing as planned, with first oil expected in 2027. The proven resource base is about 700 mmboe, with an ambition to grow this to more than one billion barrels through further exploration. The Omega Alfa discovery represents a significant building block in achieving this ambition, Aker BP said.

Equinor and partners have struck oil and gas in the Fram area, nine kilometres north of the giant Troll field in the North Sea. The discovery is estimated at between 0.6 and 6.9 million barrels of recoverable oil equivalent, the Norwegian Offshore Directorate said, adding that the licensees will consider tying the discovery into future or existing infrastructure in the area.

“These are discoveries in an interesting area with a well-developed infrastructure. In recent years, we have made several discoveries in the neighbourhood, and we plan to further explore the area,” said Geir Sørtveit, Equinor’s senior vice president for Exploration & Production West on the Norwegian continental shelf.

“We believe that we may encounter more, both oil and gas,” Sørtveit added.

Italy’s energy engineering group Saipem has been awarded a new offshore contract, worth about $1.5 billion, by Turkish Petroleum OTC for the third phase of the Sakarya gas field development project in Turkey.

Sakarya is the largest offshore natural gas field discovered in Turkey and is located about 170 km off the coast of Filyos, Zonguldak.

The third phase of development entails a new floating production unit (FPU), fed by 27 wells located in the Sakarya and Amasra fields, connected by a new trunkline to the onshore facility located in Filyos, on the Turkish Black Sea coast.

Saipem’s scope of work under the new contract encompasses the engineering, procurement, construction and installation (EPCI) of 8 rigid flowlines and a 24-inch diameter Gas Export Pipeline (GEP), approximately 183 km long, connecting the offshore field, at a maximum depth of 2,200 meters, to Filyos. The overall duration of the contract is approximately 3 years, while the offshore campaign will be conducted by Saipem’s Castorone pipelay vessel in 2027.

Low-Carbon Energy

The first carbon dioxide (CO2) volumes have now been injected and successfully stored at a reservoir 2,600 meters under the seabed as part of the Northern Lights project. With this, the world’s first third party CO2 transport and storage facility is now in operation, contributing to reducing European greenhouse gas emissions, the partners in the project – Equinor, Shell, and TotalEnergies – announced at the end of August.

The first CO2 volumes were successfully transported by vessel from Heidelberg Materials’ cement factory in Brevik, Norway, to Northern Lights’ facilities in Øygarden.

“With CO2 safely stored below the seabed, we mark a major milestone. This demonstrates the viability of carbon capture, transport and storage as a scalable industry,” Equinor CEO Anders Opedal said in a statement.

“Now, we look forward to leading safe and efficient operations on behalf of the Northern Lights partnership and use this as a stepping stone for the further development of CCS in Europe,” said Irene Rummelhoff, Executive Vice President of MMP at Equinor.

Equinor has also taken part in the $9.4-billion rights issue of the world’s largest offshore wind developer, Ørsted, in which the Norwegian energy major holds 10 percent. Equinor committed $939 million to keep its 10-percent stake after the rights issue, which is aimed at strengthening Ørsted’s balance sheet in response to the current industry challenges.

“Equinor’s support of the Rights Issue reflects confidence in Ørsted’s underlying business, and the competitiveness of offshore wind in the future energy mix, in selected geographies,” the Norwegian company said.

“Equinor believes that a closer industrial and strategic collaboration between Ørsted and Equinor can create value for all shareholders in both companies.”

In the UK, Octopus Energy and China’s wind turbine manufacturer Ming Yang Smart Energy have signed a partnership to deliver cheap, clean wind energy to British homes.

Octopus Energy Generation, the renewables arm of Octopus Energy, plans to deploy Ming Yang’s wind turbines to unleash the development of up to 6 GW of local energy capacity identified through Octopus’s matchmaking platform ‘Winder’.

“By combining Octopus’s expertise in smart technology and software with outstanding wind turbines, we can optimise every kilowatt and cut energy costs for millions of bill payers,” said Zoisa North-Bond, CEO of Octopus Energy Generation.

Edinburgh-based Fidra Energy announced in September it had secured up to £445 million of new equity investment from EIG and the National Wealth Fund as it reached financial close on the UK’s largest Battery Energy Storage System (BESS) project at its Thorpe Marsh site in Doncaster, South Yorkshire.

The 1,400 MW / 3,100MWh project, expected to be operational in mid-2027, will be the largest battery storage facility in the UK and among the largest in Europe. Once completed, Thorpe Marsh is expected to be three times larger than any other BESS project currently in operation or under construction in the UK and will have the potential to export over 2 million MWh annually, enough to supply about 785,000 homes each year.

“It’s fantastic to see the National Wealth Fund breathing new life into a former coal site — turning it into a cutting-edge battery hub that will power thousands of British homes and businesses with clean energy from wind and solar,” Energy Secretary Ed Miliband said.

Floating wind developer Cerulean Winds submitted in September the offshore consent applications for its flagship Aspen development to the Scottish Government.

Located approximately 100 km offshore in the Central North Sea, Aspen will deliver 1 GW of renewable power, targeting first generation before 2030. Aspen is expected to support more than 1,000 jobs, including 100 apprenticeships, and attract a total investment of £10.9 billion across its 50-year lifespan, Cerulean Winds said.

Aspen is being developed by a consortium of world-class partners – NOV, Siemens Energy, Bilfinger, and Ocean Installer – bringing proven expertise in delivering large-scale offshore projects.

The project is designed to enable oil and gas operators to rapidly decarbonise their operations, while simultaneously anchoring a floating offshore wind manufacturing base in Scotland.

Construction of the Inch Cape Offshore Wind Farm operations and maintenance (O&M) base is now underway at Montrose Port in Angus, Scotland, the Montrose Port Authority said in September.

Renewable Energy (ORE) Capable Terminal at Belview, County Kilkenny. This marks a major milestone for the company, the oldest Port in Ireland, with its application reinforcing Waterford’s ambition to play a central role in shaping the future of Ireland’s renewable energy sector.

The project will transform the Port’s capacity to support large-scale offshore renewable energy projects, creating the conditions for Waterford to act as a strategic site for major developments such as the proposed Tonn Nua Offshore Wind Farm and future projects across the Celtic Sea.

ORE Capable Terminal at Waterford is designed to support Ireland’s target to generate 7 GW of offshore wind by 2030.

Jones Bros Civil Engineering UK has secured a £10-million contract to deliver the infrastructure work on the Cydnerth Project in Holyhead. The expansion of the Morlais tidal energy scheme, owned by Menter Môn Morlais Ltd, marks a major milestone for the North Wales lowcarbon economy.

Our goal is to deliver an enhanced and integrated technical offering in offshore wind design, fostering innovation and creating new solutions that support the growth of the sector.

Montrose Port has a strategic location with direct line of access to Inch Cape and other existing and planned North Sea wind farms. Construction of the new facility and pontoons is due to be completed in early 2027.

“This investment not only reinforces our position as a strategic hub for offshore renewables but also brings lasting economic benefits through skilled jobs and increased port activity, both essential to our responsibilities as a trust port,” said Captain Tom Hutchison, CEO at Montrose Port Authority.

In Ireland, Port of Waterford has lodged a direct planning application for its Offshore

In Norway, the Norwegian Geotechnical Institute (NGI) has entered into a partnership with design and engineering consultancy Longitude, part of Oslo-listed ABL Group, to provide developers and operators of offshore wind farms with an integrated technical offering in offshore wind design, from concept to detailed design including foundations, subsea cables, and offshore substations.

“Our goal is to deliver an enhanced and integrated technical offering in offshore wind design, fostering innovation and creating new solutions that support the growth of the sector. Working with Longitude allows us to strengthen this ambition – from concept studies to FEED and detailed design,” said Thomas Langford, NGI’s director of offshore energy. 

USA Energy Review

By Tsvetana Paraskova

The short-term prospects of US oil and gas production and employment, as well as a new discovery in the US Gulf of Mexico, featured in the US oil and gas industry in the past few weeks.

Due to rising natural gas prices and falling oil prices in 2026, the EIA forecasts that crude oil will trade at its lowest premium to natural gas since 2005. As a result, the administration expects drilling activity in the United States to be more centred in natural gas-intensive producing regions next year. US natural gas production will be relatively flat next year compared with 2025, while crude oil production will decline by about 1 percent, the EIA reckons.

The administration sees Brent crude oil price declining significantly in the coming months, falling from $68 per barrel in August to $59 a barrel on average in the fourth quarter of 2025 and around $50 per barrel in early 2026. The EIA finalised this outlook before OPEC+ announced on 7 September that it plans to raise production by 137,000 bpd in October 2025.

The expectation of significantly lower oil prices is driven by large oil inventory builds as OPEC+ members increase production. The EIA expects global oil inventory builds will average more than 2 million bpd from the third quarter of 2025 through the first quarter of 2026.

Low oil prices in early 2026 will lead to a reduction in supply by both OPEC+ and some non-OPEC producers, moderating inventory builds later in 2026, the EIA said, expecting the Brent crude oil price to average $51 per barrel next year.

US Oil Production to Drop Slightly, Natural Gas Output to Stay Flat in 2026

US crude oil production is set for a slight drop in 2026 compared to this year, due to lower international and US crude oil prices, the US Energy Information Administration (EIA) said in its Short-Term Energy Outlook (STEO) for September.

US crude oil production will reach an annual all-time high of 13.4 million barrels per day (bpd) in 2025, up from 13.2 million bpd in 2024, the forecasts in the report showed. However, slowing drilling activity with the drop in oil prices will lower annual output to 13.3 million bpd in 2026, according to the EIA.

The US benchmark Henry Hub natural gas spot price will rise from an average of $2.91

per million British thermal units (MMBtu) in August to $3.70/MMBtu in the fourth quarter of 2025 and $4.30/MMBtu next year, the EIA forecasts. Rising natural gas prices reflect relatively flat domestic natural gas production amid an increase in US LNG exports.

Lower prices over this summer have been driven by robust production and reduced natural gas consumption in the electric power sector. However, the EIA continues to expect prices will gradually rise through the upcoming winter because inventories would be withdrawn at a faster-than-normal rate this coming winter. The relatively strong inventory draws in the forecast mostly reflect rising LNG exports amid flattening production.

In the forecast, the Henry Hub price reaches its winter peak in January 2026 at $4.60/ MMBtu, the EIA says.

LNG exports continue to be the largest source of demand growth for domestically produced natural gas. The administration forecasts US LNG exports will increase by 36 percent, or by 4.3 Bcf/d from 2024 to 2026, far outpacing the expected 1.0 Bcf/d of domestic consumption growth over the same period.

Domestic consumption of natural gas will average 91.4 Bcf/d by 2026, up by 1 percent relative to 2024. The largest user of natural gas in the United States is the electric power sector, which accounted for around 40 percent of domestic natural gas consumption last year and is set to remain at that share into next year, the EIA reckons.

Permian Gas Supply Crucial to Balance Domestic and Global Markets

Associated gas supply from the Permian basin will remain crucial for keeping a lid on the US Henry Hub prices, Wood Mackenzie said in a report at the end of August, commenting on the positive final investment decision (FID) on the Eiger Express pipeline. The major 2.5 bcfd natural gas project is set to run from the Permian basin to the Katy area, with an expected inservice date in mid2028.

reserves. That would increase its YE2024 proved reserves of 194 mmboe more than 25 percent, said Miles Sasser, senior research analyst, upstream for Wood Mackenzie.

“While Talos has not released volumes, a 200 mmboe discovery would make Daenerys GoA’s biggest find since Shell’s Whale in 2017,” Sasser added.

While Talos has not released volumes, a 200 mmboe discovery would make Daenerys GoA’s biggest find since Shell’s Whale in 2017

“Despite near-term uncertainty, low-cost Permian gas supply remains essential in keeping a lid on rising Henry Hub prices. As LNG export demand grows and power demand expands domestically, the Permian is expected to play a central role,” WoodMac research experts said.

