Aus Issue 3 - International Growth_issuu by OGV Energy

PROSERV EXPANDS DOWN UNDER: SHOWCASING COMPREHENSIVE CONTROLS TECHNOLOGY & SERVICE EXCELLENCE ACROSS THE AUSTRALIAN MARKET. READ ON PAGE 4

GLOBAL ENERGY NEWS ENERGY PROJECTS MAP INTERNATIONAL GROWTH LEGAL INNOVATION CONTRACT AWARDS DECOMMISSIONING EVENTS

Headquartered in Perth, Australia since 2017, our growth and advisory services help organisations to design and execute growth plans, develop capable leadership teams and deliver exceptional outcomes for shareholders. .

Our international expansion offering has been designed speciﬁcally for UK businesses looking to establish themselves in Australia.

We have a proven track record of supporting UK companies with their entry into the local market, allowing them to capitalise on growth opportunities in the energy, renewables and decommissioning sectors across the Asia Paciﬁc region.

Talk to our team to ﬁnd out how we can help you unlock growth opportunities and Unveil your potential:

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Welcome to the second issue of the OGV Energy Australia Magazine on the theme of ‘International Growth’

At the time of creating this issue, OGV Group PTY Ltd will be in its fourth month of operation. In this relatively short time, it’s been an honour to see the company gain steady recognition in the market and to have met so many wonderful professionals throughout all areas of the industry. Our mission is to continue to deliver the latest news and insights from the energy sector as well as provide opportunities for all levels of the industry to network and collaborate from a local to global scale.

A special thank you to our cover feature Proserv for allowing us the exclusive deep dive into their new innovative product: the IWOCS (Intervention Workover Control Systems). In line with their current OCH technology, Luke Wassel - Regional Director APAC - demonstrates how this new capability is providing solutions to challenges faced from aging subsea infrastructure and how this is already aiding in the energy transition goals across Australia and APAC regions. For more, please turn to our feature article on page 4.

We are delighted to showcase contributions in this month’s edition from Three60 Energy and Rotech Subsea plus much more.

A new edition to this issue is a comprehensive review of the Mining sector around the region as well as in-depth coverage of the energy sectors across APAC, Australia, the UK and Europe, the Middle East and the USA.

You’ll also find insightful articles from Brodies LLP and Leyton, as well as updated industry analysis and project updates from Westwood Global Energy Group and the EIC.

We hope you are inspired and informed from our third issue of OGV Energy Australia!

Proserv: Driving Sustainable Growth in Asia-Pacific Through Technological Innovation

In the dynamic world of subsea technology, Proserv has continually proven its ability to adapt and thrive by addressing the critical challenges faced by operators. With a focus on extending the life of existing assets, transitioning to cleaner energy, and supporting greenfield developments, the company is making waves in the Asia-Pacific region, particularly in Australia.

Regional Director Luke Wassell, who has been instrumental in Proserv’s strategic expansion in Asia-Pacific, underscores the importance of the Australian market.

“The operators in this region are navigating a unique set of challenges,” Wassell explains.

“Aging subsea infrastructure, insulation resistance issues, and the overarching goal of transitioning to sustainable energy sources all demand innovative, reliable solutions.

Proserv’s bespoke technologies—such as the Open Communications Hub (OCH)—are perfectly suited to address these needs.”

Solutions Tailored for Regional Challenges

Proserv’s technologies have already begun to make a significant impact in Australia. The OCH, for instance, is enabling operators to enhance the performance of aging assets

by providing an alternative communication solution that seamlessly integrates with existing infrastructure. This technology also supports third-party instrumentation, ensuring operators have flexibility without the need for costly overhauls.

“Our OCH has been a game-changer for operators dealing with insulation resistance issues and subsea erosion,” says Luke Wassell, “By integrating OCH into their subsea architecture, operators can extend asset life, maintain production, and reduce downtime.”

Additionally, Proserv’s recently delivered battery backup systems in Australia, another component of the OCH, ensure uninterrupted communication and production even when insulation resistance challenges arise. This capability exemplifies Proserv’s commitment to providing solutions that offer both reliability and economic efficiency.

A Global Reputation for Excellence

While Proserv’s technologies are tailored for the Australian market, their global reputation for reliability and innovation cannot be overstated. The company’s IWOCS solutions are particularly noteworthy, addressing a broad spectrum of requirements, from greenfield development to plug-and-abandon (P&A) activities.

