Issue 98 - International Growth

INTERNATIONAL GROWTH

Welcome to the November issue of ‘OGV Energy Magazine’, where this month we focus on the theme of ‘International Growth’.

A big thank you to our front cover partner, Vulcan (a Sawafi company), for featuring a compelling article by their CEO on pages 4–5, discussing how their partnership with Sawafi has driven their expansion as a leading force in well completion engineering.

We are also delighted to feature contributions from PD&MS, GDI, Three60, Rotech, TWMA, Marwell and Enerquip, 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 USA, and Australia, along with project updates from the E.I.C., legal advice from Brodies llp and an insight into the rise of hydrogen energy from Leyton

Thanks as always to our corporate partners, and we hope you

this issue of OGV Energy.

Scottish engineering, global impact: redefining well completion technology

The external perspective that we have added through our partnership with Sawafi has proved to be invaluable in navigating international business operations.

From its origins in the North East of Scotland, Vulcan Completion Products (VCP) has transformed regional engineering expertise into a global force, and is now operating in nearly 50 countries worldwide.

Established in 2017, VCP specialises in the design, manufacture, and application of advanced well cementing and completion technologies. Drawing on decades of combined industry experience the company delivers bespoke, precision-engineered solutions that consistently exceed client expectations. VCP’s product portfolio spans centralisers, reamer and guide shoes, float equipment, cement plugs, collars, and cable protectors each engineered to meet the most demanding operational requirements. With a reputation for quality, innovation, and reliability, the company’s Scottish-grown ingenuity continues to set new benchmarks for performance and service across the energy sector.

Recent growth has seen the company’s global team expand to nearly 40 professionals across key international locations including UK, US, UAE, Azerbaijan, Saudi Arabia, Vietnam as well as the company’s global headquarters in Aberdeenshire, Scotland. Recent key appointments include QHSE managers in the UK and APAC, a regional operations manager supporting increased market share in the Caspian region, a regional sales manager for Sub-Saharan Africa, and a business development lead for MENA.

The international footprint is further reinforced by a network of over 20 distributors and 90+ customers worldwide. Manufacturing and assembly operations now span the USA, UK, KSA, UAE, Thailand, Indonesia, Singapore, China, and India. This intentional strategy blends VCP’s technical expertise with local content to optimise delivery, reduce carbon emissions, and enhance client outcomes.

Central to fulfilling Vulcan Completion Products’ ambitious global expansion plans is its strategic partnership with Sawafi AlJazeera Oilfield Products and Services Co. (Sawafi), a leading Middle Eastern technology and energy group. Founded in 2013, Sawafi specialises in upstream technologies including drilling enhancement, intelligent completions, artificial lift systems, well characterisation and visualisation, realtime survey services, and AI-driven analytics.

The partnership is a powerful alliance that brings together cutting-edge expertise and thorough regional knowledge to deliver exceptional value to the global energy industry. By combining Vulcan Completion Products’ innovative technologies, born in the North East of Scotland, with Sawafi’s established presence and operational strength across the Middle East, the collaboration combines technical excellence with invaluable local insight to achieve mutual success.

Beyond commercial success, the collaboration with Sawafi has also nurtured knowledge sharing and training opportunities that will support the long-term sustainability of the energy sector in the region, aligning Vulcan Completion Products’ technical pedigree with Sawafi’s reach, to create a benchmark for international teamwork.

Supporting this momentum is VCP’s ISO 9001-accredited R&D hub in Westhill, Aberdeenshire. The centre houses a team with over a century of combined experience, dedicated to advancing well completion technologies through continuous innovation. To date, VCP has secured 57 global patents, underlining its commitment to pioneering solutions that redefine industry standards.

The relentless pursuit of sector development has already produced an unparalleled level of success, plus 57 worldwide patents that mark Vulcan Completion Products products out as truly unique, trailblazing solutions in a class of their own. This drive is set to continue at pace in 2026, with a brand-new suite of gamechanging products waiting in the wings and ready to hit the market next year.

They will follow in the footsteps of the company’s already illustrious portfolio which currently includes:

PHAZER™ Centralisers:

Designed to reduce drag and ECDs while ensuring optimal stand-off for zonal isolation. Variants such as PHAZER™:FLEX, PHAZER™:SUB, and PHAZER™:FLEX-TT (for extremely tight tolerances).

PHAZER™:Z - Zinc-Alloy Centralisers:

Deliver superior torque and drag reduction in both cased and open hole environments.

PHAZE-LOK™ Collars:

Compatible with the centraliser range for enhanced tubular performance.

PROBE™ Reaming/Guide and CWD Shoes:

Engineered for reliable casing/liner/screen installation in challenging wellbore conditions.

Premium Float Equipment:

Manufactured at API and ISO-certified facilities in Europe and Asia, these guide shoes and collars provide robust wellbore barriers during cementing, even under high flow rates, extended circulation, and LCM conditions.

Ian Kirk CEO/Managing Director of Vulcan Completion Products commented: “The external perspective that we have added through our partnership with Sawafi has proved to be invaluable in navigating international business operations in a post-Covid era.

“Our decision to establish an R&D facility in Scotland has been instrumental in maintaining our innovation edge and reaffirming our position as a global leader in engineered well completion technologies.” 

A SAWAFI COMPANY

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COMMUNITY news

THREE60 Energy names Ryan McPherson as Decommissioning Director

THREE60 Energy, a leading provider of life cycle solutions, has appointed Ryan McPherson as Decommissioning Director, further strengthening its management team.

Ryan brings more than 25 years of international energy sector experience to the role. He has held senior positions with both operators and service companies, leading large-scale projects across engineering, project delivery, and major asset management. His career has taken him across the UK and Europe including Hungary and the Netherlands, as well as further afield in Algeria, Egypt and Mexico, giving him extensive insight into complex and diverse operating environments. 

The fight against breast cancer deserves attention all year round.

For years, Izomax has proudly supported the Pink Ribbon campaign through annual donations each October. This year, they wanted to take their commitment one step further and make the important fight against breast cancer visible every single day of the year.

That’s why we’re introducing Thyra. She’s one of the AOGVs in our fleet that repair and maintain pipelines all over the world. From now on, Thyra will stand out, not in yellow, but in pink. And every time she’s sent out on a new assignment, Izomax will donate NOK 10,000 to the Pink Ribbon campaign. 

The Future of Offshore Operations – Innovation, Integration, and Impact

The offshore energy sector is undergoing a significant transformation.

As the industry adapts to late-life asset challenges, decarbonisation goals, and cost pressures, operators are rethinking traditional models. Integrated service delivery, digital innovation, and cross-functional collaboration are becoming essential to future-proof operations.

Vice President of Offshore Services at Bilfinger, Rod Agnew, speaks about the biggest challenges and opportunities facing offshore operators, and how Bilfinger is supporting them. 

Delivering expanded manufacturing capabilities to rapidly growing Middle East market.

Hunting PLC, the precision engineering group, is pleased to announce that it has today opened a new 45,000 sqft purposebuilt facility in Dubai, United Arab Emirates. This marks a significant step in delivering the Group’s Hunting 2030 strategy by strengthening the Group’s regional footprint in a high-growth market and bringing its leading manufacturing capabilities closer to customers in the Middle East, Africa and Asia-Pacific.

Hunting has had an established presence in the UAE since the 1970s, serving the critical and rapidly growing Middle Eastern market. 

Safelift Secures Landmark £4M+ Contract in Offshore Wind

Safelift Offshore, a specialist engineering company based in Aberdeenshire, has secured the largest contract in its 31-year history.

A multi-million-pound agreement has been secured with TenneT Offshore to design and supply manual handling and lifting equipment for two major offshore wind substation projects in Europe.

This landmark win, worth over £4 million, reflects Safelift’s accelerating pivot from its traditional oil and gas roots into the fast-growing renewables sector. The contract marks a breakthrough moment for the company, solidifying its role in the global energy transition and reinforcing its reputation as a trusted partner in complex offshore environments. 

ABL has been appointed through United India Insurance (UIIC) to oversee India’s Oil and Natural Gas Corporation Limited’s (ONGC) rig moves between September 2025 and May 2026.

Under the contract, ABL will act as marine warranty surveyor for an anticipated 25 ONGC rig moves. ABL will also be involved as tow master/marine warranty surveyor for an additional 70 moves onboard third-party Jackup units within ONGC’s fields off the west coast of India during the contract period. The total figure includes an expected 34 rig moves to new locations ahead of the Indian monsoon season from March to June.

The rig moving contract covers ONGC’s entire fleet of jack-ups and mobile offshore drilling units (MODUs) in Indian waters. 

Thyra Paints the Oil Industry Pink

ABL secures rig moving contract with ONGC

Hunting opens flagship facility in Dubai, UAE

Wellcem is an oil service company headquartered in Norway with branches located around the world.

Wellcem’s vision is to be a leading provider of technology for Plugging, Lost Circulation, Leak Stop, and Sand Consolidation in

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UK North Sea Energy Review

By Tsvetana Paraskova

The future of the UK offshore industry and tax regime, project startups, acquisition deals, and decommissioning contracts featured in the UK North Sea oil and gas sector in the past weeks.

Ahead of the Labour Party’s Conference at the end of September, Offshore Energies UK urged the Prime Minister to seize the opportunity to safeguard jobs, economic value, and net zero targets with pragmatic reform of energy policy in the national interest.

OEUK called for reform of the Energy Profits Levy (EPL), a pragmatic approach to oil and gas licensing, and backing for interlinked renewable projects and supply chains that can renew confidence across the energy mix.

“We urge the government to implement a competitive tax regime in 2026 and take a pragmatic approach to the future of our homegrown oil and gas industry,” said David Whitehouse, Chief Executive of OEUK.

“What happens to North Sea energy doesn’t begin and end in Aberdeen. It ripples through our industrial spine, across sectors and into Grangemouth, Humberside, Teesside,

Tyneside, East Anglia and the North West. It undermines the homegrown manufacture of things like fuels, chemicals and pharmaceuticals as well as our energy future. We must back UK industries.”

At the Labour conference, Prime Minister Sir Keir Starmer said that Britain must boost growth and protect jobs. This, OEUK argues, must be reflected in government support for homegrown energy.

OEUK’s Whitehouse said in response to the Prime Minister’s speech, “The government must choose the right path and these aspirations must be reflected in actions. The UK’s offshore energy industry is a national success story which supports around 200,000 skilled jobs, contributes billions in taxes, and keeps the lights on in homes and businesses across the country.”

OEUK has written to the prime minister urging him to replace the current Energy Profits Levy.

The current taxation policy “is not working. It is driving companies away, undermining investment and jobs, and raising less than one third of the tax revenue that was originally forecast,” Whitehouse said.

“Existing energy production infrastructure must not be dismantled prematurely, it must be fully used,” the executive said.

“This is not about clinging to the past, it is about making the most of what we have and building the future.”

Trust, Transparency and Transformation will be the themes of OEUK’s 2026 HSE conference in Aberdeen in February 2026.

“Our conference will focus on how we can sustain trust and enable people to challenge what more can be done to demonstrate transparency and identify areas to deliver transformational improvement.”

The UK could boost North Sea oil and gas production while remaining within the strictest international climate pathways, energy consulting firm Wood Mackenzie said in a new analysis, as the UK government considers the basin’s future following a consultation process.

Even if commercial reserves were increased by 50 percent, North Sea production can remain within the Intergovernmental Panel on Climate Change’s (IPCC) net zero emissions targets, the WoodMac analysis revealed.

This creates theoretical headroom for the UK Continental Shelf (UKCS) to produce an additional 2.6 billion barrels of oil equivalent by 2050. The surplus remains within climate science requirements whilst delivering substantial economic and environmental benefits, according to WoodMac’s analysis.

The findings emerge as the UK government considers whether to ban new exploration licences under its “science-aligned approach” to future UKCS production. WoodMac’s analysis showed compelling advantages of maximising domestic production over imports. Every additional trillion cubic feet of UKCS gas produced would save 15 Mt CO2e of Scope 1 and 2 emissions when displacing US LNG imports.

This is not about clinging to the past, it is about making the most of what we have and building the future.

“With more than 60 years oil and gas experience and 20 years of offshore wind delivery, the offshore energy industry is proud but not complacent about its HSE performance,” OEUK’s HSE & Operations Director, Mark Wilson, said.

“The more the UKCS produces, the less emissions will be released, and the less the UK will spend on imports. Such an approach will ensure production for decades to come and support the North Sea’s energy future,” said Gail Anderson, Research Director, North Sea Upstream, at Wood Mackenzie.

“The North Sea stands at a crossroads, but our analysis shows a clear pathway balancing climate science with energy security,” Anderson noted.

“Encouraging domestic production, including a smart licensing policy targeting known discoveries, would extend critical infrastructure life, whilst delivering substantial emissions and cost benefits over importing alternatives.”

At the same time, due to recent fiscal turmoil, 2025 is set to become the first year since 1960 without a single exploration well in the UK North Sea, WoodMac says.

The consultancy’s analysis advocates targeted licensing focused on existing discovered resources that could tie back to existing infrastructure.

A ban on all new licensing would ignore the strategic value of selective development. Even under a net zero scenario, the UK will consume around 500,000 barrels of oil equivalent per day and remain a net importer of oil and gas, according to Wood Mackenzie.

“The government faces pressure to restrict North Sea production, but risks undermining both climate goals and energy security,” WoodMac’s Anderson says.

Spirit Energy has completed the latest in a series of activities to boost gas production from its Morecambe hub, investing approximately £20 million to maximise economic recovery from the fields in the East Irish Sea. It is estimated the activities could increase production from the field by around 300,000 boe annually – enough to power an extra 130,000 UK homes for one year.

The work reflects Spirit Energy’s strategy to maximise economic recovery of its existing UK gas reserves while preparing to transform the North and South Morecambe fields into the UK’s largest offshore carbon store through its Morecambe Net Zero (MNZ) Peak Cluster project.

bp has awarded a new joint venture (JV) between THREE60 Energy and AF Offshore Decom, a subsidiary of AF Gruppen, a multimillion-pound contract to provide integrated decommissioning services for bp’s Andrew field in the North Sea.

The government faces pressure to restrict North Sea production, but risks undermining both climate goals and energy security

“The UK needs all types of energy and should encourage more hydrocarbons, carbon capture and storage, hydrogen and wind from the North Sea. This balanced approach would deliver the promised fair energy transition, support climate objectives and reduce UK energy costs whilst strengthening supply security.”