The energy consultancy expects an additional 3.6 bcfd of gas supply from the Permian basin by 2027 compared with 2024 levels.

“The Eiger Express FID adds to the wave of outbound build from the Permian basin,” WoodMac said.

“While short-term supply growth may slow, long-term fundamentals continue to support the basin’s critical role in balancing both domestic and global gas markets.”

Daenerys Discovery in US Gulf of Mexico

Talos Energy has recently announced successful drilling results at the Daenerys exploration prospect in the US Gulf of Mexico’s Walker Ridge blocks 106, 107, 150, and 151.

“We are encouraged by the results of our Daenerys discovery well, which confirms the presence of hydrocarbons and validates our geologic and geophysical models,” Talos President and CEO Paul Goodfellow said.

“We are now working closely with our partners to design an appraisal program that will further delineate this exciting discovery. We anticipate spudding the appraisal well in the second quarter of 2026.”

The discovery at the Daenerys prospect is a game-changer for Talos in the US Gulf of Mexico, Wood Mackenzie said

The company’s GoM portfolio was ageing, but Daenerys could add more than 50 millions of barrels of oil equivalent (mmboe) net proved

Wood Mackenzie’s preliminary prospect valuation suggests peak production could reach 65,000 barrels per day.

Combined with bp’s Far South discovery in April, this year is the best year for exploration success on a volumes discovered basis since 2020, noted Sasser. With multiple exploration wells still planned for the year, 2025 has the potential to move even further up the list.

“The timing is particularly significant with December’s lease sale approaching,” said Adrian Tjokro, research analyst at Wood Mackenzie.

“The discovery proves there are still major prizes to be found in the sub-salt Miocene, potentially intensifying competition in the Walker Ridge area as companies look to capitalize on favorable royalty terms.”

US Oil and Gas Job Growth Stalls

The number of oil and gas upstream jobs in Texas and total US oilfield service jobs has dropped in recent months amid lower oil prices and operators reducing drilling activity.

Data from the Texas Workforce Commission showed upstream oil and natural gas employment fell by 1,400 in July compared to June, the Texas Oil & Gas Association (TXOGA) said in August.

June’s job loss has been revised to 1,500— less severe than the previously estimated 2,700. Despite declines over the past two months, year-to-date growth remains positive at 4,300 upstream jobs, TXOGA noted.

“Forecasts for lower prices can slow industry growth plans,” commented TXOGA President Todd Staples.

“With approximately 8 bcf/d of new LNG export capacity under development in Texas and multiple infrastructure projects announced, we are optimistic stable global market conditions will strengthen short-term demand and reinforce our energy workforce.”

The August jobs report by the Energy Workforce & Technology Council found that the labour market continues to soften across both the energy services sector and the broader US economy.

Total jobs in the energy services sector fell to 628,062 in August, down by 6,021 positions from July, according to preliminary data from the Bureau of Labor Statistics (BLS) and Energy Workforce analysis.

“While the sector experienced a sharper decline this month, we are continuing to see companies adapt with long-term discipline and strategic focus,” said Energy Workforce President Molly Determan.

“This slowdown reflects broader economic pressures, but the foundation of the energy services industry remains strong. Companies are operating with resilience, embracing efficiency and preparing their workforce for the demands of an industrial economy. Our members are focused on stability today and strength tomorrow.” 

Middle East Energy Review

By Tsvetana Paraskova

The OPEC+ producers tapped the last layer of remaining production cuts, announcing they would begin unwinding these in October, while the national oil companies of the top Middle Eastern producers signed several major deals and issued updates on their unconventional resource development plans.

OPEC+ Begins Unwinding 1.65-Million Bpd Output Cuts

The eight OPEC+ producers, which previously announced additional voluntary cuts in April and November 2023, decided in early September to begin returning on the market the 1.65 million barrels per day (bpd) cuts announced in April 2023.

Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, and Oman met virtually on 7 September 2025, to review global market conditions and outlook.

“In view of a steady global economic outlook and current healthy market fundamentals, as reflected in the low oil inventories,” the eight

producer decided to raise their combined oil output by 137,000 bpd in October, beginning to unwind the 1.65 million bpd cut announced in April 2023.

“The 1.65 million barrels per day may be returned in part or in full subject to evolving market conditions and in a gradual manner,” OPEC said, adding that the OPEC+ producers would continue to closely monitor and assess market conditions. To support market stability, the producers reaffirmed “the importance of adopting a cautious approach and retaining full flexibility to pause or reverse the additional voluntary production adjustments, including the previously implemented voluntary adjustments of the 2.2 million barrels per day announced in November 2023.”

In other words, OPEC retained the option to reverse or pause the rollback of the cuts if market conditions deteriorate and oil prices drop significantly from current levels.

In addition, Russia, Iraq, the United Arab Emirates, Kuwait, Kazakhstan, and Oman have submitted their updated compensation plans for offsetting previous overproduction.

Due to these compensatory production adjustments, OPEC+ has returned fewer barrels on the market since April 2025 than the headline figures suggest.

Following the OPEC announcement of more oil coming in October, the oil market staged a relief rally as the production increase was far lower than thought and a large part of it would not materialize, due to the compensation for overproduction and the lack of capacity at some producers.

The modest production hike for October is “unlikely to be implemented amid production capacity constraints, and others having to compensate for previous overproduction,” analysts at Saxo Bank said after the latest rollback was announced.

“Softening demand leading to an oversupplied market remains a key risk, as Saudi Arabia seeks to regain market share while lowering its pricing for most grades next month.”

Many analysts expect an oversupplied oil market later this year and in early 2026 as OPEC+ rolls back the cuts and production from non-OPEC+ producers, led by North America and South America, continues to grow. The majority of investment banks believe oil prices could drop to below $60 per barrel by the end of the year as demand slows in the fourth quarter after the summer peak.

OPEC+ could accelerate the rollback of the 1.65-million-bpd cuts if oil prices do not fall too much in the coming weeks and months, analysts say.

The producer group did that with the previous layer of 2.2-million-bpd cuts earlier this year, after beginning with small rollbacks in April and accelerating the unwinding of the cuts to more than 500,000 bpd per month in August and September.

Middle East Conflicts Put Energy Chokepoints Under Pressure

Recent conflict flare-ups in the Middle East, with the Houthi threat and the IsraelIran conflict, have made the world’s most important shipping chokepoints more vulnerable and hiked insurance premiums on cargoes, Rystad Energy said in a report in September.

The Strait of Hormuz, the Red Sea, and the Bab el-Mandeb Strait are vital lanes for oil and gas trade flows and disruption to shipping through them threatens global energy security, the independent research and energy intelligence company said.

The Strait of Hormuz handles approximately one-fifth of the world’s maritime oil and condensate trade, along with nearly half of the Middle East’s daily oil and condensate production — around 14.0 million barrels per day (bpd) — passes through this narrow waterway to major Asian markets such as China and India. About half of Saudi Arabia and the UAE’s daily oil and condensate exports, and roughly one-fourth of China’s daily oil and condensate demand, are shipped through the strait, Rystad Energy estimates.

The Strait of Hormuz is also a key route for LNG, with about one-fifth of globally traded LNG volumes passing through it. Qatar exports about two-thirds of its daily gas production, roughly 16.3 Bcfd, through the strait to countries including China, India, and South Korea. In the past five years, China’s LNG imports via the Strait of Hormuz have increased by about 2.5 times, reaching 2.7 Bcfd.

Before a wave of Houthi attacks targeting commercial vessels and tankers in late 2023, the Bab el-Mandeb Strait accounted for around 12 percent of global seaborne oil trade. However, the surge in attacks in December 2023 caused daily shipping volumes through the Strait to drop by nearly 50 percent within just six months. Traffic has remained below normal levels ever since, Rystad Energy reckons.

Despite higher freight costs and longer transit times, traders increasingly prefer the Cape of Good Hope due to its lower security risks. Compared to other global chokepoints, it currently represents one of the safest maritime routes for crude oil transport, the energy intelligence firm said.

Deals and Supply Agreements

The NOCs of the biggest Middle Eastern oil producers have recently signed strategic and supply deals and accelerated the development of unconventional oil and gas resources.

Aramco, Saudi Arabia’s oil giant, has signed an $11 billion lease and leaseback deal involving its Jafurah gas processing facilities with a consortium of international investors, led by funds managed by Global Infrastructure Partners (GIP), a part of BlackRock.

Through the deal, Jafurah Midstream Gas Company has secured significant foreign direct investment, together with an agreement to lease and leaseback development and usage rights for Aramco’s Jafurah midstream assets.

Jafurah is the largest non-associated gas development in the Kingdom of Saudi Arabia, estimated to contain 229 trillion standard cubic feet of raw gas and 75 billion Stock Tank Barrels of condensate. It is a key component

MIDDLE EAST ENERGY REVIEW

in Aramco’s plans to increase gas production capacity by 60 percent between 2021 and 2030, to meet rising demand.

As part of the transaction a newly-formed subsidiary, Jafurah Midstream Gas Company (JMGC), will lease development and usage rights for the Jafurah Field Gas Plant and the Riyas NGL Fractionation Facility, and lease them back to Aramco for a period of 20 years. JMGC will receive a tariff payable by Aramco in exchange for granting Aramco the exclusive right to receive, process, and treat raw gas from Jafurah.

Aramco will hold a 51 percent majority stake in JMGC, with the remaining 49 percent held by investors led by GIP.

on drilling and completion efficiency, and the application of technology and AI to drive down development costs,” ADNOC said in September after Sheikh Khaled bin Mohamed bin Zayed Al Nahyan, Crown Prince of Abu Dhabi and Chairman of the Abu Dhabi Executive Council, chaired a meeting of the executive committee of ADNOC’s board of directors.

The progress in unconventional gas is being driven by enhanced productivity, a firm focus on drilling and completion efficiency, and the application of technology and AI to drive down development costs

“Jafurah is a cornerstone of our ambitious gas expansion program, and the GIP-led consortium’s participation as investors in a key component of our unconventional gas operations demonstrates the attractive value proposition of the project,” Aramco president and CEO Amin Nasser said.

“As Jafurah prepares to start phase one production this year, development of subsequent phases is well on track. We look forward to Jafurah playing a major role as a feedstock provider to the petrochemicals sector, and supplying energy required to power new growth sectors, such as AI data centers, in the Kingdom.”

In the United Arab Emirates (UAE), Abu Dhabi National Oil Company (ADNOC) has recently accelerated unconventional gas development in Abu Dhabi, including across the Ruwais Diyab field. ADNOC is also currently looking to de-risk Abu Dhabi’s vast unconventional resources.

“The progress in unconventional gas is being driven by enhanced productivity, a firm focus

ADNOC has also signed a 15-year Sales and Purchase Agreement (SPA) with Indian Oil Corporation Ltd (IndianOil), India’s largest integrated and diversified energy company, for the supply of 1 million tonnes per annum (mtpa) of liquefied natural gas sourced primarily from ADNOC’s lower-carbon Ruwais LNG project.

The 15-year SPA converts a previous Heads of Agreement into a definitive agreement, under which LNG cargoes can be delivered to any port in India.

By 2029, IndianOil is set to become ADNOC’s largest LNG customer, with a total offtake of 2.2 mtpa – comprising 1.2 mtpa from ADNOC’s Das Island operations and 1 mtpa from the Ruwais LNG project.

ADNOC’s Ruwais LNG project, currently under development in Al Ruwais Industrial City, Abu Dhabi, is expected to commence commercial operations in 2028.

“This long-term agreement with IndianOil underscores the robust energy relations between the UAE and India,” said Rashid Khalfan Al Mazrouei, ADNOC Senior Vice President, Marketing.

“Through our world-class Ruwais LNG Project, ADNOC will continue to provide more lowercarbon gas to meet growing global demand, fuel industries and power homes.” 