Crawford Tennant, a key advocate for Proserv’s IWOCS (Intervention Workover Control Systems) capabilities. “ Proserv’s IWOCS equipment sets the industry standard for performance and dependability. With our equipment now being stored in region, operators in Australia can benefit from quicker access, streamlined maintenance, and robust support. It’s a pivotal move that underscores Proserv’s dedication to the region.”

Empowering Sustainable Transitions

Beyond subsea controls, Proserv’s commitment to sustainability is evident in its ACT (Augmented Control Technology) offerings, which have been deployed globally

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COMMUNITY news

Motive cements APAC presence with six figure investment in Singapore facility

New quayside facility brings advanced cable handling and deployment equipment to the region.

Motive Offshore Group (Motive) announces investment of a six-figure sum into its newly acquired facility in Singapore, part of Motive’s strategic integration of Aquatic and its assets since acquiring the company in 2024.

A leading provider of rental, inspection, and engineering services for the energy sector, the investment solidifies Motive’s on-the-ground presence in APAC, following the opening of its first regional facility in Taiwan in 2021.

The Singapore facility represents a major milestone in Motive’s growth strategy, bringing advanced cable handling and deployment equipment to the region and positioning the company to better serve clients facing increasingly challenging deep-water environments. 

Shangari steps up to global sales role at pipeline technology specialist STATS Group

Pipeline technology specialist STATS Group has appointed Vikas Shangari as Global Sales Director after an extensive global recruitment process.

Mr Shangari will lead STATS’ global sales strategy across all of the group’s nine international locations, spanning the Middle East, North America, APAC, the UK, and Europe.

He joined STATS in 2011 as Country Manager in Qatar and over the past 14 years has played a pivotal role in growing STATS’ reputation and geographic footprint in the Middle East.

STATS Group Chief Executive Officer, Stephen Rawlinson, said: “Vikas is synonymous with proven sales success, starting out more than a decade ago at STATS in Qatar, where he helped build a fledging project-specific business into the multifaceted and productive business it is today. 

Global Gravity welcome new General manager to the team.

We are excited to announce that Timothy Gay is joining our team as General Manager, Middle East.

Tim has many years of experience in both Logistics and Oil & Gas Operations both in the Middle East and worldwide and has used TubeLock® for several years. He will be able to advise you of many of the economical and operational advantages of using TubeLock® in your offshore operation.

Tim said “I am delighted to be joining Global Gravity in the Middle East and look forward to supporting our existing and potential new clients with our TubeLock® systems which in my opinion are a game changer for the industry bringing significant safety, cost and operational benefits for offshore operators”. 

Team upskilling for CMMS success partnering with a UK Oil & Gas operator

Following a transition from their legacy CMMS, our client wanted to ensure users were proficient in their new system to maximise operational efficiency and minimise downtime during the transition phase.

The course is designed to provide fundamental upskilling on how to effectively use the new CMMS for both offshore and onshore teams. It covers the essential features, functionalities and best practices to ensure smooth implementation and efficient maintenance management, helping the client to:

• Build confidence and competence across offshore and onshore teams

• Standardise data entry and work order practices

• Strengthen understanding of how CMMS data drives performance.

This project is a great example of how strategic upskilling can boost system adoption and unlock long-term value from a new CMMS. 

Decom Engineering secures over £2m in international contracts to start 2025

Scottish subsea cutting specialist Decom Engineering has secured more than £2 million worth of international contracts in the first quarter of 2025.

The Portlethen-based firm provides a range of cold cuttings ‘chopsaws’ which can operate in harsh offshore and subsea environments.

Decom Engineering said the three contract wins in the Americas, Nigeria and Australia will position the company for further international growth.

Among the contract wins, Decom Engineering secured a chain cutting scope in the Gulf of Mexico which will see it deploy its ultra-light C1-16 chopsaw to cut mooring chains.

Meanwhile, a Decom team is preparing to mobilise on a 300-day campaign offshore Brazil involving two C1-16s. 

MCC announce strategic collaboration with Ward Advisory.

We are proud to announce a strategic collaboration between MCC and Ward Advisory. This alliance unites MCC’s technical expertise in sustainability and emissions advisory with Ward’s strength in corporate ESG strategy and investment decision-making.