In company news, bp has started up its sixth major upstream oil and gas project of 2025 with production from the Murlach oil and gas field in the UK North Sea.

Murlach adds a peak net production of around 15,000 boed to the bp-operated Eastern Trough Area Project (ETAP) in the central North Sea.

The Murlach project, which received government and regulatory approvals in 2023, involved the redevelopment of a field originally in operation in the early 2000s. bp acquired the field licence after it was relinquished by the previous operator.

The redevelopment included drilling two new wells, adding subsea equipment, reusing some existing kit, and making topside changes to the ETAP central processing facility.

“A key focus for bp in the North Sea is to identify opportunities that can be developed competitively using existing infrastructure to effectively manage established oil and gas hubs for the entirety of their lifespan. Murlach serves as another great example of this,” said Doris Reiter, senior vice president of bp North Sea.

The contract will see the joint venture assume the role of decommissioning services partner in a first of its kind agreement in the UKCS. 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 Andrew field is located 225 km 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.

In another contract for the Andrew field decommissioning, bp has awarded Heerema Marine Contractors a contract for the Engineering, Preparation and Removal (EPR) of the Andrew platform’s topside and jacket.

The scope includes the removal, transport and offloading of the topside, comprising the Flare and Kinnoull Module, and the four-legged steel jacket with 12 skirt piles. This follows the successful removal of the Andrew Drilling Equipment Set (DES) in 2024, also executed by Heerema Marine Contractors. 

THREE6O ENERGY

A life cycle solutions company enabling a sustainable future.

Europe Energy Review

By Tsvetana Paraskova

More LNG from Norway to Europe, higher crude supply from Kazakhstan to Germany, and major deals and milestones in renewable energy in key European markets featured in Europe’s energy news flow in recent weeks.

“Askeladd Vest is an important step in the development of the Snøhvit field and will help maintain full production at Hammerfest LNG until onshore compression starts as part of the Snøhvit Future project in 2028,” said Grete B. Haaland, Equinor’s senior vice president for Exploration and Production North.

Canada-based Tenaz Energy Corp has bought the issued and outstanding shares of a private company with interests in the Gateway to the Ems (GEMS) project on the boundary of the Dutch and German sectors of the North Sea.

Net production from the assets, whose purchase price was US$244 million, is estimated to be 3,200 boe/d (99 percent of which TTF natural gas) during 2025, increasing to approximately 7,000 boepd during 2026.

Kazakhstan will raise its crude oil exports to Germany in 2026 after Kazakh national oil and gas firm KazMunayGas extended and expanded a supply agreement with Rosneft Deutschland, the German unit of the Russian state oil firm that Germany placed under trusteeship in 2022.

KazMunayGas and Rosneft Deutschland have agreed to raise monthly crude oil supply from Kazakhstan to 130,000 tons in 2026 from 100,000 tons now, KazMunayGas said.

Oil & Gas

Norway is set to raise LNG supply to Europe as Equinor and partners started up production from the Askeladd Vest subsea field in the Barents Sea.

Askeladd West consists of two wells in a new subsea template tied back to the Snøhvit field. The field contributes to continued high and long-term production of LNG from the processing plant at Melkøya, which accounts for 5 percent of Norway’s total natural gas exports, and about 2 percent of the EU’s gas needs.

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

Sakarya, the largest offshore natural gas field discovered in Turkey, is located about 170 km off the coast of Filyos, Zonguldak. The third phase of development entails a new dedicated floating production unit (FPU), fed by 27 wells located in the Sakarya and Amasra fields, connected by a new trunkline to the onshore facility in Filyos, on the Turkish Black Sea coast.

Saipem’s scope of work 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 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 UK government’s latest quarterly Energy Trends report showed in September that 73.8 percent of Great Britain’s power system generation came from low carbon technologies—renewables and nuclear power, up by 5.5 percentage points from 2023.

In the second quarter of 2025, the share of electricity generation from renewable sources hit a new record-high of 54.5 percent of all generation. A 10 percent increase in offshore wind generation to 10.8 TWh and a 27 percent jump in solar output to a record 7.1 TWh contributed to the new record. Solar generation was at a record high share of 11.0 percent of all generation, with both record sun hours and increased capacity contributing. Despite a 13 percent fall in nuclear output, the low-carbon generation share reached a record high of 69.8 percent, with fossil fuel share reaching a record low of 26.7 percent.

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

“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,” RenewableUK’s Director of Future Electricity Systems, Barnaby Wharton, said, commenting on these figures.

“As well as keeping the nation powered up, we’re creating new jobs in places like Teesside, the Humber, East Anglia, the Moray Firth, across the south of Wales and in Belfast. We now have 2,000 supply chain companies based in 70 constituencies all over the UK”.

Ireland has pledged 1 billion euro in Budget 2026 to accelerate the country’s energy transition. Budget 2026 includes funding of 558 million euro for Sustainable Energy Authority of Ireland (SEAI) residential and community energy upgrades, including the Solar PV Scheme. Budget 2026 also includes significant investment in offshore renewable energy site data surveying to assist in the derisking of future projects. The Offshore Site Surveying Programme has been allocated 8 million euros.

Wind Energy Ireland has welcomed the Budget 2026 announcement, with CEO Noel Cunniffe saying “This investment, along with additional funding to increase capacity within our State agencies, will help transform our electricity system and accelerate the delivery of clean, affordable and secure energy for Irish families and businesses.”

In company and project news, SSE has strengthened its onshore wind energy portfolio in Ireland with the successful completion of the 101-MW Yellow River Wind Farm, which officially entered full commercial operation in early October.

Private investment firm Ardian has entered into a definitive agreement to acquire 100 percent of Energia Group, one of the largest energy utilities on the island of Ireland, from global infrastructure investor I Squared Capital. Energia operates across the entire energy value chain in the Republic of Ireland and Northern Ireland, serving almost 900,000 homes and businesses. The electric utility is one of the longest established providers of renewable electricity in Ireland, supplying approximately 17 percent of the island of Ireland’s total electricity requirements and 20 percent of its total wind power.

Equinor and Gwynt Glas - a joint venture between EDF power solutions and ESB - have both entered into agreements for lease for their respective floating wind farm projects in the Celtic Sea, The Crown Estate said

The sites, which lie off the coasts of South Wales and South-West England, each have a capacity of up to 1.5 GW and hold the potential to generate clean energy for millions of homes.

Equinor and Gwynt Glas are now expected to focus on developing their project designs, delivering onshore and offshore site surveys, Environmental Impact Assessments (EIA), public engagement, and securing planning consents. Once these initial requirements have been completed, the developers can then apply to obtain a full lease from The Crown Estate to build and operate the new wind farms, which could be operational by the mid-2030s.

In France, a consortium formed by TotalEnergies and RWE has been selected by the Industry and Energy Ministry as the winner of the Centre Manche 2 (AO8) offshore wind tender, for the country’s largest renewable energy project. The consortium will be responsible for designing, developing, building, and operating a 1.5 GW offshore wind farm off the coast of Normandy. Located more than 40 km off the coast of Normandy, Centre Manche 2 will be the largest renewable energy project ever developed in France, with investment expected at about 4.5 billion euro.

Once built, the project will generate approximately 6 TWh per year and supply green electricity to the equivalent of over 1 million French households.

“The project makes strong commitments to France’s goal of solidifying and expanding its own offshore wind supply chain. It will use turbines and cables made in Europe. It will involve small and medium-sized businesses for at least 10% of the project, from studies and manufacturing to construction and operations,” the WindEurope association said Energy firm Eneco has expanded its partnership with tech giant Google into Belgium by signing a Power Purchase Agreement (PPA) to supply its data centres in Belgium with wind energy from Belgian wind farms.

Eneco and Google have entered into several contracts for solar and wind energy in the Netherlands over the past decade. The wind energy powering a data centre in the Eemshaven port in Groningen Province is produced on land, on the IJsselmeer lake and in the North Sea. 

USA Energy Review

By Tsvetana Paraskova

Rising costs and persisting uncertainty continue to drag lower oil and gas activity in the most prolific US shale basin, the Permian. Both exploration and production (E&P) companies and services firms flagged uncertainty about the price of oil and the cost of producing oil and gas as reasons for delaying investment decisions.

The firms appear more pessimistic as the company outlook index fell from -6.4 in the second quarter to -17.6 in the third quarter, the survey showed. Meanwhile, the outlook uncertainty index remained elevated but edged down from 47.1 to 44.6.

Oil and gas production declined slightly in the third quarter, according to executives at E&P firms. The oil production index remained negative and was relatively unchanged at -8.6 in the third quarter. Similarly, the natural gas production index was relatively unchanged at -3.2.

Costs increased, and all series posted above average cost indexes in the third quarter. Among oilfield services firms, input costs rose, but at a slightly slower pace than the previous quarter, as the input cost index declined slightly from 40.0 to 34.8. Among E&P firms, the finding and development costs index increased from 11.4 to 22.0. Also, the lease operating expenses index increased from 28.1 to 36.9.

In the oilfield services sector, companies reported modest deterioration in nearly all indicators. The equipment utilization index for oilfield services firms fell from -4.6 to -13.0. The operating margin index was relatively unchanged at -31.8, indicating margins compressed at a similar rate. Meanwhile, the prices received for services index declined slightly from -17.7 to -26.1.

US Oil and Gas Activity Slips Again

Activity in the oil and gas sector declined slightly in the third quarter of 2025, according to oil and gas executives responding to the latest Dallas Fed Energy Survey. The business activity index, the survey’s broadest measure of the conditions energy firms face in the Eleventh District – which includes Texas, northern Louisiana, and southern New Mexico – remained negative but edged up from -8.1 in the second quarter to -6.5 in the third quarter.

Respondents in the survey expect on average a West Texas Intermediate (WTI) oil price of $63 per barrel at the end of 2025, with responses ranging from $50 to $80 per barrel. In the longer term, respondents on average said they expect a WTI oil price of $69 per barrel two years from now and $77 per barrel five years from now.

Participants in the survey project on average a Henry Hub natural gas price of $3.30 per million British thermal units (MMBtu) at yearend 2025. Respondents on average said they anticipate a Henry Hub gas price of $3.94 per MMBtu two years from now and $4.50 per MMBtu five years from now. For reference, WTI spot prices averaged $63.80 per barrel, and Henry Hub spot prices averaged $2.99 per MMBtu during the survey collection period, 10-18 September.

Most executives in the survey said they had delayed investment decisions in response to heightened uncertainty about the price of oil and/or the cost of producing oil. A total of 42 percent of executives said they have slightly delayed investment decisions, and 36 percent of executives report they have significantly delayed decisions. Executives at small E&P firms were slightly more likely to report no delay compared with executives at large E&P firms.

Most executives, nearly 70 percent, said their hedging activity for 2025 and 2026 will be about the same as in 2024.

In the services sector, the majority of oil and gas support services executives expect artificial intelligence to help increase the average lifespan of their equipment. A total of 49 percent of executives expect a slight increase, and an additional 12 percent anticipate a meaningful increase. On the other hand, 39 percent don’t expect AI to increase the average lifespan of their equipment.

Moreover, almost half of the executives, 49 percent, estimate that up to one-quarter of their oilfield equipment is directly or indirectly sourced from China. Another 22 percent of executives said 26–50 percent was Chinese sourced. An additional 2 percent of executives said Chinese-sourced equipment made up 51–75 percent of holdings. On the other hand, 27 percent of executives said none of their firms’ oilfield equipment is sourced from China.

Overall, we feel good about the future of the industry but expect some short-term pain for the next year or so.

The majority, 79 percent, of oil and gas support services executives who estimate some portion of their equipment is directly or indirectly sourced from China expect impact on the cost of equipment would be slight. An additional 14 percent of executives expect significant impact. The remaining 7 percent said there would be no impact.

Commenting on the special questions in the survey, an E&P company executive said, “Overall, we feel good about the future of the industry but expect some short-term pain for the next year or so.”

Respondents are split regarding the future of US oil activity. Some expect an offshore oil and gas boom, but others warn that “We have begun the twilight of shale.”

“The “drill, baby, drill” return isn’t going to happen! Banks, shareholders, bondholders, C-suites, and everybody realizes the prior “drill, baby, drill” boom led to financial disasters and wasted capital, natural resources and human resources. From now on, economic decisions will have to be prudent and well-founded in logic, not hyperbole,” another executive at an E&P firm said.

In other comments to the survey, one executive noted that “The administration is pushing for $40 per barrel crude oil, and with tariffs on foreign tubular goods, prices are up, and drilling is going to disappear. The oil industry is once again going to lose valuable employees.”

Another executive wrote “The noise and chaos is deafening! Who wants to make a business decision in this unstable environment?”

Court Rules Biden

Administration Offshore Drilling Ban Unlawful

A US District court in Louisiana ruled in early October that the Biden Administration’s eleventh-hour attempt to block new oil and gas leasing in several US offshore areas was unlawful and exceeded the statutory authority of the executive branch.

Former US President Joe Biden issued an order to ban “for a period of time without specific expiration” oil and gas leasing in federal waters in areas offshore Alaska, the eastern Gulf of Mexico, and the East and West Coasts. The order, issued on January 6, days before Biden left office, was challenged in court by several U.S. states led by Louisiana,

Alabama, Alaska, Georgia and Mississippi, as well as the American Petroleum Institute (API) and the Gulf Energy Alliance.

In the October ruling, Louisiana District Court Judge James D. Cain Jr. wrote that “To the extent these were indeed supposed to overcome the power of subsequent executives to revoke or modify their withdrawals, they constituted a departure from the executive branch’s longstanding practice and exceed the authority granted.”

API welcomed the district court’s decision to reverse the Biden ban.

“We welcome the court’s decision to vacate this politically motivated decision and ensure our nation’s vast offshore resources remain a critical source of affordable energy, government revenue and stability around the world,” said Ryan Meyers, API Senior Vice President and General Counsel.

“This ruling marks another important step in advancing a robust new five-year offshore leasing program and ensuring the U.S. can meet rising energy demand.”

US offshore production accounts for 14 percent of total crude oil production in America, or nearly 2 million barrels of oil per day, API said, citing data from the US Energy Information Administration.

Robust offshore oil and natural gas development could generate over $8 billion in additional government revenue by 2040, a report by Energy and Industrial Advisory Partners (EIAP) commissioned by API showed early this year. 

Middle East Energy Review

By Tsvetana Paraskova

The OPEC+ alliance led by the Middle Eastern oil producers continues to increase crude output as it rolls back the production cuts from 2023, while the national oil companies of the Gulf producers announced major strategic investments and deals.