Norway Energy Review

By Tsvetana Paraskova

Norway continues to rely on its offshore oil and gas resources to remain a key and, most importantly, a reliable provider of energy for decades to come. Interest in exploration in the Norwegian Continental Shelf (NCS) remains high as seen in the latest auction round that saw companies express strong interest in exploration acreage, again.

“We’ve had 30 years of – more or less – plateau production on the NCS. We’ll need to boost our efforts in both exploration, developing discoveries and improving recovery from existing fields in order to curb the steep production decline forecast after 2030,” Dahle said.

Norway still has substantial remaining oil and gas resources even after more than 50 years of petroleum activities, the audience at the conference heard.

These oil and gas resources come in addition to considerable seabed mineral resources and vast storage capacity for carbon dioxide (CO2), the Norwegian Offshore Directorate said.

Key players also shared their vision for further development of the NCS at the conference, with a focus on exploration and resources close to existing fields.

The Directorate, which is the industry regulator, is also challenging companies to explore more in frontier areas, and is looking for operators with the courage, determination, and ability to make a strong commitment.

Norway Continues to Bet on Offshore Oil and Gas Exploration

The Norwegian shelf is positioned to remain a competitive producer and exporter of oil and gas for many years to come, Kjersti Dahle, Director of Offshore new ventures at the Norwegian Offshore Directorate, said in her keynote speech at Sokkelkonferansen 2025, the directorate’s conference in Stavanger held at the end of August.

considerable interest in exploration near existing fields and infrastructure.

The Norwegian Offshore Directorate is now working to evaluate t he applications, with emphasis on geological comprehension and plans for exploration of the areas. When production licences are awarded, emphasis is also placed on the companies’ technical expertise and experience, as well as financial strength.

“It is encouraging to see that there is still significant interest in exploring new acreage in mature areas of the Norwegian continental shelf,” said Kalmar Ildstad, Director of regulations, licence and area management at the Norwegian Offshore Directorate.

The interest spans all sea regions, which demonstrates that there are many opportunities to make profitable discoveries from the south to the north of the shelf.

Interest in exploration on the Norwegian continental shelf remains high, the Directorate said in early September, after 20 companies submitted applications for exploring new acreage in the mature areas of the Shelf. Norway announces every year the so-called Awards in Predefined Areas (APA), which comprise the mature parts with known geology and good infrastructure already in place, allowing tie-backs to existing infrastructure for new discoveries.

The Directorate noted that most of the companies that are active on the NCS have submitted applications in this year’s APA round, and the applications confirm

“The interest spans all sea regions, which demonstrates that there are many opportunities to make profitable discoveries from the south to the north of the shelf.”

Norway’s Energy Minister, Terje Aasland, also commented on the interest in the latest licensing round.

“It is important that companies continue to explore so the petroleum activity can be further developed. Therefore, I am pleased to see that there is still strong interest and that companies have faith in the opportunities that lie in further exploration on the Norwegian continental shelf,” Aasland said.

“This facilitates Norway’s continued role as a stable and predictable supplier of oil and gas to Europe,” the minister added.

The ministry will now aim to award new production licences in the announced areas at the beginning of 2026.

The offshore directorate also aims to provide more insight into the exploration activity on

the shelf, and in early September it launched a new dashboard that offers easy access to statistics on exploration wells and technical discovery rates.

“Our data, which is also available on the Fact Pages, supports knowledge-based resource management, value creation, and sustainable resource utilisation. This data is widely used by industry players, the authorities, academia, and others interested in activities on the NCS, and provide important insights,” said Nadine Mader-Kayser, Assistant Director of Analysis at the Norwegian Offshore Directorate.

Seabed Minerals Regulation

As the regulatory body of activity on the NCS, the offshore directorate announced in early September it had stipulated the regulations relating to data collection and documentation in mineral activities on the Norwegian Continental Shelf.

The Regulations on seabed mineral activity establish, among other things, the following requirements for licensees: safeguarding consideration for other users of the sea; collection of data and samples; reporting data and submitting samples to the Norwegian Offshore Directorate; and use of methods and equipment for surveys.

The analyses the Norwegian Offshore Directorate has conducted of sulphides so far show high contents of copper, zinc, and cobalt on the seabed in the Norwegian Sea. The sulphides are found along the volcanic Mohns Ridge between Jan Mayen and Bear Island. Manganese crusts have been proven in several places along the Vøring Spur and around Jan Mayen.

Our data, which is also available on the Fact Pages, supports knowledge-based resource management, value creation, and sustainable resource utilisation.

The legal basis of the Regulations lies in the Seabed Minerals Act and the Seabed Minerals Regulations, the latter of which was adopted by the King in Council on 29 August and came into force on 1 September 2025. The Regulations govern exploration activity related to seabed minerals on the NCS.

Potential further requirements as regards exploitation will be stipulated at a later date, the directorate said.

The Regulations are broadly similar to the content and structure of the Resource Management Regulations for petroleum activities and the Regulations relating to documentation for storage of CO2 on the shelf.

In addition, rare earth elements have been found in samples from manganese crusts.

In energy company news, DNO ASA, the Norwegian oil and gas operator, raised dividends after the transformative $1.6 billion acquisition of Sval Energi Group AS earlier this year.

After the Sval acquisition, DNO has production from over 30 North Sea fields. Its most recent development, Maria Revit, was put on production in May 2025 and will contribute some 4,000 boepd net to DNO at peak.

Elsewhere in Norway, the company has six ongoing tieback developments scheduled to come onstream between 2025 and 2029, which together will contribute some 25,000 boepd net to DNO at the end of that period.

Combined, the six developments represent nearly 50 million barrels of oil equivalent (MMboe) in proven and probable reserves net to DNO. 

Australia Energy Review

By Tsvetana Paraskova

Progress in offshore oil and gas developments, the state of the electricity market, and the pace of clean energy investments featured in Australia’s energy industry in recent weeks.

The Darwin LNG plant has reached RFSU and the Barossa FPSO is expected to meet its RFSU milestone within weeks.

“Our LNG marketing business continues to perform well with strong average realised prices and tier one customers, including, most recently QatarEnergy Trading LLC. The commercial flexibility of our LNG portfolio has provided opportunities to take advantage of market conditions and further optimise the portfolio,” Gallagher said.

“Santos’ equity LNG portfolio is about 90 percent contracted over the next five years, with strong pricing driven by the high heating value of our LNG, our reliability and proximity to growing Asian markets,” the executive added.

Meanwhile, Santos and the XRG Consortium have continued to work together to complete due diligence and progress the Potential Transaction, including the negotiation of terms of a binding scheme implementation agreement.

Earlier this year, XRG, the energy investment company of Abu Dhabi’s national oil and gas firm ADNOC, has teamed up in a consortium with ADQ and investment firm Carlyle to announce a non-binding indicative proposal to acquire all of the ordinary shares of Santos by way of a scheme of arrangement.

Energy Majors Report Strong Earnings

Energy major Santos reported strong free cash flow from operations at US$1.1 billion for the first half of the year.

The company’s Barossa LNG project, an offshore gas and condensate project to provide a new source of gas to the existing Darwin liquefied natural gas (DLNG) facility in the Northern Territory, is more than 98 percent complete and first gas is expected imminently, said Kevin Gallagher, Santos Managing Director and Chief Executive fficer.

Under the Proposal, the XRG-led consortium proposes to acquire 100 percent of the ordinary shares in Santos for US$5.76 per share in cash, which would bring the value of the potential transaction at about US$19 billion. This would make the deal one of the biggest cash acquisitions in Australia’s energy sector ever.

At the end of August, Santos said it is finalising with the XRG Consortium the Scheme Implementation Agreement (SIA), which will include customary protections for Santos shareholders in the event there is a longer than expected period before completion of the Potential Transaction. On 24 August 2025, the XRG Consortium again confirmed it has not found anything in due

diligence that would lead it to withdraw its Indicative Proposal.

Still, Santos notes there is no certainty that a binding SIA will be agreed or that a Potential Transaction will proceed.

Woodside, the other major Australia-listed oil and gas company, also boasted strong firsthalf performance, with operating revenue rising by 10 percent and production increased by 11 percent from a year earlier.

“Strong underlying performance of our assets, our robust financial performance, and a focus on disciplined capital management have enabled us to maintain our interim dividend payout ratio at the top end of the payout range,” CEO Meg O’Neill said.

The Scarborough Energy Project in Western Australia is 86 percent complete and targeting first LNG cargo in the second half of 2026, the executive added.

Moreover, Woodside continued work on the Browse to North West Shelf Project to optimise the development concept, advance key regulatory approvals, and progress commercial discussions to process Browse volumes through the Karratha Gas Plant.

“Since the Minister announced his proposed approval of the North West Shelf Extension in May, we have been working with the Government to secure a final approval that supports continued and long-term operations and is consistent with the Government’s Future Gas Strategy,” O’Neill said on the teleconference call with analysts on the firsthalf results.

“Approval timeframes are certainly something that needs to be considered when we are thinking about how to lift productivity in Australia. We know that the Federal Government understands how important the North West Shelf Extension is for our communities, customers, and our workforce and therefore the nation. We look forward to a positive final outcome in the very near future,” the executive added.

Energy Market Outlook

The Australian Energy Market Operator (AEMO) has released its latest 10-year outlook on the investments needed to maintain reliability in the National Electricity Market (NEM).

The market operator noted that the reliability outlook has improved, but timely investment is essential to maintain reliability.

“Reflecting the positive investment momentum underway to meet growing demand and replace retiring generation, the report shows improved reliability outlooks, reliant on all expected investments being delivered on time and in full,” AEMO said.

Delivery of generation, storage, and transmission projects in the current investment pipeline is likely to meet reliability standards for the coming decade, according to AEMO chief executive Daniel Westerman.

Considering the large volume of generation retirements over the next decade, the timely delivery of new generation, storage and transmission, along with the operation of consumer energy resources to support reliability, remain critical...

“Considering the large volume of generation retirements over the next decade, the timely delivery of new generation, storage and transmission, along with the operation of consumer energy resources to support reliability, remain critical,” Westerman said.

AEMO forecasts a 28-percent increase in operational electricity consumption, that is, demand met by grid-scale generation, from 178 terawatt hours (TWh) in 2024-25 to around 229 TWh by 2034-35. The expected growth is predominantly driven by the rapid expansion of data centres, accelerating business electrification, and the broader inclusion of prospective industrial energy users.

Over the next five years, additional investment between 5.2 GW to 10.1 GW is expected to come online annually, often supported by government schemes, AEMO has estimated.

This new capacity will help offset the notified retirement of 11 GW of predominantly coal power stations over the next 10 years, including Eraring, Bayswater and Vales Point (NSW), Yallourn (VIC), and Callide B (QLD).

Clean Energy Investment Slows

Australia saw clean energy investment slow for the second consecutive quarter in the second quarter this year, the Clean Energy Council’s Quarterly Investment Report for Q2 showed

In the second quarter, Australia saw weaker investment in new renewable energy and storage projects, following subdued investor confidence earlier this year. Only 615 MW, or AUS$520 million of investment, in new large-scale solar and no new wind farms reached financial close in the second quarter. This pace of investment fell well short of the pace required to hit Australia’s 2030 renewable energy target, according to the council’s data.

The total amount of renewable energy generation financially committed in the first half of 2025 was 1.17 GW. This is only a third of the 6-7 GW annual pace required to replace aging coal and meet the nation’s 82 percent renewable energy target. Of these projects, no new wind farms were committed in the first half of 2025.

The pipeline of new projects remains strong, but many of the projects are being held back by

delayed transmission projects and extended planning and environment assessments, said Anna Freeman, Clean Ene rgy Council Acting Chief Policy and Impact Officer.

The industry association called on governments, regulators, and market bodies to address barriers to investment as a priority.

“Unsurprisingly, the Federal Election in May created a great deal of political and policy uncertainty which has been unhelpful to energy investors who are trying to make very large investments in assets which will be in operation for decades to come,” Freeman said.

“While we now have renewed confidence in the direction of travel, many chronic and structural issues remain unresolved – significant delays in the transmission rollout, lengthy and unpredictable environmental and planning processes, workforce bottlenecks and a lack of certainty about long-term revenue for new projects.”

Freeman pointed out that “International and local investors are ready to invest in Australia, but assessments need to be faster, clearer and more predictable to unlock projects.” 

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Brent Oil Through the Decades:

1 YEAR AGO

Around a year ago, Brent crude averaged about $74 per barrel in September 2024, trading in the low-to-mid $70s.

Prices reflected a balance of OPEC+ supply management, weaker demand signals from China, and global economic uncertainty. These factors combined to keep Brent relatively elevated compared to recent years, despite volatility in broader commodity markets.

5 YEARS AGO

In September 2020, Brent prices were much lower, reflecting the deep impacts of the COVID-19 demand collapse. The spot price hovered around $40.90 per barrel.

That year was marked by extreme volatility, widespread demand destruction, and major disruptions in global oil consumption, which dragged prices down to levels not seen in many years.

10 YEARS AGO

In September 2015, Brent crude averaged around $48 per barrel, down sharply from earlier highs.

The decline was driven by a global supply glut, fueled largely by rapid U.S. shale expansion, alongside weaker demand growth. This imbalance placed sustained downward pressure on prices, marking a period of volatility and adjustment for global oil markets.

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ABADI GAS FIELD

SAKRAYA GAS FIELD –PHASE 3

The major EPC contacts have been awarded on the project. Saipem has been awarded an  EPCI contract for eight rigid flowlines and a 24-inch diameter gas export pipeline around 183km long. Wison Energies has been awarded an EPCIC contract for the project’s FPU. And Subsea7 has the EPCI contract for the subsea umbilicals, risers and flowlines.

GULF OF THAILAND ASSET RETIREMENT PROGRAMME

Vantris Energy Berhad’s subsidiary, Sapura Energy (Thailand) Limited (SETH), has secured a contract that involves the installation and removal campaign and subsea inspection, repair, and maintenance (IRM) services from Chevron Thailand Exploration and Production Limited and is expected to be completed by the end of 2026.

The FEED phase on the project has commenced following the award of FEED contract for the FPSO, gas export pipeline (GEP) and subsea umbilicals, risers, and flowlines (SURF) scopes. he GEP and SURF FEED contract has been awarded to Worley. The FEED for the FPSO has been awarded to two competing consortia: Consortium 1 comprising Technip Engineering Indonesia, Technip Indonesia and JGC Indonesia; and Consortium 2, comprising Saipem, Tripatra Engineers & Constructors, Tripatra Engineering, and McDermott. 10 11

DAENERYS OIL DISCOVERY

Talos Energy has announced an oil discovery in the Daenerys exploration prospect located in the Walker Ridge area of the US Gulf of Mexico. The discovery well was drilled using the West Vela deepwater drillship, reaching a total vertical depth of 10,127 metres. The exploration well encountered oil pay in multiple high-quality sub-salt Miocene sands, with the discovery estimated to hold a gross resource potential of 100–300 million barrels of oil equivalent (MMboe).

SMØRBUKK MIDT OIL & GAS DISCOVERY

Equinor has announced a near-field oil and gas discovery at the Smorbukk Midt prospect with estimated resources between 6.3 and 18.9MMboe. The project’s proximity to the producing Smorbukk Sor field enables a subsea tie-back for its development. Drilling activities have been conducted utilising the Transocean Encourage semi-submersible rig.

INDONESIA DEEPWATER DEVELOPMENT

The pre-qualification (PQ) process for a contract to provide Mobile Offshore Drilling Units (MODUs) and ancillary services for the drilling campaign in the Gendalo, Gandang and Gehem fields has commenced. The contract covers 15 wells comprising eight firm wells and seven optional wells. The contract will run for five years starting in Q3 2026 and ending in Q1 2027.

LIKEMBE OIL FIELD

The field is to be developed as a subsea tie-back to existing infrastructure. The field which, is located in water depths of 1,200m, has estimated recoverable resources of 88 MMbbl and is due to come online in 2027.

BAY DU NORD

BW Offshore has signed a Heads of Agreement (HoA) with Equinor to advance the project into FEED. PreFEED work is on track for completion in mid-September, after which the parties will enter a bridging phase to prepare for FEED in early 2026, subject to approvals.

Azule Energy

GAJAJERRA GAS AND CONDENSATE DISCOVERY

Azule Energy has announced a gas discovery through the Gajajeira-01 exploration well, drilled by the Valaris 144 jackup rig. Preliminary estimated resources are about 1Tcf of gas and 100MMboe of condensate. The discovery could possibly be developed via existing infrastructure in the area.

LAMINARIACORRALINA FIELDS DECOMMISSIONING

Kent has secured a new contract from the Australian government. The contract is for technical advisory services to help with the permanent plugging and abandonment of the Laminaria-Corallina oil fields, including the removal of their associated subsea structure, located in the Timor Sea.

SAPINHOÁ OIL FIELD REDEVELOPMENT

Petrobras has announced that studies are underway regarding the potential for contracting new FPSOs to revitalise operations at the Tupi and Sapinhoá fields, aiming at extending the productive life cycle of the fields. Both projects are currently in the initial evaluation phase.

BLOCK H FIELD DEVELOPMENT –PHASE 1B

Under the scope, McDermott will be responsible for EPCI services for a carbon steel pipeline, along with the transportation and installation (T&I) of key SURF components. Engineering and project management will be led from McDermott’s Subsea and Floating Facilities team in Kuala Lumpur.

From Cyber Threats to Supply Chains:

The New Risk Landscape for Energy

By Tsvetana Paraskova

The energy industry has to navigate through many external and operational risks to keep energy supply reliable and produced in the safest possible manner.

Energy companies and supply chain firms need to manage safety and asset integrity and monitor political and geopolitical risks, environmental and reputational risks.

The oil and gas and renewable energy industries have stepped up risk assessment, management, and control to continue smooth and safe operations and ensure the energy supply the world needs.

Amid rising geopolitical tensions and a new world order emerging, cyber security risks have also become prominent in recent years. The conflicts in Ukraine and the Middle East, and the new US trade and tariff policies under President Donald Trump have added to supply chain cost risks amid changed trade flows and routes for delivery of oil and gas and raw materials for new energy projects.

Careful and successful operational risk management improves safety and mitigates operational risks of spills, explosions, and accidents. It also boosts financial performance as it could avoid losses and ensures regulatory compliance with relevant authorities.

The assessment and management of various risks could also streamline processes and improve decision making by identifying potential risks and opportunities. Companies have operations management systems to help them verify process safety or flag potential hazards. Many firms in the energy sector have started to use various forms of AI for visual analysis, operations connected with Internet of Things (IoT) applications, and digital twins, for example, to identify, assess, and mitigate potential risks.

External Risks

Energy firms are closely watching demand and supply trends in oil, gas, and renewables to mitigate risks and better manage costs amid fluctuating production and consumption, and regulatory changes in various jurisdictions.

Industries are grappling with rising costs due to the US tariffs, upended trade flows, and rising protectionism.

Identifying, assessing, and mitigating risks will continue to be key to safe and reliable energy supply, regardless of the actual energy mix in any given jurisdiction.

Early this year, KPMG published a report that considers the risks – as well as the opportunities – from tariffs, competition for resources, a heightened regulatory environment, supply chain disruption,

climate change, and other phenomena.

“Heading into the second half of 2025, the economic and geopolitical signals are intensifying,” KPMG said in the mid-year check-in.

“From global competition and evolving transatlantic trade talks to shifting conflicts and tariff regimes, companies are navigating a complex web of global uncertainty that shows no signs of dissipating.”

Companies are navigating tectonic shifts in power, fragmented regulatory and tax regimes, a technology landscape driven by the race who will dominate the AI competition, as well as multiple threats to infrastructure due to geopolitical rivalries, conflicts, cyberattacks, and extreme weather events, KMG reckons.

For example, according to the KPMG International report ‘Turning the tide in scaling renewables’, 84 percent of respondents say geopolitical challenges are causing substantial delays in, or even the abandonment of renewable energy projects. Additionally, 61 percent of renewable energy industry stakeholders cite supply chain risks as a significant obstacle to scaling renewable energy projects.

“As the main supplier for solar equipment, China holds many cards in the renewables race, and geopolitical tensions could disrupt exports and stall other nations’ green energy progress,” KPMG said.

In critical minerals, “One of the main bottlenecks to expanding mineral extraction is refining and processing, which takes time to develop. Countries with their own reserves want to move down the value chain from exploring to refining and production, and seek investments to enable this shift.”

A shrinking talent pool is also posing risks to energy companies, which may soon find themselves lacking the skilled workforce to implement AI-related tools in the industry. With many workers now retiring, the younger generations are less likely to stay or join the energy sector, KPMG says.

Operational Risks

Protecting asset integrity and monitoring energy infrastructure and assets could be made easier via technology and AI tools— if there are employees to operate remotely controlled or VR tools or analyse the AIgenerated trends.

A ResearchAndMarkets.com report from the end of 2024 showed that AI in the energy sector is expected to jump to $58.66 billion by the end of the decade, from $8.91 billion

in 2024. That’s a compound annual growth rate (CAGR) of 36.9 percent by 2030, as AIenabled predictive maintenance and grid optimisation revolutionise the management of energy assets.

Risk management will be one of the key drivers of AI adoption in the energy sector, along with energy market volatility, rising consumer demand for smart energy solutions, and AI-powered robots that help increase the safety of the workers in the energy sector, according to the report.

The challenges to faster AI adoption include insufficient real-time energy data that limits the training and deployment of AI models, as well as the lack of skilled professionals in AI and energy analytics.

Specifically in the oil and gas industry, the adoption of AI use cases is growing rapidly across upstream, midstream, and downstream activities, a survey by IBM Institute for Business Value (IBM IBV) showed in May.

Currently, 44 percent of upstream organisations use AI in oil and gas exploration. Another 45 percent plan to do so within three years. In downstream operations, 41 percent apply AI in refining, while another 52 percent expect to do so in three years, according to the survey.

Firms Increasingly Rely on Technology to Enhance Safety

Companies have increased their adoption of advanced technology and AI-powered solutions to boost safety.

For example, Aberdeen-based Fennex earlier this year secured a multi-year contract with EnQuest for the deployment of their flagship AI-powered Behaviour-Based Safety System, BBSS. The partnership marks a major step in advancing datadriven safety practices across EnQuest’s UK operations. BBSS is fully live across all EnQuest’s UK offshore assets and the Sullom Voe Terminal.

“We identified BBSS™ as an opportunity to make a step change in operational safety through making it easier and more user friendly for personnel to participate and allowing us to make more effective use of the resulting leading data,” said Ian McKimmie, EnQuest’s Director of HSE and Wells.

“It provides full visibility of engagement in our safety reporting and real-time data, giving us immediate insight into reported issues and the ability to act swiftly for the best outcomes in our operations.” 

certified hose solutions and full lifecycle control.

A single hose failure can trigger downtime, hazards, and environmental damage. That’s why TESS Aberdeen takes risk management seriously.

Supported by our TESS Hose Management (THM) system, we don’t just supply hoses, we help you maintain full control over their lifecycle.

From inspection and tagging to proactive replacement scheduling, THM helps reduce the risk of rupture, unplanned downtime, and environmental exposure.

With certified hose solutions, compliance assurance, and lifecycle management, we stop small issues becoming big consequences.

Backed by our 24/7 local team and fully equipped mobile workshop van, we’re ready to be onsite when and where you need us.