The OPEC+ producers cited “a steady global economic outlook and current healthy market fundamentals, as reflected in the low oil inventories,” as the reason for their continued reversal of the cuts.

As per usual, the producers warned that they “will continue to closely monitor and assess market conditions, and in their continuous efforts to support market stability, they 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.”

The eight OPEC+ countries also noted that the rollback “will provide an opportunity for the participating countries to accelerate their compensation.”

OPEC+ Proceeds with Restoring Production

The eight OPEC+ producers, which had announced additional voluntary output cuts in April and November 2023 – Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, and Oman – decided on 5 October 2025 to continue reversing the 1.65 million barrels per day cuts announced in April 2023. The producers will raise their production in November by 137,000 bpd, the same amount as in October, when they began tapping this 1.65 million bpd layer of cuts.

The shrinking spare capacity that could be activated within 90 days leaves the market exposed to the next supply shock, be it from new sanctions on Iran or Russia, or flare-ups in the conflicts in the Middle East.

Kurdistan Oil Exports Resume after 2 ½ Years

A steady global economic outlook and current healthy market fundamentals, as reflected in the low oil inventories

Oversupply Vs Shrinking Spare Capacity

Oil markets did not move much on the news, as the increase in November production was more modest than some industry and market analysts had feared.

At any rate, forecasters still expect oversupplied oil markets at the end of this year and early next year, as OPEC+ raises output and oil production from South and North America, predominantly Brazil, Guyana, Canada, and the US, continues to grow.

However, investment banks and analysts have started to warn that with the rollback of the cuts, OPEC+ is reducing its spare production capacity. Only Saudi Arabia, the United Arab Emirates (UAE), and Iraq to an extent, have meaningful spare capacity that can be brought online quickly and sustained for a period of time.

Oil supply from the Middle East to global markets has recently increased after oil exports from Iraq’s semi-autonomous region Kurdistan resumed on 27 September after two and a half years. Crude oil from Kurdistan now flows via the IraqTurkey pipeline from northern Iraq to the Turkish port of Ceyhan on the Mediterranean.

In September, eight companies operating in Kurdistan signed agreements with the Kurdistan Regional Government (KRG) and the Federal Government of Iraq to enable the restart of international crude exports from Kurdistan.

This agreement paved the way to the restart of exports from Kurdistan, which were halted for two and a half years, after they were shut in in March 2023 due to a dispute over who should authorize the Kurdish exports.

The federal government in Baghdad and the regional Kurdish government in Erbil squabbled for more than two years over who should be responsible for the oil exports and the subsequent revenue distribution.

Under the agreement, hailed as historic by Iraq’s federal government, KRG will deliver the crude to Iraqi state marketing company SOMO. The companies will deliver 180,000 to 190,000 bpd to the Ministry of Oil and reserve 50,000 bpd for the operation of domestic refineries.

MIDDLE EAST ENERGY REVIEW

NOCs Sign Major Funding and Development Deals

Investment firm KKR has bought a minority stake in ADNOC Gas Pipeline Assets LLC, the gas pipeline network of Abu Dhabi’s national oil company, expanding its strategic partnership with ADNOC and reflecting the firm’s confidence in Abu Dhabi’s competitiveness as a premier global investment destination.

The gas pipeline network connects ADNOC’s upstream assets to local off-takers in the United Arab Emirates (UAE). Pipeline ownership and operational management remain with ADNOC.

“KKR has a long history of owning and operating critical national infrastructure worldwide, collaborating closely with governments,” said Cristina González, Managing Director, Infrastructure, at KKR.

“This strategic partnership leverages KKR’s expertise in infrastructure investments and ADNOC’s operational excellence to deliver practical energy solutions. This investment in ADNOC Gas Pipeline Assets provides access to high-quality, long-dated yield alongside an outstanding partner in ADNOC.”

The deal for a minority stake in ADNOC’s gas pipelines assets follows the first such transaction in the Middle East, when KKR bought in 2019 a minority stake in ADNOC’s oil pipelines business. The 2019 acquisition of 40 percent in ADNOC Oil Pipelines by KKR and BlackRock was the first-ever investment of foreign asset managers in infrastructure of a state-owned energy firm in the Middle East.

KKR and BlackRock last year  sold the 40-percent stake in ADNOC Oil Pipelines LLC to Abu Dhabi-based alternative investment manager Lunate.

In Saudi Arabia, state oil giant Aramco has successfully completed a $3 billion international Islamic bond, or Sukuk, issuance across two tranches.

“We believe this successful issuance reflects the confidence of global investors in Aramco’s exceptional financial resilience and robust balance sheet, as we continue to optimize our capital structure,” said Ziad Al-Murshed, Aramco Executive Vice President of Finance & CFO.

“Our ability to price the offering with a negative new issue premium across both tranches demonstrates Aramco’s unique credit proposition and standing within international capital markets.”

Aramco has also teamed up with King Abdullah University of Science and Technology (KAUST) and US industrial conglomerate Honeywell to co-develop a next-generation direct Crude-to-Chemicals (CTC) technology.

Under a Joint Development Agreement (JDA), the collaboration will focus on developing and scaling up the full CTC process. This initiative aims to significantly reduce both capital and operating costs associated with CTC conversion.

The new CTC pathway is designed to extract significant value from each barrel of crude oil by converting it directly into light olefins and other high-demand chemicals, KAUST said. The innovative CTC process concept is expected to improve fuel efficiency, carbon utilisation, and process economics— allowing for more efficient and cost-effective production at scale.

The collaboration is aligned with Saudi Arabia’s Vision 2030 by helping to advance economic diversification, build national research and technology capabilities, and strengthen the Kingdom’s position across the petrochemicals industry.

“By harnessing the power of cutting-edge technologies, we aim to enhance energy efficiency and unlock increased value from

every barrel of crude,” stated Dr. Ali Al-Meshari, Aramco Senior Vice President of Technology Oversight & Coordination.

“This novel Crude-to-Chemicals process is aligned with our vision of supporting the global transition towards cleaner, high-performance chemical production.”

From Qatar, the national firm QatarEnergy has entered into an agreement to buy from Shell a 27-percent participating interest in the North Cleopatra block offshore Egypt. Under the terms of the transaction, which is subject to approval by the Egyptian government, Shell will retain a 36-percent participating interest as operator. The other participating interest holders are Chevron with 27 percent and Tharwa Petroleum Company with 10 percent.

The North Cleopatra block is located in the frontier Herodotus basin and is north and adjacent to the North El-Dabaa block, where QatarEnergy holds a 23-percent participating interest.

QatarEnergy has also signed a long-term sales and purchase agreement with Germany-based Messer for the supply of 100 million cubic feet per annum of high-purity helium from Qatar’s facilities in Ras Laffan to global markets.

“This agreement underscores QatarEnergy’s commitment to delivering reliable resources from one of the world’s largest helium producers to support fast-growing industries worldwide,” said Qatar’s Minister of State for Energy Affairs, Saad Sherida Al-Kaabi, who is also the president and CEO of QatarEnergy.

Norway Energy Review

By Tsvetana Paraskova

Norway is asking operators to nominate blocks for the next exploration and production licensing round, while companies are boosting production and recovery from mature and recently developed fields.

The Norwegian Offshore Directorate is also submitting proposed changes to the Resource Management Regulations and the Regulations relating to storage of CO2 on the shelf for public consultation. Stakeholders can submit comments to the proposed regulatory changes by 1 December 2025.

The regulator at the end of September granted consent for the start-up of a tie-in from the Troll B platform to the Kvitebjørn gas export line. This project for a new gas export solution from Troll B to the Kvitebjørn gas pipeline to Kollsnes will help reduce the decline in gas exports in coming years. The solution will facilitate increased gas export from Troll B, as gas injection is no longer needed there. It also provides additional flexibility as the gas can be exported via both the Troll A and Kvitebjørn gas pipelines.

The first compressor module in phase two was replaced in 2023, now the second and final module has been installed, at a depth of 270 metres.

Combined for both phases, the recovery rate from the Mikkel and Midgard fields will increase to 90 percent due to the compressor plant. This amounts to an additional 306 million barrels of oil equivalent from the fields, Equinor said.

The new gas export solution with tie-in to the Kvitebjørn gas pipeline will contribute to reducing the decline in gas production in the coming year

“In this project, Equinor, together with partners and suppliers, has further developed and qualified the next generation of compressor modules. The technology allows us to recover more gas from producing fields,” said Trond Bokn, Equinor’s senior vice president for project development.

Fresh off the 25th licensing round for acreage in mature areas offshore Norway, which attracted applications from 20 companies, the Norwegian Offshore Directorate invited the companies on the Norwegian continental shelf (NCS) to nominate blocks for the 26th licensing round on the NCS.

Available attractive acreage is the key to ensure continued high activity in the industry. Ordinary licensing rounds make acreage available in more frontier areas, the directorate said.

The 26th round is expected to be held in 2026.

“The new gas export solution with tie-in to the Kvitebjørn gas pipeline will contribute to reducing the decline in gas production in the coming years,” said Niels Erik Hald, assistant director Offshore South at the Norwegian Offshore Directorate.

A new discovery was also made on the NCS in recent weeks. OKEA and its partners have made an oil discovery near the Brage field. The preliminary estimated size of the discoveries in well 31/4-A-15 B is 2-7 million barrels in the Cook Formation and 14-26 million barrels in the Statfjord group in the Talisker area, the offshore regulator said.

Equinor said that together with its partners in Åsgard and Mikkel licences it had started phase 2 of Åsgard subsea compression in the Norwegian Sea. The project will help maintain production from the field by increasing the pressure in the pipelines between the wells and the Åsgard B platform.

“Good resource utilisation is important to maintain high and stable production from the Norwegian continental shelf,” Bokn added.

Norway is also boosting LNG supply to Europe as Equinor and partners started up production from the Askeladd Vest subsea field in the Barents Sea.

Askeladd West consists of two wells in a new subsea template tied back to the Snøhvit field. The field contributes to continued high and long-term production of LNG from the processing plant at Melkøya.

“Askeladd Vest is an important step in the development of the Snøhvit field and will help maintain full production at Hammerfest LNG until onshore compression starts as part of the Snøhvit Future project in 2028,” said Grete B. Haaland, Equinor’s senior vice president for Exploration and Production North.

The Melkøya plant produces 6.5 billion standard cubic metres of gas each year, which is the equivalent of about 5 percent

of Norway’s total gas exports, and about 2 percent of the EU’s gas needs. Custom-built LNG vessels leave Melkøya every five days, carrying cooled liquid gas from HLNG to the European markets.

Vår Energi ASA has acquired TotalEnergies’ ownership interest in the Ekofisk PPF (Previously Produced Fields) development project.

The transaction will increase Vår Energi’s ownership interest in the PPF project in licence PL018F from 12.388 percent to 52.284 percent, strengthening its position in the Greater Ekofisk Area.

Completion of the deal is subject to Final Investment Decision for the PPF project and customary regulatory approvals, including the carve-out of the PL018F licence from the PL018 licence.

The Ekofisk PPF project, located in the Greater Ekofisk Area, will extend the production life of the Ekofisk area.

It is encouraging that two consortia, consisting of strong players, have applied to take part in the competition for floating offshore wind in Utsira Nord

The re-development will enable better reservoir exposure and production rates resulting in significantly increased recoverable resources, through use of new completion and horizontal well technology. The project consists of four new subsea templates and 11 production wells tied back to the Ekofisk Field Center.

The transaction will add estimated net proved plus probable reserves of 38 million barrels of oil equivalent for Vår Energi with low operating costs per barrel and potential for further growth. Final investment decision is expected to be taken in the fourth quarter this year with production from the project expected to start up at the end of 2028.

Vår Energi has also announced that both production and recoverable volumes from the Gjøa field have increased, following the startup of the Gjøa low pressure project.

The project has modified the compressor systems on the Gjøa platform, which has enabled the wells to produce longer and at higher rates, increasing the remaining recoverable volumes.

Production from the Gjøa field increased from 35,000 boepd to 41,000 boepd (gross) as a result of the start-up. In addition, remaining recoverable volumes increased by a total of 6.3 million boe, representing approximately 25 percent increase, Vår Energi said.

“By using off-the-shelf technology, we are not only boosting production and remaining recoverable volumes from the Gjøa field, we are also prolonging the economic lifetime of the other producing fields Duva, Vega and

Nova that are tied into the Gjøa platform,” Vår Energi COO of Torger Rød said.

In the renewable energy sector,

Norway’s Energy Ministry has received two applications for the award of project areas for floating offshore wind in Utsira Nord.

Two consortia have applied—one is Equinor Utsira Nord AS and Vårgrønn Utsira Nord AS, and the other is the Harald Hårfagre AS consortium of Deep Wind Offshore Norway AS and EDF Renouvelables International SAS.

The Ministry will now begin the process of assessing the applications.

“It is encouraging that two consortia, consisting of strong players, have applied to take part in the competition for floating offshore wind in Utsira Nord,” Energy Minister Terje Aasland said.

In May this year, the Ministry announced a competition for the allocation of project areas

for floating offshore wind in Utsira Nord.

The Norwegian Government has an ambition to allocate areas for 30,000 MW of offshore wind production by 2040.

“Offshore wind is one of the government’s key focus areas to ensure sufficient power supply in the years ahead. During the development phase, floating offshore wind in Utsira Nord will play an important role in advancing technology and reducing costs,” Aasland said.

“By investing in offshore wind, we are also laying a solid foundation for Norwegian suppliers to compete in the development of future offshore wind projects,” the minister noted.

The small pool of applicants “is a clear signal to the authorities that the industry is ready to deliver, but at the same time we must learn from the process and create more predictability going forward,” Arvid Nesse, CEO of Norwegian Offshore Wind, commented

“This applies both to the timetable for new licensing rounds and to the criteria and framework conditions for those investing in Norwegian offshore wind farms.” 

Australia Energy Review

By Tsvetana Paraskova

shareholder value, with base business generating strong, stable cash flows underpinned by disciplined low-cost operating model, the company said.

New oil and gas projects have advanced in Australia in recent weeks, the federal government set 2035 clean energy targets, while a consortium led by Abu Dhabi’s energy company dropped a bid to buy one of the Australian top oil and gas producers, Santos.

Consortium Drops Pursuit to Acquire Santos

A consortium led by XRG P.J.S.C., a subsidiary of Abu Dhabi National Oil Company and including Abu Dhabi Development Holding Company and Carlyle, has withdrawn its indicative proposal to acquire 100 percent of the issued shares of Santos via a cash scheme of arrangement, the Australia-based company said in September.