Supported by our TESS Hose Management (THM)

Why offshore safety training must evolve

Safety has long been recognised as a top priority across the offshore industry. Yet the reality is that the depth of commitment, and the effectiveness of delivery, varies.

by Neil Shepherd, Marketing Manager, DMO & Draeger Hire

Cultural influences, economic pressures and leadership styles all shape how safety is viewed and practised offshore. To truly protect workers and the environment, the sector must go beyond compliance and actively foster a culture of safety.

The challenge isn’t the lack of training. Workers in the energy sector average just over three safety courses every two years, but whether these sessions actually prepare people to be safe, not just feel safe, is the real task at hand.

This is where Dräger steps in, combining its rich legacy of protective equipment and training with innovative products and services that can reimagine offshore safety.

According to the report, which was launched in June, 78% of energy workers ranked on-the-job training as one of the most effective methods - far ahead of traditional classroom or online formats.

The Dräger Academy programmes reflect this preference, with a strong emphasis on scenario-based, experiential learning, led by qualified industry professionals.

At Dräger’s safety training centres, participants engage in hands-on, immersive training that replicates the challenges of the offshore environment. Donning real gear and responding to high-pressure emergency simulations, trainees gain more than just theoretical knowledge, they build practical skills and muscle memory.

From navigating confined spaces and managing gas detection to executing emergency evacuations, every scenario is designed to reflect the realities of offshore work. What sets Dräger apart is its team of trainers, many of whom are former offshore workers themselves. With years of on-the-job experience, they bring invaluable insight and credibility to the training, transforming it from passive instruction into active problem-solving, grounded in real-world know-how.

Digitalisation is also reshaping industry norms. On AI, the research shows that energy leads, with 76% favouring a balanced approach between human oversight and technology.

The sector also has a higher awareness (49%) of AI’s role in safety than other industries, with 48% believing that AI can improve employee training programs through immersive simulations.

Dräger is continuing to innovate when it comes to digitalisation, in particular exploring how data can be used to better understand risk and hazards, and how this can then better inform safety training.

Equipment including gas detectors, wearable sensors, and self-contained breathing apparatus (SCBAs) can now be used to monitor real-time environmental and human risk factors. This data can then by analysed, enabling detailed analysis of hazards, incident trends and worker behaviour. Insights from this data support predictive risk modelling and allow safety managers to identify potential dangers before incidents occur. Most importantly, the data informs targeted, realistic safety training tailored to specific risks, roles and environments. The result: safer behaviours embedded before boots even hit the rig floor.

While technology and methods matter, Dräger understands that the most effective training also addresses the human element. Data shows that 84% from the energy sector say mental health and wellbeing are inseparable from workplace safety - fear of speaking up, blame culture, lack of leadership supportcan undermine physical safety.

Dräger’s programs are designed to build not just compliance but confidence. Through peer-to-peer training and leadership engagement, they promote open communication, encourage questioning and reduce stigma around mistakes. This shift from obligation to empowerment is crucial for fostering a proactive safety culture offshore.

Box-ticking is not enough when lives are on the line. Offshore safety training must evolve, becoming more immersive, datadriven and human-centred. By combining its heritage in protective technology with forward-looking innovation, Dräger is showing how the industry can go beyond minimum standards to set new benchmarks in safety.

Because offshore, it isn’t just about passing a course. It’s about going home safe

From Compliance to Confidence: Turning Risk into Opportunity

Every organisation faces risk, but the smartest ones turn it into a driver for growth, resilience, and reputation.

This is where QHSE ABERDEEN steps in.

As specialists in Quality, Health, Safety, Environmental, and Information Security management, the company helps businesses turn compliance into confidence through robust systems, risk assessments, and a proactive approach to safety.

The Hidden Cost of Ignoring Risk

Workplace hazards, data breaches, environmental impacts, and dangerous substances can all disrupt business operations. Left unmanaged, these risks don’t just lead to regulatory penalties, they can cause downtime, reputational damage, and in the case of cybersecurity incidents, massive financial loss.

Industry data suggests that the average cost of a major cyber-incident now runs into the millions, a figure that rivals the cost of a serious safety incident. For many businesses, one event can jeopardise contracts or even the future of the company.

This is why effective risk management — physical and digital — is essential to longterm success.

ISO Management Systems – The Safety & Security Engine

For organisations that want to build resilience, ISO management systems provide a proven framework. QHSE ABERDEEN works with clients to implement and maintain ISO 9001 (Quality), ISO 14001 (Environmental), ISO 45001 (Health & Safety), and ISO 27001 (Information Security), turning risk management into a structured, proactive process.

Together, these systems embed a culture of continual improvement and allow businesses to demonstrate to clients and regulators that they take all risks seriously, not just the visible ones.

The Four Pillars of Risk -Based Thinking

ISO 9001 – Quality Management

Build consistency, reduce errors, and deliver products and services that meet customer expectations every time.

ISO 14001 – Environmental Management

Minimise your environmental impact, stay ahead of regulations, and improve sustainability performance.

ISO 45001 – Health & Safety Management

Create safer workplaces, prevent incidents, and protect the wellbeing of your people.

ISO 27001 – Information Security Management

Safeguard sensitive data, protect against cyber threats, and maintain client trust and regulatory compliance.

Partner with QHSE ABERDEEN to build a safer, smarter, and more secure business.

The Overlooked Area… Psychosocial Risk Management

ISO 45001 defines “injury and ill health” as an adverse effect on the physical, mental, or cognitive condition of a person. Yet, while the standard references this definition, mental health is often overlooked in practice. This is where ISO 45003:2021 provides valuable supplementary guidance, helping organisations to identify and manage psychosocial risks.

ISO 45003 recommends integrating psychosocial risk into all aspects of the 45001 management system. This may include setting objectives around psychological wellbeing, identifying psychosocial hazards, and implementing specific controls. The standard outlines more than 70 examples of hazards across three broad areas:

How work is organised (e.g., workload, scheduling, shift patterns).

Social factors at work (e.g., workplace relationships, customer interactions).

Work environment and tasks (e.g., exposure to distressing events, high-risk roles).

For many organisations, introducing a psychosocial procedure demonstrates a more mature and responsible approach to health and safety. While more common in healthcare, businesses in all sectors face psychosocial risks, especially those with customer-facing teams or employees working irregular hours.

By addressing psychosocial wellbeing, organisations not only improve compliance but also boost retention, morale, and productivity. QHSE ABERDEEN helps clients integrate these considerations into their management systems, ensuring that both physical and mental health are safeguarded.

DSEAR and the Risks You Can’t See

Some risks are invisible until it’s too late. The Dangerous Substances and Explosive Atmospheres Regulations (DSEAR) are designed to prevent fires, explosions, and chemical incidents, but many companies underestimate their exposure.

QHSE ABERDEEN helps organisations carry out comprehensive DSEAR risk assessments, identify hazardous substances, and implement safe systems of work. This not only protects staff and assets but also ensures compliance with stringent UK regulations.

Turning Risk into Opportunity

When risk is managed well, it stops being a threat and becomes a competitive advantage. Businesses with robust safety, environmental, and information security systems are more attractive to clients, especially in industries where pre-qualification questionnaires, supplier audits, and data security requirements are mandatory.

A safe, secure, and well-managed workplace also improves staff morale and retention, a benefit that goes beyond compliance and directly impacts productivity.

“Risk management is not about ticking boxes,” says Dave Rusling the M.D.. “It’s about building a stronger, more resilient business that can thrive even in challenging times.”

The QHSE ABERDEEN Advantage

With years of experience across multiple sectors, QHSE ABERDEEN brings practical solutions tailored to each client. Their approach is hands-on, ensuring that systems are not just implemented but embedded into day-to-day operations.

By partnering with QHSE ABERDEEN, businesses can rest assured that they are compliant, competitive, and confident about the future, physically, environmentally, digitally, and psychologically. 

Challenging the NORM: Safety in Offshore NORM Decontamination

Rethinking outdated approaches to make offshore decommissioning safer, smarter, and more sustainable. The NORM Status Quo

Naturally Occurring Radioactive Material (NORM) has long been one of the most complex challenges in oil and gas decommissioning.

Traditionally, the accepted practice has been to remove topsides and transport them onshore for decontamination as part of the demolition process. While this approach remains effective in many cases, it brings significant drawbacks: extended project timelines, high mobilisation costs, logistical complexity, increased safety risks during onshore entry, and the loss of operational knowledge once the topside leaves the offshore environment.

It’s time for the industry to recognise offshore NORM decontamination as a viable and often preferable alternative.

Sureclean provides complete NORM management services — onshore and offshore — covering survey, identification, decontamination, waste management, and secure disposal. While offshore decontamination will not always replace onshore methods, the industry’s reluctance to adopt offshore solutions has left opportunities for safer, more efficient, and more costeffective decommissioning untapped.

Challenging misconceptions

Safety perceptions

A common belief is that offshore NORM decontamination introduces greater risk. In reality, retaining the platform offshore preserves the working knowledge of its systems, controls, and integration. This makes safe entry and cleaning more straightforward than in a demolition yard, where vessels may have been dormant for months and require makeshift lighting, rigging, and access.

When manual entry is required offshore, Sureclean deploys robust risk assessments, controlled entry protocols, and specialist supervision. This ensures worker and environmental safety, reducing the hazards associated with delayed, unfamiliar, or improvised entry conditions onshore.

Operational issues

Another misconception is that offshore NORM decontamination extends cessation of production and platform departure. In practice, it can be integrated seamlessly with other offshore waste removal scopes.

Sureclean’s method uses the same highcapacity cleaning equipment already mobilised for vessel cleaning, with pressure adjusted to remove NORM scale and residues. Crews work sequentially — one managing hydrocarbons and waste, another following on to remove NORM. Containment systems capture both waste streams in a controlled process.

Our fleet, capable of continuous operation with 250m vertical and horizontal reach, reduces setup requirements while maintaining productivity, saving both time and cost.

Cost assumptions

It is often assumed offshore solutions are more expensive. The reality is the opposite. Offshore decontamination can cut equipment and manpower time, eliminate duplicate mobilisations and reduce transport onshore.

Instead of repeating waste removal onshore, the work is completed in a single offshore campaign. The result is significant cost reduction, fewer logistics movements, and less risk, truly making an Industrial world of difference™.

Additional value is created through materials recovery, such as recovering and selling diesel from tanks for client credit.

Lack of proven alternatives

Some still question whether offshore NORM decontamination can be delivered reliably at scale. Sureclean’s track record proves otherwise.

In one of the largest waste removal contracts in the North Sea, we safely removed NORMcontaminated waste from multiple platforms using our proprietary non-intrusive system. Over 80% of vessels were cleaned without entry, with NORM safely removed and disposed of in line with strict regulatory standards. This success has been replicated across further assets and operators, confirming the model is not just possible, but proven.

By Robbie Smith-Sinclair

Industry inertia

Industry guidance has historically reinforced onshore decontamination as the default, partly influenced by the P&A process which requires tubulars and subsea infrastructure to be returned onshore. While that is unavoidable for certain assets, it has created an assumption that all topside decontamination must also be done onshore.

This assumption is outdated. Recent regulatory changes have relaxed requirements for NORM repatriation to the UK, allowing contaminated assets sent overseas for disposal to remain overseas. This shift highlights the need to reassess the role offshore decontamination can play in decommissioning strategies.

New regulations, new opportunities

The Ionising Radiations Regulations 2017 (IRR17) and the Transfrontier Shipment of Radioactive Waste and Spent Fuel (EU Exit) Regulations 2019 set the framework for managing NORM. While complex, these regulations now provide operators with greater flexibility in how and where NORM is treated.

Crucially, the removal of mandatory UK repatriation opens the door for offshore decontamination to reduce risk, cost, and environmental impact. Instead of sending contaminated topsides overseas, operators can now decontaminate offshore before heavy lift, protecting both people and the planet.