The two parties failed to reach an agreement on the valuation of Santos and a sale price. Meanwhile, Santos continues to successfully execute its clear strategy to deliver superior

Santos’ two major development projects, Barossa and Pikka phase 1, are well advanced and materially de-risked through proven selfexecute capability, positioning Santos for around 30 percent increase in production by 2027. As these projects come online, Santos’ capacity to generate free cash flow will materially strengthen, supporting greater returns to shareholders under its capital allocation framework, the firm said.

“Santos has a clear strategy, strong leadership and high-quality growth opportunities across our global portfolio. The Board is confident these strengths will deliver long-term value for shareholders,” Santos Chair, Keith Spence, said after the XRG Consortium pulled out its offer.

New Oil and Gas Projects Near Start-up

A few days later, Santos announced that the BW Opal FPSO (floating production, storage and offloading vessel) had successfully received first gas into the facility to commence production operations. This follows the BW Opal achieving ready for start-up status on 16 September 2025, and the commencement of flow from the subsea wells. This is a major milestone for Santos and its Barossa joint venture partners, PRISM Energy Australia and JERA Australia, in delivering the Barossa LNG project.

“First gas into the FPSO is an important step for the project and a credit to the hard work of our people and support from our partners. It puts us on track to deliver reliable energy to our customers and long-term value to our shareholders from Barossa LNG,” said Kevin Gallagher, Santos managing director and chief executive officer.

Santos has also signed a non-binding memorandum of understanding (MOU) with Orica, one of the world’s leading mining and infrastructure solutions providers, for potential domestic gas supply from the Narrabri Gas Project to Orica’s east coast manufacturing network in the longer term.

The parties will negotiate potential domestic gas supply by Santos to Orica of up to 15 PJ per year from Narrabri for a period of up to 10 years and will also explore decarbonisation activities through Santos’ third-party carbon management business.

Santos signed another non-binding memorandum of understanding with Narrabri Shire Council for the potential supply of natural gas from the Narrabri Gas Project to a new industrial precinct, in a deal designed to attract new business and boost economic growth in the region.

Australia Approves North West Shelf Project Extension

Australia’s federal government has given the  final approval for the North West Shelf Project Extension that will see the operating life of the country’s biggest and oldest LNG plant extended to 2070.

Australia’s Environment Minister, Murray Watt, gave the final approval to the project, with 48 strict conditions that will avoid and mitigate significant impacts to the Murujuga rock art.

Woodside’s North West Shelf gas processing plant in Karratha, Western Australia, the country’s first and largest LNG plant, can now operate until 2070.

Woodside and the North West Shelf Joint Venture  welcomed the Australian Government’s final decision to grant environmental approval for the North West Shelf Project Extension.

“This final approval provides certainty for the ongoing operation of the North West Shelf Project, so it can continue to provide reliable energy supplies as it has for more than 40 years,” said Liz Westcott, Woodside Executive Vice President and Chief Operating Officer Australia.

Woodside Signs LNG and Hydrogen Deals

At the end of September, Woodside Energy, Japan Suiso Energy, Ltd. (JSE) and The Kansai Electric Power Co., Inc. (KEPCO) announced a new memorandum of understanding to

pioneer the development of a liquid hydrogen supply chain between Australia and Japan.

Under the MOU, the parties will look to create an innovative supply chain in which liquid hydrogen, produced at Woodside’s proposed H2Perth Project in Western Australia, would be shipped in liquid hydrogen carriers to receiving terminals in Japan.

The H2Perth Project would be located in the Rockingham and Kwinana Industrial Zones in Perth. The facility is intended to produce liquid hydrogen via natural gas reforming, with the intention of achieving net zero Scope 1 and 2 greenhouse gas emissions from the start of operations. This would be achieved through the application of carbon capture and storage, subject to further technical assessments and securing all necessary commercial arrangements and regulatory approvals, and to the extent needed the use of carbon credits as offsets.

As a result, AEMO will not request the Australian Energy Regulator to consider imposing an obligation on retailers and liable entities to enter sufficient contracts through the retailer reliability obligation (RRO) for South Australia in 2026-27.

Australia Sets 2035 Target on Path to Net Zero

The federal government in September announced Australia’s 2035 emissions target, the next step on the path to the long-term target of net zero by 2050. The government also released the Net Zero Plan, along with a series of supporting documents, which outline how Australia will achieve these targets.

Every wind farm, every solar project, every big battery makes the next one easier. We’re hitting critical mass now, and momentum is on our side

The government has set a national target to reduce emissions by 62–70 percent below 2005 levels by 2035. This target is ambitious, achievable, and in Australia’s national interests, the cabinet said.

In LNG supply, Turkey’s energy firm Boru Hatları ile Petrol Taşıma A.Ş. (BOTAŞ) and Woodside have signed an LNG Heads of Agreement under which Woodside will supply BOTAŞ a total of approximately 5.8 billion cubic meters natural gas equivalent of LNG for up to nine years starting from 2030, primarily from the Louisiana LNG project.

AEMO No Longer Expects Reliability Gap for South Australia

The Australian Energy Market Operator (AEMO) published in October an update to the 2025 Electricity Statement of Opportunities (ESOO), the 10-year reliability outlook for the National Electricity Market (NEM).

The update was triggered by the delayed retirement of three units at the Torrens Island B Power Station (600 megawatts) in South Australia from 1 July 2026 to 1 July 2028, and the earlier potential closure of the Gladstone Power Station (1,680 MW) in Queensland from 2035 to 31 March 2029.

The Update shows that the previously forecast reliability gap for South Australia under the ‘Committed and Anticipated Developments’ outlook in 2026-27 is no longer expected.

“The delayed retirement of AGL’s Torrens Island B power station has improved the shortterm reliability outlook in South Australia,” said Nicola Falcon, AEMO Executive General Manager System Design.

To achieve this target, Australia will build on existing policies to support industry to lower emissions with the Safeguard Mechanism, build a more resilient economy powered by clean energy, offer more choices in fuelefficient and zero emissions vehicles with the New Vehicle Efficiency Standard, and help Australians join the clean energy transition with the Cheaper Home Batteries Program.

The Clean Energy Council welcomed the setting of Australia’s next emissions reduction target.

“These targets are essential to give investors and communities the confidence that Australia is serious about delivering on its climate commitments,” the Council said.

“The clean energy industry is fully committed to doing its part to meet this new target. Renewable energy, backed by firming and storage, is delivering clean, reliable and affordable power for Australian familiesand businesses.”

Brett Wickham, Interim CEO of the Clean Energy Council, commented,

“Every wind farm, every solar project, every big battery makes the next one easier. We’re hitting critical mass now, and momentum is on our side.”

“With clear policy settings, strong investor appetite and projects rolling out across the nation, we are confident the sector can deliver the next big leap and ensure Australia’s energy future is clean, reliable and affordable.” 

RCP-EDR

ELECTRONIC DRILLING RECORDER

The RCP EDR is designed to give operators a clear, unambiguous overview of critical drilling and mud data processes The system has been developed by RCP to greatly improve how information is presented using the latest industrial technologies and user-friendly interfaces.

The RCP EDR offers a quick and cost-effective solution for clients considering a new installation or a partial upgrade to their existing drilling instrumentation systems Our highly experienced engineers and software developers allows us to tailor each new system to meet your exact needs meaning that you do not pay for functionality you will never use

The RCP EDR utilizes a variety of sensing technologies to monitor the drilling processes, (typically: Level, Pressure, Height, Temperature and Flow). Sensor output signals are received by the distributed I/O racks and are then processed by the EDR.

Processed information is then transmitted through network communication modules to each of the user interfaces including remotely networked PC’s and local HMI’s System and operator interface communications may utilize either: Fibre-Optic, Profinet, Profibus or Industrial Ethernet connection

Brent Oil Through the Decades:

1 YEAR AGO

1 year ago (Oct 2024)

Around October 2024, Brent crude traded near US $75.6 per barrel.

Global indicators included robust demand in Asia, tight OPEC+ production discipline, and geopolitical risk premiums (especially in the Middle East) supporting the price.

5 YEARS AGO

5 years ago (Oct 2019)

In October 2019, Brent was about US $59–60 per barrel.

At that time, global growth was slowing, trade tensions weighed on demand, and U.S. shale continued driving flexibility in supply, while OPEC sought to stabilize the market.

10 YEARS AGO

10 years ago (Oct 2015)

By October 2015, Brent had fallen to roughly US $48.9 per barrel

This was amid a supply glut, rising U.S. production, weaker demand (particularly from China), and OPEC’s decision to maintain output — all exerting downward pressure globally.

At the heart of OGV Media Group is the OGV Community, a corporate membership service that connects energy sector organisations with our growing network of professionals, leveraging member engagement and platform traffic to maximize brand exposure.

Subscription to the OGV Community offers its members the following growing list of benefits:

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Energy projects and business intelligence in the energy sector

The EIC delivers high-value market intelligence through its online energy project database, and via a global network of staff to provide qualified regional insight. Along with practical assistance and facilitation services, the EIC’s access to information keeps members one step ahead of the competition in a demanding global marketplace.

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It is renowned for excellence in the provision of services that unlock opportunities for its members, helping the supply chain to win business across the globe.

The EIC provides one of the most comprehensive sources of energy projects and business intelligence in the energy sector today.

PETRONAS ASSET RETIREMENT PROGRAMME

Dayang Enterprise is the only vendor of Petronas that is invited to bid for all three packages of for decommissioning across Sarawak, Sabah and Peninsular Malaysia. The tender, which is currently in its final evaluation stages, covers 31 platforms throughout Malaysia over three years. The contracts are expected to be awarded by Q4 2025 or H1 2026 at the latest.

MALAYSIA/VIETNAM

BUNGER ASTER FULL FIELD DEVELOPMENT

Hibiscus is planning to conduct a comprehensive evaluation to progress the Bunga Aster development with first oil expected in 2029. This decision follows the successful completion of the Bunga Aster-2 appraisal well.

HAMMERHEAD OIL FIELD (STABROEK PHASE 7HAMMERHEAD FPSO)

Since the announcement of the FID being reached in September several contracts have been awarded. MODEC has been the EPCI contract to deliver the FPSO, Saipem has EPCI contract for the subsea, umbilical, riser and flowline structures for the production facility and gas export system, and TechnipFMC has the contract for the subsea production system.

EL KING GAS DISCOVERY

bp and EGAS signed an MoU to for a new five-well drilling programme at the West Nile Delta. The new wells will be tied-back to existing facilities at WND. This programme, along with the exploration wells at El King and Fayoum are part of bp’s plans to increase production in Egypt up to 2.5 MMboe/d by 2030. Production capacity may be increased further by 2035. A second well will be drilled at El King by Q1 2026.

VIJAYAPURAM GAS DISCOVERY

Oil India has made gas discovery at Vijayapuram-2 exploration well that is located 17 km from the shoreline at a water depth of 295 m. The well was drilled to a depth of 2,650 m. The capacity of the gas discovery has not been disclosed. The Vijayapuram discovery is part of AN-OSHP-2018/1 Block under the Open Acreage Licensing Policy (OALP) in the offshore Andaman area.

RATAWI FIELD DEVELOPMENT PHASE 2

ENKA has signed a contract with TotalEnergies for the EPC of the Central Processing Facility for the project. The CPF is expected to be commissioned within three years and will have a capacity of 210,000 b/d.

ENCHOVA-PAMPO FIELDS DECOMMISSIONING (WELL P&A AND SUBSEA EQUIPMENT REMOVAL)

OceanPact has announced that it has won the EPRD tender and signed a contract worth more than 1 billion BRL with Trident Energy to work on the decommissioning project. Start of activities are planned to begin in Q1 2026 and will take up to three years to be completed. The scope of work includes the decommissioning of 630 km of flexible risers, plus small manifolds and other subsea equipment.

VOLANS GAS CONDENSATE DISCOVERY

Rhino Resources has made a gas condensate discovery via the Volans-1X exploration well. Drilling operations started back in July and were conducted utilising the Deepsea Mira semi-submersible rig. Further information covering the discoveries resources estimates will be assessed in the future.

TIBER-GUADALUPE OFFSHORE OIL FIELD

The Tiber-Guadalupe project has seen a FID reached. The development will include a floating production platform with capacity of up to 80,000b/d. BP plans to drill six wells at Tiber and link them to the facility, alongside a twowell tieback from Guadalupe field. Combined recoverable resources sum up about 350 million barrels of oil equivalent.

INDONESIA

$250 million

PT MGA Utama Energi

SEPANJANG BLOCK FSO PROJECT

PT MGA Utama Energi (MGAU) has initiated the PQ process to look for an FSO that will support reactivation operations at the Sepanjang Block on Sepanjang Island in East Java, Indonesia. The operator is expected to charter an Indonesian-flagged FSO that is not more than 20 years old. Companies interested in submitting their registration and pre-qualification documents must do so by the 6 November.

SÉPIA OIL FIELD (PHASE 2 - P-85 FPSO)

SLB has won a contract to deliver completion services and technology for up to 35 ultradeepwater wells in the phase 2 of Atapu and Sépia. Under the contract, SLB will provide advanced electric completions technologies and digital solutions to support realtime production intelligence and enhanced reservoir management.  Work is expected to commence around Q2 2026.

NAHR BIN UMAR FIELDFIELD DEVELOPMENT AND FLARE GAS PROJECT

Baker Hughes has signed an agreement with Halfaya Gas Company (HGC) to advance a flare gas recovery system at the Bin Umar gas processing plant in southeastern Iraq. The project, building on a prior MoU and pre-FEED study, will recover up to 300 MMscf/d of flared gas. The recovered gas will be converted into treated dry gas, LPG, and condensate for both domestic consumption and export.

Energy Firms Pursue International Growth

As operating oil and gas fields are maturing while global demand still grows, international majors have set their sights on increasing frontier exploration and expanding conventional energy projects worldwide.

Global Field Output Declines Accelerate

The world needs investments in existing oil and gas fields just to curb the accelerating output declines, the International Energy Agency (IEA) said in a recent report, “The Implications of Oil and Gas Field Decline Rates”.

The average rate at which output at oil and gas fields declines over time has significantly accelerated across geographies, largely due to higher reliance on shale and deep offshore resources, the report found. Energy companies will now have to work much harder before just to maintain production at today’s levels, the IEA said.

Nearly 90 percent of annual upstream oil and gas investment since 2019 has been dedicated to offsetting production declines rather than to meet demand growth. Investment in 2025 is set to be around US$570 billion, and if this

persists, modest production growth could continue in the future. But a relatively small drop in upstream investment can mean the difference between oil and gas supply growth and static production, the IEA reckons.

If all capital investment in existing sources of oil and gas production were to cease immediately, global oil production would fall by 8 percent per year on average over the next decade, or by around 5.5 million barrels per day (bpd) each year. This is equivalent to losing more than the annual output of Brazil and Norway each year, according to the agency’s estimates. Natural gas production would fall by an average of 9 percent, or by 270 bcm, each year, equivalent to total natural gas production from the whole of Africa today.

“Decline rates are the elephant in the room for any discussion of investment needs in oil and gas, and our new analysis shows that they have accelerated in recent years,” said IEA Executive Director Fatih Birol.

“In the case of oil, an absence of upstream investment would remove the equivalent of Brazil and Norway’s combined production each year from the global market balance. The situation means that the industry has to run much faster just to stand still. And careful attention needs to be paid to the potential consequences for market balances, energy security and emissions.”

Against this backdrop, keeping global oil and gas production constant over time would require the development of new resources. Even with continued spending on existing fields, the IEA’s analysis shows that more than 45 million bpd of oil and nearly 2,000 bcm of gas from new conventional fields would be required by 2050 to maintain production at today’s levels. This would be the equivalent of adding the total oil and gas production from all of the top three producers combined, according to the IEA.

The Return of Frontier Exploration

The rise in oil and gas demand and decline in discovered resources have prompted the industry to pursue frontier discoveries amid a global focus on energy security, Rystad Energy said in a report in September.

The six global majors – ExxonMobil, Chevron, Shell, TotalEnergies, BP, and Eni – have been responsible for about 20 percent of the total conventional oil and gas volumes discovered since 2020, the intelligence firm said.

“Overall, the six majors are pushing the boundaries of exploration, targeting frontier areas in search of new discoveries to sustain their businesses. While the risks are high, the potential rewards are significant, and the industry is likely to see increased activity in these regions in the coming years,” said Taiyab Zain Shariff, Vice President – Upstream Exploration at Rystad Energy.

Exxon targets Trinidad and Tobago for exploration to potentially replicate its success in Guyana, TotalEnergies is betting on Suriname, BP made a massive discovery offshore Brazil and vies for Libya and Caspian Sea exploration, while Eni, with its “dual exploration” strategy, targets resources and fast monetisation of oil and gas discoveries offshore Africa.

West Africa Potential

For example, at the end of September, Eni completed the sale of 30 percent in its operational Baleine oil and gas project offshore Cote d’Ivoire to Vitol Group, the world’s biggest independent oil trader.

The sale of the minority stake in Baleine is part of Eni’s strategy to optimise its upstream portfolio by accelerating the monetisation of exploration discoveries through the divestment of equity stakes, a model it has dubbed the “dual exploration model.” Eni has been pursuing this model in recent years—to sell part of its stake in operated assets to other companies to fast-track oil and gas discoveries to production.

Eni and Vitol are also partners in the OCTP and Block 4 projects in Ghana, and are now further consolidating cooperation in West Africa.

In the West Africa region, established producers Nigeria and Angola seek fiscal reforms for their mature basins, while a wave of high-impact exploration efforts are under way in Namibia, Ghana, Cote d’Ivoire, and the west coast of South Africa.

“While Nigeria and Angola introduce fiscal reforms for mature offshore basins, high-impact exploration reveals untapped potential for Cretaceous plays,” Ian Thom, Research Director, Upstream, at Wood Mackenzie, says

Nigeria and Angola have enacted incentives to stimulate investment and project approvals, Thom added.

“While Nigeria and Angola work to revitalise their existing assets, a more dramatic story of frontier exploration is unfolding across West Africa offshore. A strategic pivot from traditional Tertiary-age reservoirs to deeper, more complex Cretaceous plays has gained momentum,” the expert noted.

TotalEnergies and Shell are driving this exploration shift that has been catalysed by a string of game-changing discoveries like Ghana’s Jubilee, Venus and Graff in Namibia, and Baleine in Côte d’Ivoire.

However, more than half of the recently discovered resources remain subcommercial, hindered by challenges such as low reservoir permeability and, critically, the lack of viable markets and infrastructure for the associated gas, according to WoodMac.

The rapid development of Baleine stands in contrast to the slower progress at Namibia’s oil and gas discoveries.

“This shows that above-ground factors are just as important as below-ground potential,” Thom said.

Ultimately, West Africa’s upstream future would depend on both fiscal ingenuity in mature basins and continued exploration success in frontier plays that can deliver the next generation of world-class energy projects, he added.

Middle East NOCs Balance Regional Needs with Global Energy Shifts

The national oil companies (NOCs) in the Middle East continue to play a pivotal role in global energy security amid shifting market dynamics and the energy transition, Aditya Saraswat, Senior Vice President, Research Director MENA, at Rystad Energy, wrote in a recent special insight.

The Middle East’s NOCs are expanding capacity and scaling international portfolios amid slowing growth from non-OPEC+ supply and higher hurdles to global upstream investment.

The NOCs have low breakeven costs, strong domestic bases, and strategic ambitions, and are well-positioned to meet growing international demand for energy, Saraswat reckons.

Backed by over 6.5 million barrels per day of surplus crude capacity as of the end of the first half of 2025, and $400 billion worth of project sanctioning through 2020-2035, particularly in gas and offshore projects, the Middle East is poised to sustain its energy leadership while driving economic diversification and low-carbon growth.

Ongoing crude oil expansion projects in the UAE, Saudi Arabia, Iraq, and Kuwait are focused on maintaining and further increasing capacity. For Saudi Arabia and the UAE, offshore developments at prolific fields like Upper and Lower Zakum, Berri, Marjan, and Zuluf are crucial for their targets of 12 million bpd and 5 million bpd, respectively. Additional expansions at Upper Zakum, Safaniya, and Manifa could provide further capacity boosts as both countries look to offset declines from their onshore assets, which have shouldered over half of the overall output up until now, according to Rystad Energy.

Moreover, amid the ongoing OPEC+ production agreements, which limit Middle East NOCs from fully harnessing their domestic production potential, these companies have strategically pivoted toward aggressive international expansion to sustain growth, Saraswat notes. 

By Tsvetana Paraskova

The Hidden Dangers of Backlog and

How RVI Helps Us See Again

Inspection backlog has quietly become one of the most dangerous normalisations in integrity management. It’s discussed in dashboards, tolerated in reviews, and rationalised as “manageable.” But backlog isn’t just a scheduling issue, it’s a creeping uncertainty that eats away at our confidence in the true condition of our assets.

When inspection or anomaly work is deferred, something subtle but serious happens: we stop knowing, and start assuming.

What Risks Lie in the Backlog

Each item in backlog represents a point of doubt, a gap in our understanding of integrity. It may be an overdue visual, a pending anomaly assessment, or a delayed thickness check. But collectively, these gaps distort how we perceive and prioritise risk.

The hidden dangers are clear:

• High-risk systems remain unseen, while lower-priority scopes consume attention.

• Anomalies age without verification, losing context with each passing month.

• Risk models drift, because they’re fed by outdated or incomplete data.

Deferred Backlog gives us the illusion of control - we can measure it, track it, report on it - yet it quietly hides what we no longer understand. It’s not the list itself that’s dangerous, but the blind spots it represents.

Over time, this acceptance breeds complacency. The more backlog becomes “business as usual,” the more we lose touch

with reality. Deferred inspections turn into forgotten ones. Risks that were once high priority blend into the noise. And that’s how critical issues can hide in plain sight — not through inaction, but through overload.

From Delay to Decision: How RVI Changes the Equation

This is where GDi’s Remote Visual Inspection (RVI) provides genuine relief as a viable inspection method in its own right.

RVI uses structured digital capture - highresolution imagery, spatial mapping, and traceable datasets - to perform complete integrity inspections remotely. The process operates within ISO 17020 inspection standards, ensuring the same level of assurance, documentation, and auditability as any conventional campaign.

At GDi, an Oceaneering Company, RVI is delivered by highly competent OIE-grade inspectors, bringing the same professional rigour and engineering judgement expected in traditional inspection but executed through a digital framework. This allows inspections to be completed, verified, and signed off without delay, maintaining full compliance and traceability.

RVI doesn’t just help us see the backlog, it allows us to resolve it. Each inspection provides a defensible record, enabling engineers to confirm asset condition, close actions, or escalate verified anomalies for further assessment.

The benefits are clear:

• Auditable coverage – every inspection is evidence-based, traceable, and reviewable.

• Scalable execution – inspection activity flexes with operational demand and priority.

• Reduced human error – consistent imagery, digital overlays, and multiple reviewer sign-off improve accuracy.

In short, RVI turns backlog into clarity and clarity into action.

Relieving the Hidden Risk

The most powerful outcome of RVI is the relief it brings to integrity management. It restores understanding where uncertainty has taken hold. It transforms deferred actions into completed inspections. It gives integrity teams a credible, quality-assured route to reduce and sometimes remove backlog altogether.

RVI doesn’t replace inspection; it redefines how it’s delivered. It turns passive backlog into active knowledge, allowing teams to see, assess, and act without delay.

Because backlog isn’t just a list — it’s a risk. And by applying RVI as part of the inspection toolkit, we can finally stop carrying that risk forward and start closing it down. 

GDi, an Oceaneering Company, provides ultra-efficient asset management, engineering and inspection solutions across the energy sector.

www.globaldi.co.uk

Niall Shanks, Integrity Operations Manager

Ambition, Diversification, and Transformation: Powering the UAE’s Energy Future

In the dynamic landscape of global energy, few regions embody the spirit of ambition, diversification, and transformation quite like the United Arab Emirates.

As the UAE accelerates its journey toward a net-zero future, it is redefining its energy identity - balancing its hydrocarbon legacy with bold investments in clean energy, digital innovation, and sustainability. For THREE60 Energy, this evolving ecosystem presents a powerful opportunity to contribute, grow, and lead.

Ambition: A Vision Beyond Oil

Ambition is the spark that ignites progress. In the UAE, that spark has become a flame - one that fuels some of the world’s most forwardlooking energy initiatives. The UAE Energy Strategy 2050 sets out to triple the contribution of renewable energy and invest AED 150 to 200 billion by 2030 to meet increasing demand for energy. This includes investment in energy infrastructure with 25 major projects spanning solar, wind, hydro, nuclear, and waste-to-energy.

The Mohammed bin Rashid Al Maktoum Solar Park, set to reach 7.2 GW by 2030, and the Barakah Nuclear Power Plant, which can supply 25% of the UAE’s electricity, are tangible proof of this ambition. These projects not only reduce emissions but also position the UAE as a global leader in energy innovation.

For THREE60, ambition has always meant doing things positively differently. From our origins in oil and gas, we’ve built a Tier 2 services organisation that delivers engineering, operations, and systems across the full asset lifecycle. Today our ambition is broader, to support the UAE’s evolving energy landscape. We remain committed to advancing oil and gas development while also enabling the transition to new energies, from hydrogen to CCUS, helping our customers navigate both current and future energy needs.

Diversification:

Building Resilience and Opportunity

Diversification is more than a strategy - it’s a necessity. The UAE is actively reshaping its energy mix with solar, wind and nuclear power leading the way. Hydrogen is emerging as a cornerstone of the UAE’s decarbonisation efforts. The Abu Dhabi Hydrogen Alliance drives green hydrogen opportunities and positions the country as a regional hub. Carbon Capture Utilisation and Storage (CCUS) lead by ADNOC is capturing significant amounts of CO₂ annually, contributing to the UAE target of 10 million tonnes by 2030.

At THREE60, diversification has meant expanding our offerings, sectors, and geographies. Today, we operate across six sectors: oil and gas, marine, defence, CCS, nuclear, and wind - with over 1,100 people in 20 locations. This diversity not only spreads business risk but also enables us to bring cross-sector insights to complex energy challenges. Our key operational hubs in the UK, Norway, and Malaysia position us to support clients globally with regional expertise and agile delivery. With our recently established presence in the UAE, it joins the US as a key growth market for the business.

Transformation: Reimagining What’s Possible

Transformation is the natural evolution of ambition and diversification. In the UAE, it’s being driven by digitalisation, AI, and integrated energy systems. Abu Dhabi’s AD.WE platform, powered by AI, is revolutionising energy management - enabling real-time analytics, predictive maintenance, and smarter decision-making.

For THREE60, transformation means embracing digital innovation, agile mindsets, and bold commercial models. Our oil and gas decommissioning journey started small, building trust, and daring to think differently. We co-created new models with clients like bp and Repsol, enabling them to unlock greater value from complex projects in the North Sea and Gulf of America.

Transformation is rarely linear. It requires courage, adaptability, and a willingness to learn from both success and setbacks. At THREE60, we speak of our own 5 step “Hero’s Journey” - from an idea to taking the leap, fighting through the messy middle, persevering through the climb, and onward to impact. Then, we dare to dream again.

Looking Ahead

As the UAE continues to lead the energy transition, the way forward will be shaped by those who embrace ambition, diversification, and transformation. The challenges are real—but so are the opportunities. With the right mindset and partners, we can co-create a future that is cleaner, smarter, and more sustainable.

At THREE60, we’re proud to be part of this journey. And with our new entity and physical presence within Abu Dhabi, we are committed to helping our customers and the UAE power and decarbonise the future. 

minimise downtime and enhance operational efficiency.

With a network of 140 service centres and 1,600 dedicated professionals, we deliver integrated hose management and maintenance solutions that perform in the toughest environments.

From design and installation to testing and maintenance, our comprehensive approach ensures safety, reliability, and efficiency at every stage, powering offshore success, worldwide.

Design. Build. Operate. Grow: Rotech Subsea’s Global Expansion in Motion

In a modern, integrated energy portfolio, maintaining subsea integrity has never been more important to uphold existing infrastructure and drive forward new energy developments.

Building on the momentum of its 30th anniversary celebrations in 2024, the Aberdeen-based business has experienced significant growth over the past two years, with revenue on track to have increased by 90% since 2023.

A contributing factor to this growth has been Rotech’s sustained activity in the Asian offshore wind market. With 7 projects completed to date and several still ongoing, Rotech has completed a variety of scopes across the entire project lifecycle for both global and regional contractors.