Unique differentiating capability

From offshore removal to onshore disposal, Sureclean delivers unique, industry-leading NORM decontamination services with zero compromise on safety, compliance, or environmental responsibility.

Onshore: Our five-acre, fully permitted facility runs multiple decontamination lines in parallel, maximising throughput and cutting downtime.

Offshore: Our modular, field-proven systems can be deployed anywhere in the world, integrating with wider cleaning scopes to remove waste and NORM in one campaign.

This flexibility means operators gain the best of both worlds: proven onshore capacity and reliable offshore innovation.

Faster, smarter solutions

In a cost conscious, risk-averse, and environmentally accountable industry, it is no longer enough to rely on traditional methods alone. Offshore NORM decontamination has proven its value in delivering safety, efficiency, and financial benefits, without compromise.

Sureclean’s expertise, agility, and regulatory knowledge give operators the peace of mind that comes from partnering with the industry experts.

The message is clear: it’s time for the industry to break clean from the old way and embrace offshore NORM decontamination as a powerful partner to traditional onshore practices. 

Britain Accelerates Toward Clean Energy with 73.8%

Electricity from Renewables

Record renewable generation and new wind and solar capacity highlight Britain’s progress toward the Clean Power 2030 target.

UK Clean Power Share Hits 73.8% in 2024

Great Britain has made significant strides in its transition to clean power, with the share of electricity generated from renewable and lowcarbon sources reaching 73.8% in 2024. This represents a notable increase from 68.3% in 2023, according to the UK government’s first official statistics tracking progress toward the Clean Power 2030 agenda. The data offer a clear indication that the country is on a steady path toward its long-term goal of generating 95% of electricity from clean sources by the end of the decade.

Commenting on the figures, Barnaby Wharton, Director of Future Electricity Systems at RenewableUK, said:

“It’s great to see that Britain is making excellent progress towards clean power by 2030, with a significant increase in 2024 compared to the year before, as we roll out vital new wind and solar projects, strengthening our capacity to generate secure homegrown power.”

Wharton emphasized that the deployment of renewable projects, particularly in wind and solar, is central to maintaining energy security while reducing reliance on imported fossil fuels.

Record Renewable Generation in 2025

The figures were released alongside the Department for Energy Security and Net Zero’s (DESNZ) latest Energy Trends statistics, which provide further insight into the UK’s renewable energy performance. The data show that the

share of electricity produced from renewable sources reached a record 54.5% in the second quarter of 2025, surpassing the previous high of 51.7% seen in the same quarter of 2024. Total renewable electricity generation in the quarter grew 5.5% year-on-year to 35.1 terawatt-hours (TWh), driven by both increased capacity and favorable conditions for solar generation.

Key highlights from the quarter include:

• Offshore wind generation: +10% to 10.8 TWh

• Solar generation: +27% to a record 7.1 TWh

• New capacity added over the past year: 2.6 GW (1.4 GW solar PV, 1 GW offshore wind)

Onshore wind and other renewable technologies also contributed to this growth, helping to diversify the energy mix and ensure a more resilient electricity system.

Despite a 13% decline in nuclear generation during the same period, low-carbon electricity overall reached a record share of 69.8% in the quarter. This demonstrates that renewable sources are increasingly capable of compensating for fluctuations in other lowcarbon technologies, reinforcing the stability and reliability of the UK’s electricity system. Experts highlight that this diversification is crucial as the nation prepares for a future in which clean power forms the backbone of domestic energy supply.

The Clean Power 2030 initiative aims not only to expand renewable generation but also to strengthen the resilience, flexibility, and security of the grid. Achieving the target of 95% clean electricity will require continued investment in offshore and onshore wind, solar PV, energy storage, and smart grid technologies. Government policy, regulatory support, and private sector investment will all play key roles in ensuring that the UK can meet rising electricity demand while minimizing carbon emissions.

In summary, the latest figures signal robust growth in Britain’s clean energy sector. Clean electricity reached 73.8% in 2024, with record renewable generation in 2025 highlighting tangible progress toward a more sustainable, secure energy future. Continued investment in capacity, infrastructure, and innovation positions the UK to meet its Clean Power 2030 goals. 

TotalEnergies, RWE to build France’s largest renewable energy project

The consortium formed by TotalEnergies and RWE has been selected by the Ministry in charge of Industry and Energy in France as the winner of the Centre Manche 2 (AO8) offshore wind tender. The consortium will be responsible for designing, developing, building, and operating a 1.5 gigawatt (GW) offshore wind farm off the coast of Normandy. Renewable energy investments

Located more than 40 km off the coast of Normandy, this will be the largest renewable energy project ever developed in France. Once built, it will generate approximately 6 TWh per year and supply green electricity to the equivalent of over 1 million French households. The electricity will be sold at a competitive price of €66/MWh, as set by the tender.

TotalEnergies will be the operator of the project, relying on its expertise in offshore wind and the management of large-scale marine energy projects. The company will continue the necessary studies to reach a final investment decision by early 2029. Electricity production is expected to begin in 2033, in line with RTE’s grid connection schedule.

Patrick Pouyanné, Chairman and CEO of TotalEnergies. said: “We are very proud to have won this tender for the construction of the largest renewable energy park in France to date. It embodies Total’s transformation into TotalEnergies in France. This project will be the largest investment made by TotalEnergies in France in decades and reflects our company’s deep commitment to our country.

“As a long-standing player in Normandy, we are determined to mobilize our expertise to ensure this project is an industrial success while securing its acceptance by the region. We will work to support the local industrial ecosystem, which has already developed skills through the first offshore wind projects currently being installed. Finally, this project strengthens our development in green electricity production to offer competitive prices to our French customers.”

As part of a strategic review of its investments, RWE has expressed the wish to exit the consortium, subject to French authorities’ approval. In any case, TotalEnergies will pursue the project, assuming all the commitments of the consortium, and will propose to bring a new partner into the project.

The project is expected to represent a €4.5 billion investment and generate significant economic benefits for the Normandy region. Up to 2,500 people will be employed during the three years of construction, and TotalEnergies has committed to offering 500,000 hours of work to apprentices and individuals in professional reintegration. TotalEnergies also plans to engage the local economic ecosystem, which has already developed expertise in offshore wind.

The project will also benefit the European industry, as TotalEnergies intends to source primarily from European suppliers, particularly for wind turbines and electrical cables.

In the coming months, a dedicated TotalEnergies team, based in Normandy, will continue the consultation work with local and regional stakeholders that began during the tender phase. It will ensure the proper integration of the project into the Normandy region, especially its coexistence with commercial fishing.

TotalEnergies will also implement crowdfunding financing that will allow local residents and authorities in the Normandy region to invest in the project and directly contribute to the energy transition of their territory. Additionally, TotalEnergies will fund a €10 million territorial fund to support initiatives in training, education, and culture in Normandy.

On environmental matters, TotalEnergies will allocate €45 million to measures aimed at avoiding, reducing, and offsetting the project’s impacts; as well as €15 million to a biodiversity promotion fund in Normandy.

TotalEnergies disclosed that it has committed to making the project exemplary in terms of recycling offshore wind farm components, with recycling, reuse, or repurposing rates of blades, towers, and nacelles equal to or greater than 95%, and 100% of generator magnets being recycled or reused.

Since 2020, while transforming its energy offer, TotalEnergies has invested more than €8 billion in France, nearly half of which has supported the energy transition of its assets and for its customers. With a renewable portfolio of 660 wind, solar, hydro, and battery storage plants, TotalEnergies meets the electricity needs of the equivalent of 1.8 million people in France, ranking among the top three renewable electricity providers in the country with over 2 GW of installed capacity. TotalEnergies supplies electricity and gas to 4.2 million residential and business customers. 

Offshore safety update: weight limits and gangways

There have been significant safety developments related to offshore operations, here we take a look at how and when these might affect you.

Victoria Anderson and Malcolm Gunnyeon, Brodies LLP

HSE Safety Notice

On 8 August 2025 the Health & Safety Executive (HSE) issued an urgent offshore safety notice in respect of motion compensated gangways. The aim of the notice was to highlight the risks of and aim to avoid potentially fatal gangway accidents to offshore workers as a result of unexpected auto-retraction in certain circumstances.

Power failures or control system errors were identified as being the cause of unexpected retraction. Such events put workers at risk from falling from height, being struct by moving parts and suffering serious injuries including death. In many cases, the HSE identified that audible or visual alarms were either absent or triggered at the same time as the retraction, meaning that personnel did not have sufficient time to react to the warning and move to safety.

The HSE is calling upon operators in the energy sector to review their gangway arrangements, stressing that any gangways that cannot provide sufficient warning before automatic retraction must be taken out of service until proper safety controls are installed.

HSE issued a similar safety alerts in 2024, however, it is of the view that gangways which do not provide sufficient warning before autoretraction are still being commonly used.

It is therefore recommended that duty holders should conduct evaluations of all automatic gangway functions and produce updated technical risk assessments which detail the evaluation of functions, especially autoretraction triggers and override protocols. Many in the industry have advocated for fail-safe design features whereby, following a power loss or control error, the gangway will default to a safe state meaning that no auto-retraction is triggered unless it has been verified that personnel are safe. HSE has advised caution in relation to manual override highlighting that it must be governed by strict procedures and risk assessment to avoid deliberate or accidental misuse.

OEUK Safe Weight Limit Policy

For several years now, the weight of offshore workers has been known to present a safety hazard in the sector. Data published in 2022 indicated that the problem was acute, particularly in relation to emergency response. As a result, OEUK has been consulting with key industry stakeholders and formed a working group of industry experts to consider the issue and potentially develop a policy to assist employers in the sector.

The average weight of an offshore operative was noted in 2022 to have increased to 96kg. That figure confirms a steady and significant increase over the years and is now approximately 10kg heavier than the average in 2008.

Lifeboats and other evacuation systems were traditionally designed for a person with an average weight of 75kg. Accordingly, with today's average weight closer to 97kg, lifeboats may exceed safe capacity even when occupied by fewer people. Uneven weight distribution can affect how lifeboats launch and float, especially in rough seas.

HM Coastguard has written to OEUK expressing its concerns on the topic, highlighting the limitations of winches used in SAR situations, suggesting that it may not be safe for individuals weighing more than 125kg to work offshore.

OEUK intends to issue a policy which would mean that an OEUK medical certificate would not be issued to individuals weighing more than 124kg and this could come into force as early as October 2026. The policy could be enforced by employers at the point of travelling offshore, meaning that anyone without a valid OEUK medical certificate due to weight or who records a weight of more than 124kg at the heliport would not be permitted to travel offshore.

The existing statutory framework, including the Offshore Safety Case Regulations 2015 and PFEER 1995, requires duty holders to manage the risks in relation to safety evacuation. Accordingly, to demonstrate ongoing compliance, employers need to be able to demonstrate that personnel could, in the event of an emergency, be safely evacuated/rescued.

Accordingly, employers will be encouraged to advocate weight loss programmes for those thought to be at risk of breaching the safe weight limit to ensure that personnel can continue to work without additional safety risks.

The OEUK policy is expected to be published in early October 2025.

For more information or to contact Victoria and Malcolm, visit brodies.com 

Want to know more?

Brodies LLP is a UK top 50 law firm with offices across Scotland, the UK and internationally. For more useful insight and details of our energy expertise visit brodies.com

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We simplify your access to these complex incentives. Our combined teams of highly skilled Tax and Technical specialists, enhanced with cutting-edge digital tools developed internally, maximise the financial benefits for any type of business.

Digital Guardians: Transforming Safety in the Energy Sector

In an industry where a single malfunction can trigger multimillion-pound losses and risk lives, the energy sector is under mounting pressure to rethink how it manages safety.

As operations grow more complex and climate goals push innovation, traditional methods are being replaced by predictive, technology-driven systems. Digital twins alone are estimated to reduce unplanned downtime by up to 20%. These technologies are transforming safety into a competitive advantage.