In March, Rotech’s equipment quite literally reached new heights when a Boeing 747F was chartered to transport an RS spread directly to Taipei at the request of a major client. Despite alternative solutions being readily available in-country, the client specifically requested Rotech’s proven systems and experienced team to lead the project, a testament to the trust and confidence Rotech’s client base has for its proven reliability and results. From the runway to demobilisation, the project was successfully completed in under 2 weeks.

Prolonged demand in the region has resulted in the promotion of Alasdair Maclean to Country Manager, who has relocated to Taichung to provide a dedicated in-country presence. With no signs of slowing down, the business is continuing to recruit additional onshore personnel to further bolster its in-country team

Speaking on the demand experienced, Maclean said “We started the year with three RS spreads of equipment supporting client scopes in the region. However with demand continuing to grow, we have since mobilised a fourth spread as well as one of our RSG-C grab-cutters to meet the workload.”

Looking ahead, Stephen Cochrane, Director of Subsea and Global Head of Business Development, believes the company’s achievements in Taiwan are laying the groundwork for broader expansion across the APAC region. “The strength of our operations in Taiwan will support our continued growth into the Australian market, particularly as it moves deeper into the decommissioning phase,” he explained. “Our technology and experience are ideally suited to meet those emerging needs.”

Beyond Asia, Rotech Subsea continues to maintain a strong presence in North America despite challenging market conditions. While the US offshore wind sector faces political and regulatory headwinds, demand for Rotech’s solutions has remained constant. This demand spans from required maintenance scopes for already established wind farms, to supporting the continued development of offshore power networks. To meet this demand, a second spread has now been sent to the region, demonstrating the versatility of

both the company’s equipment and its team to support a range of end markets.

At its Aberdeen headquarters, Director of Base Operations Martin Graham described the company’s momentum as strong and sustained. “Normally demand eases off at the tail end of summer, but right now every Rotech spread is booked and busy. The yard looks quite empty because our fleet is out supporting key client scopes worldwide.”

Biding by its mantra ‘Design, Build, Operate’, Rotech is continuing to add to its equipment fleet, which already consists of 32 systems. This will soon increase to 36 as the business builds additional RS2 and RS3 tools to keep up with global demand from its customers. Summing up this customer-centric approach, Managing Director Dr Donald Stewart said “At every stage of the process, Rotech will go out of their way to make sure the client gets the results they are looking for.”

As Rotech begins to look towards 2026, demand across the energy sector remains constant, proven by a solid pipeline of secured work and opportunities. With its growing international team, equipment fleet and proven track record, Rotech continues to build the foundations for continued international growth. 

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Lighthouse AI: Smarter

supply chains start here

Lighthouse AI transforms logistics data into real-time intelligence – leading to tangible and strategic streamlining and optimisation opportunities for your supply chain operations.

Built with operational expertise at its core, Lighthouse has processed 10m tonnes of cargo in 13 years and is now available as a global So ware as a Service solution, ready to deploy in as little as a day.

Discover the value of your data with Lighthouse.

IS TRANSFORMING

At the core of this growth is THOR –our patented Thermal Oil Recovery downhole heater. By applying heat directly into the reservoir, THOR achieves production rates up to 6.5x higher than steam, chemical, or gas injection. The system is maintenance-free, remotely controlled, and cuts emissions by up to 95% compared to steam, removing the need for carbon-heavy surface infrastructure.

CLEANER, FASTER, SMARTER

From Aberdeen to America and the Middle East, Cavitas Energy is redefining heavy oil recovery. Our targeted downhole heating solution overcomes the toughest challenges in heavy oil extraction and flow assurance. What started as a North Sea innovation is now delivering results globally, including for NOCs in Kuwait and operators in Utah.

HEAVY OIL RECOVERY FROM HEAVY OIL TO PROFITABLE RECOVERY.

IN JUST 30 DAYS

In the US, THOR turned a well that even with cable heaters was nonproductive, into generating up to 60 barrels per day, equivalent to $1.7 million in annual revenue with breakeven in just 30 days. This success unlocked a 400 million barrel stranded asset.

400 MILLION BARREL STRANDED ASSET UNLOCKED

Global Growth Through Greener Waste Solutions

Andrew Morris, TWMA Group Commercial Manager

As the global energy sector balances production demands with the need to decarbonise, sustainable offshore operations have become increasingly important. While much focus is on reducing rig emissions and electrifying platforms, drilling waste management is emerging as a key way to lower emissions worldwide.

Every offshore well generates large amounts of waste such as drill cuttings and slops. Traditionally, this waste is shipped to shore for treatment. Although compliant, this approach uses a lot of energy, produces significant carbon emissions, and carries operational risks. Each vessel trip and skip lift adds to emissions and safety concerns. As a result, the industry is searching for better ways to handle drilling waste. Increasingly, waste is viewed not as a costly byproduct but as a chance to improve sustainability.

TWMA leads this change with more than 25 years of experience in transforming drilling waste management. Its international growth is driven by increasing recognition from operators, regulators, and governments that waste management is a critical part of environmental performance.

A core technology enabling this shift is TWMA’s RotoMill®. The system treats drilling waste at the source and recovers oil, water, and solids for reuse or safe disposal. By eliminating the need to transport untreated waste to shore, it cuts logistics-related emissions by up to 90%. With over 100,000 metric tons of drill cuttings processed annually, TWMA’s approach is both scalable and adaptable across global markets.

This adaptability is key to TWMA’s international expansion. The company has entered the Middle East, West Africa, the

Americas, and other regions, tailoring its systems to meet diverse environmental regulations and operational goals. Whether supporting drilling in remote locations or servicing large industrial hubs, TWMA’s technologies help operators reduce costs and emissions simultaneously.

One prime example is TWMA’s projects in Abu Dhabi. There, the company deployed its RotoMill in a pioneering at-source drilling waste solution. To meet zero discharge rules and avoid waste transport, TWMA treated all waste directly at source. The results were impressive. The project recovered more than 420,00 bbls of base oil worth $65 million, diverted over 500,000 metric tons of solids from landfill, and treated more than 1.3m bbl’s of slop. Complete with 6.5 million man hours and no lost time incidents, these projects have set a new standard for sustainable offshore waste management.

Innovation remains central to TWMA’s global success. In 2021, the company restructured its research and development team, bringing engineering and automation expertise inhouse. This led to the RX Series, the next generation of RotoMill technology. The RX1, launched in 2023, introduced enhanced remote accessibility and with the support of AI, a new level of predictive maintenance. RX2, completed in 2025, will be fully electric and emission free further enhancing the value proposition of the technology.

To meet growing demand, TWMA has expanded its services to onshore markets. The upcoming RX3 and RX4 units will be deployed in large-scale land-based treatment projects, in the GCC region. This expansion highlights TWMA’s ability to serve both offshore and onshore sectors.

TWMA’s success is also strengthened by investments in automation and digitalisation. Its XLink platform allows operators to track emissions reductions, monitor equipment performance, and verify sustainability gains in real time. This transparency supports environmental, social, and governance compliance demanded by investors and regulators around the world.

As climate targets tighten and ESG scrutiny grows, drilling waste management is no longer optional. It is essential. With the offshore waste management sector projected to grow by 6% annually over the next decade, demand for sustainable, integrated solutions is rising rapidly.

By focusing on innovation, adapting systems to local needs, and delivering proven environmental benefits, TWMA shows that growth and responsibility can go hand in hand. As operators globally seek ways to reduce impact without sacrificing productivity, greener waste solutions have become a global necessity. 

Saving a million dollars on your next lower completion installation is easy when you add a little magic

Ok, so there is a little more to it than simply waving a magic wand, but the secret to more efficient lower completion deployment is about keeping things simple and utilizing smart technology.

Unquestionably, wells of the future will need to be lower cost to make sustainable business cases in ever more challenging brownfield reservoirs with smaller pockets of recoverable reserves.

In recent years, many operators have reported that the number of engineering hours per well has increased significantly. Compounding the problem is the fact that the cost per engineering hour has also increased in most regions around the world. Add this to the increased cost of completion hardware and it does not make for encouraging reading when reviewing the CAPEX budget for the project.

Thankfully there is a new solution in the completion engineer’s toolbox which is cutting completion time and saving operators millions of dollars. How can this be possible? It’s as simple as disappearing metal, or to be more precise, FADETM engineered dissolvable alloys. It may seem like magic, but behind this miraculous material lies a wealth of very clever engineering and a deep understanding of materials science.

So, what is this wonderous material and how is it used in the completion? The answer to this question will take us deep into the fundamental design principles of

well completion and its interface with the reservoir. We will be unlocking simplicity of well design to increase efficiency, minimize formation damage, increase productivity and reduce well costs.

What is FADETM engineered dissolvable alloy?

FADETM is a family of dissolvable metal alloys which dissolves or degrades when exposed to commonly used wellbore construction fluids. The alloys have been engineered to dissolve in selected fluids in a time-controlled and predictable manner. Marwell have developed a method of using these engineered materials to create a range of plugs which can be incorporated directly into the liner or into inflow control valves, sand control screens, pre-drilled liners, sliding sleeves and a number of other downhole tools.

The dissolvable materials allow for running the lower completion without an inner string as a continuous unperforated liner with pump-through capability. The plugs are then designed to disappear within hours or days when in contact with the appropriate fluid.

Marwell have an in-house laboratory for the design and testing of FADETM material and compatibility

with fluids, where an extensive database has been built up from hundreds of tests. When the FADETM plugs are combined with the TIME toe valve, they create a fully fluid activated washpipefree lower completion system.

Removing the need for washpipe

By utilizing FADETM dissolvable alloy and applying this to radial plugs installed directly into the lower completion, it is possible to create a closed liner system with full pressure integrity and the ability to circulate fluids to the toe and out into the open hole / lower completion annulus.

Having circulation capability while deploying the lower completion can aid in improved installation time and increased safety through better well control options. The FADETM plugs can withstand high temperatures and pressures of over 10,000psi, which provides the operator with the ability to pressurize the entire lower completion and activate liner hanger, mechanical open hole packers and other devices. By removing the need to run washpipe, operators are saving over 24 hours of rig time on most wells.

Enabling placement of breaker fluids

One of the benefits of having pressure integrity of the liner is that fluid trains can be pumped all the way to the toe and up the open hole annulus of the well. This allows for the precise placement of breaker systems and suitable low solids fluids, to aid in filter cake removal and mitigate screen plugging and formation damage. This simple technique is allowing operators to increase productivity from the reservoir, by improving the interface between the sandface and the completion.

Reducing completion time

The use of FADETM allows operators to utilize standard completion equipment and upgrade its functionality into a system which is greater than the sum of its parts. The controlled dissolution of the FADETM plugs provides a predictable operating window for deploying the lower completion, placing fluids in the annulus and then setting hanger and open hole packers. The TIME toe valve then permanently closes the toe (shoe) and the FADETM plugs are dissolved, at which point the well can then be placed on immediate production or injection. This improves deployment time and the cleanup time needed for flow back prior to well handover.

Installing longer lower completions in extreme ERD wells

The high differential pressure capabilities of the plugs make it possible to maintain a buoyant volume in the liner by using air or a lighter density fluid, to float the lower completion / liner into the open hole. This drastically reduces drag and enables longer completions to be run in a single trip.

The benefits of utilizing FADETM engineered dissolvable alloy are numerous and the solution can be tailored to work with many types of completion designs. The result is a simple, flexible and robust system which does not require electronics, timers or pressure pulses to activate it. Marwell’s team of expert completion advisors are helping operators around the world leverage this disruptive technology, realizing significant cost savings and performance gains. Some people say it’s like magic but to us it is the embodiment of our ‘Well-First Thinking’. With clever engineering and a deep understanding of materials science we ‘Marwellize’ lower completion designs. 

Marwell AS - Washpipe-free system with FADE dissolvable plugs and TIME chemically actuated toe valve

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Tenth anniversary marked with leadership evolution

Multi award-winning torque specialist EnerQuip is celebrating its landmark tenth anniversary by announcing a significant evolution in its leadership.

In line with long-term strategic goals and the company’s unrelenting commitment to international operational excellence, Andrew Robins has become Chief Executive Officer with company founder Andrew Polson to remain in the role of Chairman. John Duncan steps into the role of Chief Technical Officer and Iain Frater has joined the business as Chief Operating Officer. Darren Bragg, who relocated to Dubai, UAE in 2023, returns to the UK, to take up a new position of Chief Commercial Officer.

Darren’s regional responsibilities have been taken on by Nick Glennie who has been hired as EnerQuip’s new Abu Dhabi-based regional manager for the Middle East where contracts worth $10m have been secured this year alone. In addition to capital equipment sales, the company is also punching high in maintenance and servicing work, which is proving to be a prime area for growth. Anticipated future strengthening in volume is likely to prompt the need for additional members of staff, including the technical team in the Middle East and further investment in regional resources and inventory.

One star performer in the Middle East is EnerQuip’s revolutionary Mobile Torque Unit (MTU) which performs fully automated rig-side operations and positively disrupts incumbent methods by reducing labour requirements and carbon emissions whilst boosting efficiency and improving safety by reducing hands-on time by 50-60%. Also central to international success for the Aberdeenshire-headquartered business is the flagship Fully Rotational (FR) torque machine which makes up 50% of overseas trade and allows fast, accurate makeup and breakout of premium threaded connections. The business expects a near 100% level of export of product for 2025.

Further boosting growth in the Middle East was the acquisition of the AMC product line from Forum Energy Technologies, taking ownership of the intellectual property, people and assets in a move which further consolidated its market leading position and brought on board additional products which continue to help fulfil adventurous growth plans.

The ambitious company prides itself on delivering flexible solutions backed by the best in the business: the team is light on its feet when it comes to giving customers what they want, where and when they want it –and they’re in increasing demand, not only in the Middle East but in all four corners of the globe. Strategically placed service centres across the globe ensure prime positioning to exceed the expectations of the energy industry in mature and developing markets.

Founded in 2015, privately owned and with its global headquarters in Aberdeenshire, EnerQuip has blossomed from a specialist start-up to an international partner of choice built on knowledge and expertise grown in the North east of Scotland and delivered to the world with passion, skill and commitment. In just ten years, the company has established operations in key global hubs, and its sustainable growth is underpinned by a reputation for technical expertise, service reliability and an unwavering focus on safety and quality.

The company’s global headquarters in Aberdeenshire and Caithness manufacturing facility, supported by worldwide service hubs,

enable 24/7 client support, maintaining existing equipment or delivering new solutions to meet evolving industry regulations.

Commenting on the recent news, Andrew Robins said: “Celebrating ten years of growth and success, and with the business continuing to expand into new markets and consolidate its presence in existing ones, it is important that we redefine our leadership structure to support future growth aspirations.”

“To capitalise on recent momentum, particularly in international markets, we have realigned the team to ensure that we correctly tap into our wealth of individual skills to achieve collective growth as we prepare for the next phase of our corporate journey, as we continue to diversify organically and through acquisition.” 

L-R Iain Frater, Darren Bragg, Andrew Robins, John Duncan

Top 250 oil and gas firms own just 1.5% of the world’s renewable power

Despite public promises by many fossil fuel firms that they are investing in the green transition, it turns out that they have made little contribution to the growth of renewable energy

Leading oil and gas companies own less than 1.5 per cent of the world’s renewable power capacity – raising questions about how committed they are to the green energy transition, despite their public claims.

Marcel Llavero Pasquina and Antonio Bontempi at the Autonomous University of Barcelona looked at ownership records of more than 53,000 wind, solar, hydroelectric and geothermal projects worldwide, as tracked by Global Energy Monitor, a non-governmental organisation. They then cross-checked these to see what proportion of them were owned by the world’s 250 biggest oil and gas companies, which are collectively responsible for 88 per cent of global hydrocarbon output.

Many fossil fuel firms have pledged to invest in renewable energy sources as the world attempts to transition away from oil and gas, but the researchers found that the top firms own just 1.42 per cent of the total operating renewable capacity globally. More than half of that – some 54 per cent – was owned via acquisitions, rather than companies developing their own projects. By calculating the total energy output of the 250 firms, the pair found that renewable power accounts for just 0.13 per cent of the energy produced by these companies.

“The results were surprising, even for me,” says Llavero Pasquina. “I knew they were playing a very little role in the energy transition. I knew it

was only for show. It was only for dressing their narrative. But I didn’t expect this low number.”

Llavero Pasquina and Bontempi are both part of a group called Environmental Justice, which aims to produce research to “study and contribute to the global environmental justice movement”. Llavero Pasquina says his campaigning position strengthens his research. “You have the biggest interest in being as rigorous as possible, because you have to convince and you have to show what’s true.”

The fact that big energy firms, which have made their name and fortunes through oil and gas exploitation, aren’t massive players in renewables is unsurprising, says Thierry Bros at Sciences Po in Paris. “At the end of the day, [the energy transition] has to be something disruptive, and it’s not going to be in the hands of those companies.”

However, Bros does believe the big energy firms are unduly promoting their work on the energy transition. “They are portraying themselves [as] doing something, but I think if they were to do something, it would be more the carbon capture and sequestration,” he says, which involves capturing carbon as it is emitted, for instance when burning fossil fuels. “They are not doing much because I think it’s completely outside their domain of expertise.”

Offshore Energies UK, an industry body that represents the UK’s offshore energy industry, including oil, gas, wind, carbon capture and hydrogen, declined to comment directly on the study’s findings. However, it pointed to a previous statement from its chief executive, David Whitehouse. “Far from being in conflict, oil and gas, wind, and emerging low-carbon technologies are part of one integrated system. It is the skills of our people, the same people who built the North Sea that will deliver this transition,” he said. 

Renewables overtake coal as world’s biggest source of electricity

Renewable energy overtook coal as the world’s leading source of electricity in the first half of this year – a historic first, according to new data from the global energy think tank Ember.

Electricity demand is growing around the world but the growth in solar and wind was so strong it met 100% of the extra electricity demand, even helping drive a slight decline in coal and gas use.

However, Ember says the headlines mask a mixed global picture.

Developing countries, especially China, led the clean energy charge but richer nations including the US and EU relied more than before on planet-warming fossil fuels for electricity generation.

‘Crucial’ turning point

Despite these regional differences, Ember calls this moment a “crucial turning point”.

Ember senior analyst Malgorzata WiatrosMotyka said it

“marks the beginning of a shift where clean power is keeping pace with demand growth”.

Solar power delivered the lion’s share of growth, meeting 83% of the increase in electricity demand. It has now been the largest source of new electricity globally for three years in a row.

Most solar generation (58%) is now in lowerincome countries, many of which have seen explosive growth in recent years.

That’s thanks to spectacular reductions in cost. Solar has seen prices fall a staggering

Turkey Emerges as a Regional Leader in Renewable Energy Expansion

Turkey’s renewable energy sector is booming, bolstering energy security and cutting reliance on imports.

99.9% since 1975 and is now so cheap that large markets for solar can emerge in a country in the space of a single year, especially where grid electricity is expensive and unreliable, says Ember.

Pakistan, for example, imported solar panels capable of generating 17 gigawatts (GW) of solar power in 2024, double the previous year and the equivalent of roughly a third of the country’s current electricity generation capacity.

Africa is also experiencing a solar boom with panel imports up 60% year on year, in the year to June. Coal-heavy South Africa led the way, while Nigeria overtook Egypt into second place with 1.7GW of solar generating capacity –that’s enough to meet the electricity demand of roughly 1.8m homes in Europe.

Some smaller African nations have seen even more rapid growth with Algeria increasing imports 33-fold, Zambia eightfold and Botswana sevenfold.

In some countries the growth of solar has been so rapid it is creating unexpected challenges.

In Afghanistan, widespread use of solarpowered water pumps is lowering the water table, threatening long-term access to groundwater. A study by Dr David Mansfield and satellite data firm Alcis warns that some regions could run dry within five to ten years, endangering millions of livelihoods.

Adair Turner, chair of the UK’s Energy Transitions Commission, says countries in

Aiming for net-zero emissions by 2053, the country has diversified its energy mix since the early 2000s and tripled renewable electricity generation over the past decade. Construction is also underway on Turkey’s first nuclear power plant.

Solar power has been a standout success. Capacity doubled between 2022 and 2024, exceeding the government’s 2025 target, with self-consumption driving most of the growth. Together, solar and wind energy have saved Turkey around $15 billion in natural gas imports. The country’s 33 GW pipeline of

the global “sun belt” and “wind belt” face very different energy challenges.

Sun belt nations – including much of Asia, Africa, and Latin America – need large amounts of electricity for daytime air conditioning. These countries can significantly reduce energy costs almost immediately by adopting solar-based systems, supported by increasingly affordable batteries that store energy from day to night.

Wind belt countries like the UK face tougher obstacles, however. Wind turbine costs have not come down by anything like as much as solar panels – down just a third or so in the last decade. Higher interest rates have also added to borrowing costs and raised the overall price of installing wind farms significantly in the last few years.

Balancing supply is harder too: winter wind lulls can last for weeks, requiring backup power sources that batteries alone can’t provide –making the system more expensive to build and run.

But wherever you are in the world, China’s overwhelming dominance in clean tech industries remains unchallenged, other new data from Ember shows.

In August 2025, its clean tech exports hit a record $20bn, driven by surging sales of electric vehicles (up 26%) and batteries (up 23%). Together, China’s electric vehicles and batteries are now worth more than twice the value of its solar panel exports.. 

storage-integrated projects now far surpasses its 2030 goal, while total renewable capacity reached 74 GW by August.

Wind power attracted $1.3 billion in investment last year, and growth is expected to continue. Meanwhile, the EU has launched a $3.22 million project to boost Turkey’s hydrogen sector. The electric vehicle market is also accelerating — sales tripled in June 2025, and China’s BYD plans a $1 billion manufacturing plant. With strong policies and foreign backing, Turkey’s clean energy transformation is gathering pace. 

Are you the right ‘fit’? Spot the green freeport’s opportunities

In June this year, the Scottish and UK Governments approved the final business case for Inverness and Cromarty Firth Green Freeport (ICFGF), paving the way to unlock up to £25 million of seed funding, which the Freeport and its participants will benefit from.

ICFGF is considered by many to be the most significant opportunity in decades for the Highlands, which opens up possibilities for businesses in the energy sector as well as other markets - to create jobs, reverse the depopulation of the region’s rural communities, and play a role in Scotland and the UK’s journey to net zero through the creation of a renewable energy hub.

The concept of a green freeport is unfamiliar territory for many, so it’s understandable that businesses are asking: “what do the opportunities look like for me?”

The good news is, the opportunities are plenty and the range is vast. Some are obvious, such as the tax driven benefits, but some are less so and arise as a knock-on effect of what others are doing in the Freeport, and the demands that are created in the commercial ecosystem.

In ICFGF itself, the facilitation of offshore wind, floating wind and green hydrogen projects has occupied much of the conversation. The fabrication, assembly and maintenance of offshore structures will require people to carry out these processes, while any plans to house a hydrogen plant at the Freeport –such as The Cromarty Hydrogen Project –will need to be powered by electricity, from whatever source is decided as most suitable.

A strong supply chain will be necessary, both on and off-site. Warehouses, factories and purpose-built yards need to be built,

while materials and equipment will require transportation into and out of, the Freeport.

People will be crucial to initial set-ups and ongoing operations – electricians, builders and the rest of the trades world too, architects, planners, and engineers. Those who specialise in data processing, analysis and reporting will play an important role, as will the marine technology sector. And for all those workforces operating on-site at ICFGF, day-to-day services will be needed - catering, electric vehicle charging stations and bus routes, to name a few.

There will be leasing and sales opportunities too, for land and property near to the Freeport or on the routes that lead to it. Whether it’s available laydown space or use of an outbuilding, businesses will need somewhere to store their tools, equipment, materials and vehicles.

And then there are the ‘less obvious’ opportunities that are on the horizon, arising indirectly from ICFGF becoming operational and attracting more people to the region. Some of that workforce will be temporary or on fixed contracts, others permanent.

What do people require? Somewhere to live or stay. Housing, hotels, guesthouses, bed and breakfasts.

They need services too. Public transport, private transport, tour operators, taxis, car hire, schools, healthcare. And then there are all the

other services and facilities that are needed on a day-to-day basis. Access to sports, leisure, and activities to enjoy during their downtime, food and drink venues, shopping facilities, entertainment… a non-exhaustive list but full of opportunity for the local region.

For businesses who provide a service locally or are considering doing so, here are four points to help you plan:

1. Pay attention to what’s happening at ICFGF to determine whether it impacts your target client base, the timing of launching a new business, or pivoting or expanding an existing service.

2. Identify what is needed to move forward – sourcing investment, seeking legal advice, investigating planning rules and permissions, training employees or hiring more people.

3. Consider how your business, service or product is currently, or can be more, green. Banks and investors are increasingly focused on supporting sustainable ventures that contribute to the UK’s net zero objectives, so be clear in how your business meets, or plans to meet, that criteria.

4. Engage with the right people. The team at ICFGF is supportive of anyone keen to be part of the Freeport’s future. Its innovation and training hub - The Powerhouse - is a good place to start having conversations. 

Are you the right ‘fit’ for the green freeport? Download our guide to identify opportunities for you and your business

Laura Petrie is a partner at Brodies LLP, specialising in the energy sector.

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Fueling the Future: The Rise of Hydrogen Energy

Producing green hydrogen involves using renewable energy to split water into hydrogen and oxygen. The search for sustainable energy sources is more critical than ever, and hydrogen fuel technology is proving to be a real game-changer.

This innovative technology has the potential to revolutionise global energy use. Recent advancements in hydrogen fuel cells, green hydrogen production, and international collaboration have brought about significant economic and environmental benefits.

The Promise of Hydrogen Fuel Cells

Hydrogen fuel cells have advanced greatly in recent years by becoming more efficient and durable. One of the biggest challenges used to be the high cost of platinum, which is needed for catalysts in these cells. However, with new materials reducing our reliance on platinum, fuel cells are becoming more practical for big projects. Ongoing research and development initiatives that would meet the UK R&D tax relief criteria include focusing on lowering production costs and making components reusable, which is driving hydrogen fuel to be a more competitive option compared to traditional energy sources.

Exciting advancements in electrolyser technology have made this process more efficient and less energy-intensive. R&D efforts in novel materials for electrocatalysts are helping reduce energy losses and improve hydrogen production efficiency. The field of biotechnology is also getting involved, with researchers exploring how algae and other bio-organisms can be used to generate hydrogen.

Global Implications for Energy Systems

Hydrogen fuel has the potential to transform various sectors around the world. In transportation, for instance, hydrogen fuel cell vehicles (FCVs) are becoming a major player in reducing emissions. Countries like Japan

Authored by Nikki

and South Korea are leading the charge, and big automakers are investing heavily in these clean-energy vehicles. This shift aligns perfectly with global efforts to combat climate change.

Industrial sectors are also seeing the potential of hydrogen. For instance, industries like steel production and chemical manufacturing are looking at hydrogen as a cleaner alternative to fossil fuels. Hydrogen can replace these fuels in high-temperature processes, significantly cutting down the carbon footprints of these industries and supporting global sustainability goals.

Additionally, hydrogen’s ability to store renewable energy effectively is revolutionising energy storage solutions. By converting excess renewable energy into hydrogen, ongoing research is working on stabilising power grids and ensuring a steady energy supply, even when traditional renewable sources like wind and solar are not producing energy.

Catalysts for Global Growth: International Collaborations and Investments

Around the world, governments are making bold investments in hydrogen technology. The European Union’s Hydrogen Strategy and collaborations between countries like Germany and Australia are perfect examples of this global commitment. These initiatives aim to create strong hydrogen economies and infrastructure.

The private sector is also jumping on board. Major investments from big energy companies and innovative start-ups are driving research and development. These collaborations are crucial for quickly bringing hydrogen technologies to market.

Economic and Environmental Benefits

The hydrogen sector holds the promise of not only cleaner energy but also more jobs. From research and development to manufacturing and infrastructure development, the hydrogen industry can create many new jobs, boosting local economies.

On the environmental front, using hydrogen fuel can significantly reduce greenhouse gas emissions. Predictions show that widespread use of hydrogen could drastically cut emissions, helping us meet international climate goals and creating a cleaner planet.

Furthermore, hydrogen can increase energy security by reducing our dependence on imported fossil fuels. Countries with abundant renewable resources can produce green hydrogen locally, leading to greater energy independence.

Navigating Challenges

However, this bright future for hydrogen comes with some challenges. Building a comprehensive hydrogen infrastructure for production, transportation, and storage is no small feat. Therefore, potential R&D projects such as exploring new storage methods and transportation systems to create a reliable global hydrogen network would potentially qualify for UK R&D tax relief.