The Shift to Predictive Risk Management

Historically, safety in the energy industry has relied on routine inspections, manual monitoring and reactive measures. While these approaches remain essential, they leave operators vulnerable to unexpected equipment failures, environmental hazards and high operational costs.

The shift towards predictive risk management is changing the landscape. By leveraging live data from sensors and smart devices, energy companies can identify potential failures before they occur. Digital twins are virtual replicas of physical assets that allow engineers to simulate how systems might behave under stress, forecast degradation, and plan interventions more accurately. This proactive approach enhances safety and regulatory compliance while supporting more efficient operations.

Advancements in Technology

Recent developments are turning digital twins into the cornerstone of safety innovation in the energy sector. Once primarily used to model physical assets, modern twins integrate artificial intelligence and machine learning to anticipate faults and evolve with every new data point.

Supporting technologies, including robotics and autonomous drones, capture precise inspection data in difficult or hazardous locations for human access, which feeds

Authored by Nikki Modare, Software Assistant Manager - Leyton UK

directly into the digital model. Virtual and augmented reality connect to these twins to provide interactive simulations, allowing engineers to visualise emerging risks and train in realistic, scenario-based environments. Together, these technologies transform the digital twin from a static representation into a living system that predicts and prevents incidents, giving energy companies a significant safety and operational advantage.

R&D Initiatives Driving Innovation

Companies investing in these innovations can often meet the UK R&D tax relief criteria, as the work involves overcoming technological uncertainties and developing improved or new solutions in the industry. Key areas of activity include:

1. Predictive Modelling and AI Simulation

Advanced R&D focuses on designing algorithms that allow digital twins to anticipate failures before they occur. This includes simulating extreme operational scenarios such as rapid load changes, corrosion, or structural fatigue in wind turbines, pipelines or hydrogen storage systems. Technological uncertainties would potentially include incorporating variable environmental conditions or complex system interactions.

2. Real-Time Data Fusion and Analytics

Energy infrastructure generates vast amounts of sensor data, often from multiple sources such as vibration monitors and temperature sensors. R&D in this area involves building platforms that can integrate and analyse these data streams in real time, feeding the digital twin with accurate, synchronised information. Projects may also tackle uncertainties in reducing latency, improving data accuracy and automating insights to support immediate operational decisions.

3. Immersive Training and Human-Machine Interfaces

Virtual and augmented reality provide realistic, risk-free training environments linked to live or simulated digital twin data. R&D can focus on creating high-fidelity interactive scenarios, such as emergency response drills or predictive maintenance exercises, which respond dynamically to the evolving twin.

4. Cybersecurity for Connected Risk Systems

Cybersecurity is a growing concern as digital twins and their supporting platforms become increasingly connected to IoT and operational networks. R&D in this space may include developing encryption protocols, intrusion detection methods and resilient system architectures that protect sensitive operational data while maintaining real-time functionality. Together, these initiatives represent the forefront of technological innovation in risk and safety management. They help the energy sector operate more reliably and efficiently and align with the UK’s goals for sustainable and secure energy infrastructure.

Impact and Benefits

By detecting issues earlier and preventing downtime, companies can extend asset life and improve energy efficiency. Financially, predictive risk management can translate into significant cost savings by reducing unplanned maintenance and avoiding incidents that could lead to regulatory penalties or reputational damage.

From a strategic perspective, investing in safety innovation strengthens public and investor confidence, demonstrating a commitment to environmental stewardship and worker protection. On an ecological level, preventing leaks, failures, and energy losses contributes directly to the UK’s net zero ambitions, supporting a cleaner and more sustainable energy infrastructure.

Conclusion

Innovation in risk and safety management is no longer optional for the energy sector. Digital twins, AI-driven simulations and immersive training tools are moving the industry from reactive responses to predictive resilience. In the UK, companies that continue investing in R&D to enhance these technologies are positioning themselves at the forefront of a safer, more innovative, more sustainable energy landscape. 

OSSO secures major geothermal contract and establishes dedicated European regional entity

OSSO, the specialist provider of fluid temperature control and separation solutions, has secured a major geothermal contract in Central Europe, with a project in Germany’s Upper Rhine region.

The multi-well, multi-rig campaign further strengthens the company’s position in the market and as a result of this growing activity on the continent, OSSO has also established a dedicated European entity in Amsterdam to support increasing demand.

OSSO is providing its high-capacity mud cooling technology to support a six well, three rig drilling campaign, with operations underway. Its technology is designed to tackle the extreme downhole temperatures common in geothermal operations by actively cooling drilling fluid as it returns to the surface. This temperature control is beneficial for enhancing drilling performance, extending the lifespan of downhole tools, and significantly reducing overall operational costs. By lowering the temperature of the fluid at surface level, it also reduces heat exposure for rig crews, supporting safer working conditions.

To support its continued growth and activity across the region, OSSO has established a dedicated European entity. Based in Amsterdam, Netherlands, the entity is already providing local servicing and technical support. The Netherlands was strategically SPONSORED BY

selected as the base for OSSO in Europe due to its central location and strong infrastructure, allowing for efficient access to key markets and faster mobilisation across the continent.

James Scullion, CEO of OSSO, said: “We’re delighted to be supporting on another important European geothermal project. This latest contract builds on the strong momentum we’re seeing across Europe and the wider business. Securing several geothermal contracts to date shows the value we’re delivering, and setting up a European entity is the next step in scaling our capability, enabling us to support customers in the continent with an enhanced, localised service not only for Geothermal but for fluid management and separation solutions. Pivoting our expertise into sectors like geothermal and fluid management has been central to our growth strategy, and we’re focused on driving that forward.”

Geothermal is increasingly recognised as a key low-carbon energy source for Europe. In 2024, the EU Energy Council endorsed plans to accelerate its deployment, positioning it as a central pillar of the energy transition.

According to the International Energy Agency, geothermal could meet 15% of global electricity demand growth by 2050, with investment in the sector projected to reach up to USD 140 billion per year.

Alasdair Carstairs, Business Unit Manager at OSSO, added: “Our mud cooling technology is proven in high-temperature geothermal wells, and that track record was key to securing this contract. Our consultative approach and ability to deliver local servicing have positioned us strongly for this project, and with the new entity in place, we’re primed to continue supporting the sector as it grows. We’re also expanding our geothermal offering to include fluid and wastewater management – critical capabilities for tackling the broader operational challenges the industry will face as it scales.” 

Atlas Oranto Secures Four Offshore Exploration Contracts in Liberia

Landmark Agreements Set to Revitalize Liberia’s Offshore Oil Sector with Major Investments and Job Creation

The Liberia Petroleum Regulatory Authority (LPRA) and international oil company Atlas Oranto Petroleum have signed four PSCs, granting exploration rights for offshore blocks LB-15, LB-16, LB-22 and LB-24

The agreements mark a pivotal step in reviving Liberia’s oil and gas sector after more than a decade of limited activity.

The contracts include a $12 million signature bonus and commit to an estimated $200 million investment per block. Atlas Oranto Petroleum’s operations will be conducted under national laws and regulatory oversight to ensure responsible and transparent exploration.

The agreements are now subject to ratification by Liberia’s National Legislature. Once approved, they are expected to attract new investment, generate employment and advance the objectives of Liberia’s ARREST Agenda, the government’s long-term plan for sustainable growth and development. 

BW Contracts Rig for the First Drilling on the Kudu Field in 18 Years

The Norwegian oil producer BW Energy, has contracted a rig for the drilling of the Kharas appraisal well on the Kudu licence (PPL003) in the Orange Basin, offshore Namibia.

The Deepsea Mira semi-submersible, operated by Northern Ocean Ltd., will drill the long awaited well on the Kudu structure as part of the scheduled rig-sharing arrangement in which Rhino Resources Ltd also gets to drill is own third well in the prospective Petroleum Exploration Licence (PEL) 85, where it has reported two oil discoveries: Sagittarius-1X and Capricornus-1X in the last eight months. Kharas will be the ninth well on the Greater Kudu structure and the first drilling since Tullow Oil’s disappointing Kudu-8 appraisal well failed to account for the additional

reserves needed to signal development. “The results of the logging programme indicated production from the well would not exceed the 19Million standard cubic feet per day (MMscf/d) rate recorded at Kudu-5”, Tullow reported at the time, in late 2007.

BW Energy claims in a statement released July 28, 2025 that “the contract (entered with Northern Ocean Ltd for Deepsea Mira), provides access to an in-country rig and an experienced services team with a strong track record in the Orange Basin, supported by a high level of local content”.

BW Energy concluded its farm in into the Kudu field acreage in February 2017 as BW Offshore, before the company then spun off BW Energy as a quasi-independent entity, working as E&P operator, as part of the BW Group. The company took a 56% stake at the time, with NAMCOR, the state hydrocarbon company, holding a 44% stake. As the Namibian state was unwilling to invest in what could have led to a gas to wire project, BW Energy assumed more of the stake in the Kudu production licence with a 95% working interest. NAMCOR E&P now holds the remaining 5% carried interest. 

NHV announce North Sea contract win

NHV is pleased to announce the contract award with Anasuria Hibiscus UK, flying one of our H175 aircraft out of Aberdeen in support of the Teal West Project.

The first flights were successfully completed on the 10th of September and we will now continue regular operations with weekly flights in the months ahead.

This milestone also represents the first UK well delivery for Anasuria Hibiscus UK Limited. NHV is honoured to contribute to this achievement!

Jamie John, Chief Commercial Officer at NHV Group, states: “We are very pleased that Hibiscus has chosen NHV as their partner for this prestigious project. We look forward to supporting their operations and contributing to the continued success of the Teal West Project!’’ 

TechnipFMC Bags Contract for Newest Stabroek Project

TechnipFMC PLC said it had won a “substantial contract” from Exxon Mobil Corp to deliver subsea production systems for the Hammerhead field in the Stabroek block offshore Guyana.

“TechnipFMC will provide project management, engineering and manufacturing of subsea production systems supporting both production and water injection capabilities”, the integrated energy contractor said in a press release. “The subsea architecture will include products from the Subsea 2.0® platform, including subsea trees, manifolds and associated controls”.

TechnipFMC values a substantial contract between $250 million and $500 million.

“Hammerhead is our seventh greenfield project award from ExxonMobil Guyana since the first development was sanctioned in 2017″, said Jonathan Landes, president for subsea at TechnipFMC. “Our continued success stems from our ability to provide schedule certainty,

built on our proven execution and the benefits of Subsea 2.0®”.

Last week ExxonMobil announced a positive FID (final investment decision) on Hammerhead, earmarking $6.8 billion for the 150,000 barrels per day (bpd) development.

Targeted to be put into production 2029, Hammerhead will grow Stabroek’s production capacity to 1.5 million bpd, the operator said in a statement September 23.

Hammerhead is the seventh project approved in Stabroek, with the fourth and biggest – the 250,000-bpd Yellowtail – started up earlier this year through floating production, storage and offloading vessel (FPSO) ONE GUYANA.

“ExxonMobil is safely producing approximately 650,000 barrels of oil per day from the Stabroek block”, ExxonMobil said. “With the recent successful startup of a fourth FPSO, the ONE GUYANA, the company anticipates growing production to more than 900,000 barrels of oil per day by the end of the year.

“Construction is underway for the fifth and sixth approved projects, Uaru and Whiptail, with Uaru anticipated to start production in 2026, and Whiptail is anticipated for startup in 2027”.

Hammerhead’s development plan includes 18 production and injection wells.

The Hammerhead FPSO has already been under construction. MODEC Inc had won the engineering, procurement, construction and installation contract, as well as the frontend engineering and design contract, for the project, as announced by the Tokyo-based company April 21.

MODEC is also building Uaru’s FPSO, named Errea Wittu.

ExxonMobil said investments committed to Stabroek now exceed $60 billion, with over $7.8 billion paid to the South American country’s Natural Resource Fund since the block went online 2019.