Policy support is also critical. To integrate hydrogen into our energy systems smoothly, we need strong, supportive policies and regulatory frameworks. Governments must set international standards and safety protocols to facilitate this transition.

Conclusion:

A Vision for a Sustainable Future

Hydrogen fuel technology has the potential to transform how we consume energy worldwide, bringing substantial economic and environmental benefits. With recent advancements in fuel cells and green hydrogen production, we’re getting closer to making this vision a reality. Continued investment in research and development, supported by international cooperation and solid policy frameworks, is key to unlocking hydrogen’s full potential. By addressing current challenges and leveraging technological advancements, hydrogen can play a crucial role in creating a sustainable and secure energy future for everyone. 

Modare – Assistant Manager

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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.

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.

OSSO is providing its high-capacity mud cooling technology to support a six-well, three-rig drilling campaign, with operations now underway. The technology is designed to address the extreme downhole temperatures common in geothermal operations by actively cooling drilling fluid as it returns

to the surface. This temperature control enhances drilling performance, extends the lifespan of downhole tools, and significantly reduces operational costs. By lowering fluid temperature at the surface, it also reduces heat exposure for rig crews, supporting safer working conditions.

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.”

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

The multi-well, multi-rig campaign further strengthens OSSO’s position in the market and reflects growing activity across Europe. To support this expansion and increasing demand, the company has established a dedicated European entity in Amsterdam. The new base is already providing local servicing and technical support. The Netherlands was strategically chosen for its central location and strong infrastructure, enabling efficient access to key markets and faster mobilisation across the continent. 

Petrofac Secures Two Contract Extensions for North Sea Assets

Petrofac said it has secured a two-year, $50 million contract renewal from Ithaca Energy, extending its work for the oil and gas company in the North Sea.

Under the integrated services contract, Petrofac will continue to provide operations, maintenance, engineering, construction, and onshore and offshore technical expertise, the company said in a news release.

The scope extends across Ithaca Energy’s North Sea operated asset base, which includes Alba, Captain, Erskine and FPF-1, according to the release.

John Pearson, chief operating officer of Petrofac’s asset solutions and energy transition projects said, “The continuation of our longstanding relationship with Ithaca Energy is testament to the safe and reliable delivery of operations services by our team, who have been embedded on these assets for well over a decade. The North Sea is one of Asset Solutions’ core markets and this award underlines the commitment from both Petrofac and Ithaca Energy to the region. We remain focused on supporting Ithaca Energy to maximise safe, efficient and responsible production from its assets”

Also in the North Sea, Petrofac secured a contract extension from Shell UK-operated venture ONEgas West.

TechnipFMC Bags Contract for Newest Stabroek Project

“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

Under the contract, Petrofac will provide services across ONEgas West’s Southern North Sea portfolio, supporting the Clipper South complex, Leman Alpha assets, Bacton Terminal, and OneGas Barge campaigns.

Financial terms of the contract extension were not disclosed.

Pearson said, “Having supported these assets since 2020, Petrofac is embedded within the delivery team and is uniquely placed to support production enhancement and field life extension. The North Sea remains one of Asset Solutions’ core markets and this award demonstrates confidence held in our team and the value they drive. We look forward to continuing this relationship, delivering safe and reliable operations”.

Agreement Reached on Restructuring

Meanwhile, Petrofac said it has reached an agreement in principle with Samsung E&A Ltd. and Saipem SpA regarding their claims relating to the Thai Oil project 

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. 

Able secures decommissioning contracts from Allseas for two TAQA UK platforms

Able has been awarded contracts by leading offshore contractor Allseas to dismantle, reuse and recycle two of the most significant North Sea decommissioning topside projects to date: TAQA UK’s Cormorant Alpha and Tern.

Able will take delivery of the topsides at its Teesside facility, Able Seaton Port (ASP), from 2027 onwards.

Up to 97% of the recovered Northern North Sea topsides’ materials will be reused or recycled, further cementing ASP’s position as an experienced and capable facility for largescale marine decommissioning.

Dismantling of the combined 47 500 t weight of the Cormorant Alpha and Tern topsides will also generate substantial economic activity and long-term employment opportunities across Teesside.

Lance Taylor, Able Group Chief Executive Officer, says: “These decommissioning contract awards from Allseas for TAQA UK’s Tern and Cormorant Alpha topsides are a defining moment for Able Seaton Port and for UK decommissioning. They reflect the trust placed in us by Allseas to deliver on these significant projects for TAQA.

“We continue to invest millions of pounds into extending our capabilities – from building new quays to expanding infrastructure –ensuring we can handle larger and more

complex projects in parallel. As a result, we are actively positioning ourselves to deliver more contracts, support more jobs and strengthen Teesside’s role at the centre of the global decommissioning industry.”

Allseas’ Vice President Projects, Matthijs Groenewegen, says: “This award marks another milestone in our collaboration with Able. Projects such as Tern and Cormorant Alpha showcase the strength of our singlelift removal technology, while Able’s proven expertise ensures these major topsides are safely and responsibly recycled, reflecting our shared commitment to sustainable North Sea decommissioning operations.”

TAQA UK Managing Director, Sandy Hutchison says: “TAQA UK’s asset-wide decommissioning programme positions us a leader in safe, efficient, late-life asset management and decommissioning in the UK. By working closely with Allseas, we’re pleased that our Cormorant Alpha and Tern topsides will be taken to a UK facility owned by Able Group for dismantling, reflecting our continued commitment to delivering lasting value to the UK’s energy sector and local communities.”

Pauline Innes, Director of Supply Chain and Decommissioning at the North Sea Transition Authority, says: “We very much welcome substantial decommissioning contracts being awarded to UK facilities. This is in line with the North Sea Transition Deal, in which the UK’s oil and gas industry pledged to support the country’s suppliers by giving them a fair share of decommissioning work, and we hope to see further onshore dismantling work being entrusted to the UK’s highly skilled supply chain.”

Decommissioning

of one of the largest UK southern North Sea gas fields has reached a new milestone.

Removing and transporting structures from the Hewett gas field in the UK southern North Sea has reached the halfway point in a multiyear project.

Offshore contractor Scaldis SMC has removed three platforms from the abandoned field in block 48/29 and delivered them to a recycling yard in the Netherlands. It has another three to complete, scheduled for 2026, for the full abandonment of the Hewett field.

Scaldis successfully delivered the 48/29C jacket from the Hewett field to the quayside in Vlissingen at the start of October after its removal in September by a heavy-lift vessel.

Gulliver lifted the topsides from the 48/29B and 48/29C platforms and returned to lift the 12-piled 48/29B jacket and 48/29C jacket in a Q3 2025 campaign, transporting them to Vlissingen.

“With the safe removal and transport of this structure, the project has now reached its halfway point,” said Scaldis in a social media post. “To date, three abandoned platforms have been dismantled and removed. The remaining three platforms, forming together the central complex, are scheduled for removal next year, bringing the project to full completion.”

Eni’s Hewett decommissioning programme is an engineering, preparation, removal and disposal contract.

Heavy- lift vessel Gulliver will soon set course for the Baltic Sea to execute two additional projects before the end of Q4 2025.

In Q2 and Q3 2025, Scaldis vessels installed platforms for offshore windfarms in the North Sea. The steel jacket and topsides for the Thor offshore windfarm, located in the Danish sector of the North Sea off the west coast of Jutland, were installed under a subcontract from HSM Offshore Energy in August.

Scaldis also worked with DEME to install the offshore substation for the Treport windfarm, off Dieppe, France.

New guidance targets soaring oil and gas well decommissioning costs

Energy companies have been urged to follow new guidance to speed up the rollout of improved technologies for decommissioning oil and gas wells.

Launched by the Net Zero Technology Centre (NZTC) in partnership with engineering consultancy Astrimar, the framework comes as the UK and other countries ramp up efforts to cut costs and reduce the environmental impact of ageing energy assets.

The Aberdeen-based centre said the current pace of deployment “remains incredibly slow” as the scale of the challenge grows.

NZTC and Astrimar have set out a clear, evidencebased process to assess whether materials can safely and permanently seal wells that are no longer in use. Well abandonment is one of the most costly aspects of decommissioning.

The six-step framework supports safe and confident use through a structured qualification process – the first guidance focused specifically on well plug and abandonment (P&A).

It helps users identify risks, build a strong evidence base, and streamline approvals to accelerate the safe deployment of new solutions.

Around 2,000 wells in the North Sea alone are expected to shut down over the next decade. The aim is to reduce costs for both operators and taxpayers, with public funding supporting decommissioning through tax reliefs.

Other countries, including the US, Norway and Australia, are also tackling rising costs and environmental issues related to well decommissioning across their energy sectors as part of their transitions.

More than 14,000 unplugged non-producing wells remain in the Gulf of Mexico, while around 7,000 wells across Asia Pacific are due for decommissioning by 2030.

Australia faces a major offshore oil and gas decommissioning challenge, with costs estimated at US$40.5 billion over the next 50 years. This covers more than 1,000 wells as well as related infrastructure, highlighting the scale of the task.

Long-term safety and environmental protection are critical as the industry moves away from traditional cement-based barriers.

New technologies using low melting point alloys, resins, polymers and epoxies are emerging, but face challenges demonstrating their effectiveness and reliability.

The framework also reflects input from operators, regulators and technology developers, and draws on international guidelines and standards such as DNV RP A203 and API RP 17Q, which are widely used across the energy sector.

It stems from NZTC’s Wells Decommissioning Collaboration, which aims to speed up testing and adoption of P&A technologies with a goal to cut costs by 35 per cent and halve emissions by 2035.

NZTC and its partners encourage companies to apply the framework to help speed the safe deployment of new solutions.

Lewis Harper, programme manager at NZTC, said:

“Well decommissioning is an increasingly urgent global issue as maturing basins seek ways to cut costs, reduce emissions and improve efficiency.

“The only way to achieve that is through new technology, but the pace of developing and deploying new solutions remains incredibly slow.

“This guidance will help speed up the safe adoption of innovative technologies, giving operators and regulators the confidence to move faster.

“By managing performance to stringent standards, the adoption of new materials should become easier and more reliable.

“Created with input from operators, regulators and industry experts, the guidance shows the strength of our partnership approach.

“It ensures solutions meet everyone’s needs and supports faster and safer adoption.

“This framework gives the industry the tools to tackle well decommissioning challenges with greater confidence.” 

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Building Trust in International Markets:

How ATPI’s People-First Duty of Care Approach Gives Companies the Confidence to Deploy Staff

Safely Across Borders

Successful

international expansion depends on one crucial factor: the ability to move people confidently and safely across borders. In today’s complex geopolitical environment, ensuring that employees can travel and work securely is essential for sustaining global growth.

ATPI’s people-first duty of care approach gives organisations the confidence to deploy teams worldwide, even in challenging markets such as the Middle East. With safety, wellbeing, and support embedded into every aspect of travel management, ATPI empowers companies to focus on growth while knowing their people are protected.

A People-First Approach to Global Mobility

At the heart of ATPI’s global success lies its commitment to people. Whether deploying engineers to remote energy sites or coordinating large-scale crew rotations across continents, the company’s top priority is always the safety, wellbeing, and efficiency of travellers.

For ATPI, duty of care isn’t a policy — it’s a mindset. Every travel request, decision, and communication is guided by a proactive approach to risk management and traveller support. By combining risk intelligence, travel management, and local assistance, ATPI ensures that every traveller is informed, protected, and connected, no matter where their journey takes them.

This integrated model not only reduces risk exposure but also builds long-term trust between ATPI and its clients, giving organisations the assurance they need to expand confidently into high-growth, high-potential regions.

Global Reach, Local Expertise

ATPI’s global presence is underpinned by teams on the ground in every energy major region. This structure allows the company to deliver real-time updates, instant crisis response, and 24/7 in-house support, thus ensuring that operations continue seamlessly, even in the most challenging circumstances.

The ability to mobilise teams quickly, share intelligence instantly, and coordinate centrally gives clients peace of mind that their people, and their business are in safe hands.

Strength in Partnership: A Strategic Presence in Saudi Arabia

A cornerstone of ATPI’s Middle East operations is its joint venture in Saudi Arabia, which provides unrivalled local expertise and operational agility. This partnership strengthens ATPI’s ability to navigate the region’s evolving regulatory landscape, manage complex cross-border movements, and offer in-person support when it matters most.

For clients, it translates into smoother operations, faster response times, and trusted local insight, which provides critical advantages when doing business in a dynamic and rapidly growing market.

Confidence to Expand, Backed by Care

As organisations continue to pursue opportunities in emerging and high-growth markets, having a trusted global travel partner that prioritises people above all else has never been more vital.

ATPI’s people-first duty of care approach is more than a promise, it’s a proven strategy that enables companies to operate globally with confidence, knowing that their most important asset, their people, are supported every step of the way.

Case Study: Navigating Complex Crew Mobilisation Amid Airspace Disruptions

When sudden airspace closures in the Middle East disrupted commercial flight paths, ATPI faced the challenge of rerouting 120 crew members travelling between Erbil and Sulaymaniyah in Northern Iraq, ensuring safety and minimal delays.

With volatile airspace conditions, ATPI swiftly executed and coordinated a mobilisation plan. Mardin Airport in Turkey was designated as an alternate hub, supported by cross-border ground transfers and customs coordination. Manual hotel bookings, tailored catering, and bank transfer payments were managed precisely. Crews received layover support in Istanbul, while dynamic monitoring ensured rapid response to flight changes.

As a result, ATPI safely rerouted all 120 crew members, maintaining 100% invoice accuracy, and achieving zero escalation requirements. The operation demonstrated exceptional teamwork, precision, and resilience under pressure, earning high praise from the client’s Iraq-based teams.

Delivering Confidence Through Experience

This case underscores how ATPI’s global reach, local expertise, and people-first philosophy combine to deliver real-world results. From proactive crisis management to 24/7 operational support, ATPI empowers organisations to send their teams anywhere in the world with complete confidence.

In markets like the Middle East where success depends on agility, reliability, and trust, ATPI stands as a partner that not only moves people safely but keeps businesses moving forward. 

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

Zara Higgins, General Manager Saudi Arabia / Head of Energy – Arjaa ATPI

Ideally Positioned

Based in the Dubai Multi Commodities Centre (DMCC), our Middle East branch subsidiary gives us the opportunity to offer an unrivalled rental service offering.

Our range of equipment located within the UAE includes:

- 93kW Diesel Power Pack - Rigsafe

- 57kW Diesel Power Pack - ATEX Zone 2

- 45kW Electric Power Pack - ATEX Zone 1

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