“We continue to set a new standard in Guyana – advancing an impressive seventh project just 10 years after first discovery”, said ExxonMobil upstream president Dan Ammann.

ExxonMobil added, “There are currently some 6,200 Guyanese working in support of Stabroek block operations – which is about 70 percent of the workforce. ExxonMobil Guyana and its contractors have spent more than $2.9 billion with Guyanese suppliers since 2015”

ExxonMobil operates Stabroek with a 45 percent stake. Chevron Corp’s Hess Guyana Exploration Ltd owns 30 percent. CNOOC Petroleum Guyana Ltd, part of China National Offshore Oil Corp, holds 25 percent. 

bp award THREE60 Energy and AF Gruppen Andrew decommissioning project in the UK

A new joint venture (JV) between THREE60 Energy (THREE60) and AF Offshore Decom (AFOD), a subsidiary of AF Gruppen, has been awarded a multi-million-pound contract by bp to provide integrated decommissioning services for their Andrew field in the North Sea.

A first of its kind in the UKCS, this contract will see the joint venture assume the role of decommissioning services partner. The JV will deliver post cessation of production (CoP) operations, well decommissioning, facilities / pipelines / topsides preparation, substructure and topsides disposal and subsea infrastructure removal. The JV will also work alongside the topsides removal contractor to ensure successful unified delivery of the full decommissioning scope.

The contract, which is subject to regulatory approvals, will be delivered over several phases, with the initial phase being well planning, P&A preparation scopes, including platform readiness, and transition planning.

Within the JV, THREE60 will combine its responsibility and capability as Installation, Pipeline and Well operator with AF Offshore Decom’s experience and track record in EPRD preparation, management and disposal.

THREE60 is a leading independent energy service company offering complete asset life cycle solutions. Their engineering, subsea, operations and wells team will leverage its differentiated and previous experience as Duty Holder, Pipeline Operator and Well Operator to deliver this integrated scope.

For over 20 years, AFOD has been a dedicated decommissioning EPRD main contractor in the North Sea. The company has safely prepared, removed, and recycled more than 90 offshore structures and has built extensive experience in managing large and complex projects. The company also operates a purpose-built decommissioning facility; AF Environmental Base Vats. Their deep breadth of offshore experience in project delivery, EPRD management and execution, as well

pure disposal, will be integrated into the project team.

The Andrew field is located 225km northeast of Aberdeen and serves as a central hub for four subsea fields. The facility features a steel structure that integrates both drilling and production facilities, with the topsides weighing approximately 11,100 tonnes and the supporting structure around 7,600 tonnes. The Andrew area includes 17 platform wells, 8 subsea wells, 41km of subsea bundles, 42km of umbilicals, and 2,500 tonnes of subsea equipment.

Walter Thain, Group CEO of THREE60, commented on the contract award: “We are honoured to partner with AF Offshore Decom on this significant bp project. The award is testament to both our team’s collective work throughout the tender process and in co-creating a bespoke solution to meet bp’s requirements. We are dedicated to delivering comprehensive and safe decommissioning solutions and really excited to embark on this journey.”

Alice Andreassen, Managing Director in AFOD said: “We have found the right partner who complements our vision of delivering across the entire value chain. In this partnership, AFOD will integrate with THREE60 to deliver integrated decommissioning solutions in compliance with bp requirements. We are really looking forward to embarking on this journey together with THREE60, to deliver this important project with bp. This partnership is strategically important for the North Sea market and the future of decommissioning project execution models.”

The scope of work will be delivered from a THREE60 – AF project office headquartered in central Aberdeen, Scotland. 

Allseas

wins UK North Sea decommissioning job

Operator Taqa UK is in process of decommissioning Brae Alpha platform in North Sea

A major contract has been awarded for the decommissioning of topsides at the Brae Alpha platform in the UK North Sea.

Operator Taqa UK has picked offshore contractor Allseas to carry out engineering, preparation, removal and disposal (EPRD) of the Brae Alpha topsides, following a competitive tender process.

The work is scheduled to begin later this year and will be a key part of one of the UK’s largest decommissioning programmes.

Allseas will deploy heavy-lift vessel Pioneering Spirit to remove the 33,000-tonne topsides and 12,000-tonne upper jacket, in two standalone campaigns.

Sandy Hutchison, managing firector of Taqa UK, said the work “represents a major project for a platform that has played a significant role in the UK’s energy security over four decades”.

Taqa has committed to reusing or recycling at least 95% of recovered topsides material.

Located around 270 kilometres northeast of Aberdeen, Brae Alpha began production in 1983. It has produced over 636 million barrels of oil equivalent during its lifetime.

Allseas is also carrying out the EPRD programme for Taqa UK’s North Cormorant, Tern, Eider and Cormorant Alpha assets in the North Sea as part of the largest single offshore decommissioning contract awarded in the UK to date. 

Aggreko and Katoni release whitepaper on temporary power for North Sea decommissioning

Aggreko and Katoni Engineering have jointly published a new whitepaper, Temporary Generation for North Sea Oil & Gas, examining the increasing role of compliant, low-emission power solutions in offshore decommissioning.

As the UK Continental Shelf prepares for a peak in decommissioning activity by 2030, operators face growing challenges around emissions reduction, generator availability, and operational continuity. The paper highlights the demand for temporary generation during life-support operations, plug and abandonment campaigns, and topside removals, particularly as fuel gas supplies decline post-cessation of production.

The whitepaper explores the operational and regulatory trade-offs between legacy Stage I–III diesel generators and modern Stage V units, and demonstrates how hybrid solutions, including battery integration, can help reduce fuel use, emissions, and costs.

A North Sea turnaround case study featured in the report shows the potential impact of these approaches. By deploying a tailored temporary generation package designed for the platform’s reduced load profile, operators were able to avoid an additional 4.5 tonnes of CO₂ emissions during a 50-day campaign. The project also achieved fuel savings of nearly £900,000 and carbon cost savings of almost £200,000.

By combining Aggreko’s modern Stage V generator fleet and logistics expertise with Katoni’s engineering and integration capabilities, the partnership provides operators with a reliable pathway to decommission assets more efficiently, cost-effectively, and with lower emissions. 

Decom Mission Appoints Caroline Lawford to Board of Directors

Decom Mission is pleased to announce the appointment of Caroline Lawford as its newest Board member. Caroline joins the organisation bringing extensive expertise in decommissioning, with a distinguished career spanning projects in the North Sea and Offshore West Africa.

Currently Manager of Decommissioning at Canadian Natural Resources Limited (CNRL), Caroline has played a pivotal role in several landmark North Sea decommissioning projects, including Murchison. Her experience and leadership in the sector are set to provide significant value to Decom Mission’s ongoing initiatives.

Commenting on her appointment, Caroline Lawford said:

“Decom Mission is a vital organisation, and it is a privilege to serve on the Board and contribute to shaping its future. During my tenure, I aim to foster cross-industry dialogue that promotes innovation and collaboration, which are critical to a safe, efficient, and cost-effective decommissioning sector.

Decommissioning is a growing area with numerous opportunities. The work Decom Mission undertakes to support the supply chain and emerging professionals is essential to the long-term success of the industry. I am excited to contribute to this important mission.”

Jinda Nelson, Chair of Decom Mission, added:

“We are delighted to welcome Caroline to our Board of Directors. Her depth of knowledge, industry experience, and dedication to advancing opportunities in decommissioning will be invaluable as we continue to support and represent our UK and international membership.”

Caroline’s appointment reflects Decom Mission’s ongoing commitment to strengthening governance and supporting the decommissioning sector’s growth and sustainability. 

UPCOMING GLOBAL EVENTS

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, London, UK

Safety in Travel Management Expertise and Excellence

John Nixon, Director of Global Customer Experience - ATP

When we think of risk and safety management within the energy industry, our minds will first go to on-site safety and ensuring that the working environment is secure, that personnel are compliant when working, and that they’ve had the appropriate safety training to complete their jobs. But safety at work begins at the moment that an employee leaves their home, and so too does the responsibility that an employer has for that individual.

Whether a crew member traveling to an offshore rig, or a member of senior management heading to an international event or meeting, the route may be different, but duty of care standards must always remain at the highest level.

Duty of care isn’t a subject that is niche to the energy industry, all businesses – regardless of size or sector – have a responsibility for their employees, clients, and wider communities alike. However, the energy industry does come with specific considerations and challenges, driven by the fact that personnel frequently travel to remote and high-risk locations, and it’s not just restricted to offshore platforms or isolated production sites. International collaboration and synergy are the industry’s greatest strengths, but that does come with a compromise in understanding that the job can take you to markets that are more volatile or have their own regional complexities.

Understanding and navigating the diverse differences between countries is demanding enough to become a full-time job for booking coordinators and logistics managers, and that is why external support can be a game-changer.

Placing People First

As a key part of the supply chain, proactive travel management partnerships can help provide the tools, expertise, and confidence to ensure workforce safety when travelling, maintaining duty of care standards without sacrificing operational efficiency. However, no two locations are the same with different environments, political factors, and regulations all influencing travel requirements.

In recognition of these key differences, ATPI takes a holistic but tailored approach. The industry’s trusted travel partner, we have a proven track record of supporting individuals get from A to B safely in over 170 countries worldwide. You can’t build this reputation

without a deep comprehension of factors that can influence how individuals travel, whether race, religion, gender, or sexuality.

So, how can we support you to maintain the highest safety management standards, set new benchmarks for employee duty of care, and maintain your global connectivity?

Real-Time Risk Management

Offering several travel management platforms tailored to energy companies, solutions such as our ATPI Traveller Tracking System help organisation to track traveller locations, assess established and potential risks in real-time as they develop, and respond to emergencies quickly and with confidence. The addition of instant travel updates and our awareness of global risks allow booking managers to anticipate potential disruptions and plan for the best course of action so that those travelling are never left behind or in compromised environments when working internationally.

Key features include:

> ATPI Traveler Tracking: Provides real-time monitoring of employee locations, enabling immediate response in emergencies.

> ATPI Alerts: Delivers real-time notifications about flight delays, political unrest, weather conditions, and travel disruptions affecting employees.

> Emergency Communication Tools: Enables direct, two-way communication between travellers and support teams, ensuring rapid response in crisis situations.

> Risk Assessment and Mitigation: Identifies high-risk destinations and develops contingency plans to protect traveling employees.

> Compliance Monitoring: Ensures all travel aligns with government regulations, corporate policies, and international safety standards using compliance technology for corporate travel.

By integrating technology with duty of care, ATPI empowers you to proactively manage travel risks to keep employees safe, connected, and supported - regardless of the location or scenario. With expert support on hand, travellers have the safety net that allows them to focus on their work, knowing they are in trusted hands. 

If you would like to find out how ATPI can help streamline your travel management, email:

Wider Africa Energy Summit is the premier platform bringing together technology providers, innovators, project owners, and stakeholders to drive the future of the African energy industry.

Entering its second year, WAES aims to provide an exclusive environment for meaningful exchanges between the operator side of the industry and the supply chain.

Specifically focusing on the technologies that enhance oil recovery and the management of asset infrastructure.

waesummit.com

Empowering a Safe, Skilled, and FutureReady Workforce

The global, not-forprofit skills authority for safety-critical industries.

At OPITO, our mission is clear – to be the leading global skills authority for safety-critical industries. Our purpose drives us to provide expertise and solutions that elevate safety, skills, and competence across a global workforce, creating a safer and more skilled future for all.

We work with governments, industry, and training providers to shape standards, drive workforce development, and deliver trusted qualifications across high-risk sectors worldwide.

From global safety standards and qualifications to future-focused initiatives like My Energy Future and the APTUS apprenticeship programme, we’re investing in the talent of tomorrow - ensuring workers are equipped, empowered, and ready to thrive in an evolving energy landscape.

Together, we’re building a safer, skilled future.