Together, we will support businesses in navigating ESG risks and opportunities, sustainability strategy development and reporting, netzero transition, new energy, and responsible investment strategies—ensuring alignment with evolving regulatory frameworks and market expectations. Whether it’s optimising sustainable supply chains, integrating low-carbon solutions, or developing climate resilience strategies, our combined expertise ensures impact-driven and commercially viable outcomes.. 

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Australia Energy Review

By Tsvetana Paraskova

The latest report is consistent with previous calls for new investment in gas as supply from the gas fields in Bass Strait deplete, AEMO chief executive Daniel Westerman said.

Australia Needs

More Investment in Gas Despite Renewables Boom

Australia needs more investment in natural gas supply to avert a supply crunch later this decade, the energy market operator said in its most recent assessment.

Production from the Longford Gas Plant, which has historically supplied two-thirds of the gas used in the East Coast Gas Market, will reduce before retiring at the end of 2033, according to AEMO.

Natural gas consumption is expected to decline with the switching from gas to electricity in the residential, commercial, and industrial sectors.

However, the risk of peak-day shortfalls and seasonal supply gaps in the southern states is expected to arise from 2028, with annual supply gaps emerging from 2029, AEMO said.

“New investment is needed to deal with structural supply risks from 2029 to maintain supply to homes and businesses including for gas-powered electricity generation,” the market operator noted.

In response to the report, the Australian Energy Producers association commented that GSOO “reaffirms the need for governments to fasttrack new gas supply, amid an improved supply-demand outlook that defers forecast seasonal and structural shortfalls by a year.”

The report showed that there was no room for complacency if the east coast is to avoid shortfalls, as AEMO found that ‘all scenarios identify the need for new supply investments to maintain supply adequacy’.

“The GSOO makes clear that governments and regulators must work with industry to remove regulatory barriers to new gas supply and investment to avoid shortfalls,” said Samantha McCulloch, chief executive of Australian Energy Producers.

“While 2028 may seem a long way away, the long lead time for major energy projects means governments need to act now to ensure Australian homes and businesses continue to have reliable and affordable energy,” McCulloch added.

Renewable energy installations are rebounding and reaching all-time highs, but natural gas supply, which will continue to play a major role in Australia’s energy system for decades, needs to rise, the market operator and oil and gas industry executives say.

More Investment Needed to Fill Expected Gas Supply Gaps

The annual Gas Statement of Opportunities (GSOO) report by the Australian Energy Market Operator (AEMO) showed the need for new investment in Australia’s central and east coast gas markets to address forecast supply shortfalls in the southern states.

Developed with updated inputs from industry, the GSOO is one of AEMO’s gas planning and forecasting reports that provide technical insights to support investors and governments in making informed decisions to benefit consumers.

From 2028, seasonal supply gaps may emerge in southern Australia if conditions lead to sustained high gas usage, while expanded production of uncertain supply will be needed to meet domestic and export positions in northern Australia.

Various options are being considered by the gas industry, including new supply, transportation and storage projects, and LNG regasification terminals. Australia will likely need a combination of solutions to supply and deliver enough gas to where it is needed in the longer term, AEMO said.

As Australia transitions to a net zero emissions future, gas will continue to be used by Australian households, businesses and industry, and support the reliability and security of the electricity sector.

“Flexible gas-powered generation will remain the ultimate backstop in a high-renewable power system,” Westerman said.

“Gas, alongside batteries and pumped hydro, will enable higher renewable penetration and support reliability as coal-fired power stations retire.”

Major industry players also noted the need for sufficient reliable gas supply to Australia’s domestic market.

ExxonMobil in 2024 completed the transformation of the Gippsland Basin Joint Venture from an oil and gas business to a gas business and will ensure the production system delivers the reliability the customers expect, David Berman, ExxonMobil Australia Commercial Director, said at the 2025 Australia Domestic Gas Outlook Conference in Sydney in early April.

At the gas development, fourth-quarter 2024 production was equal to the average of the previous 5 years and 6 percent higher than the fourth quarter of 2023, Berman said.

Majors Call for Policy Reforms

Despite a consensus on the problem with domestic gas supply and its causes, “there is less alignment on how to reclaim the investment certainty that is required to secure the capital to produce the energy Australia needs,” Exxon’s executive noted.

MINING Review

By Tsvetana Paraskova

Australia’s mining industry saw a decline in mineral exploration expenditure at the end of 2024 amid caution and uncertainty from companies about new project investments.

The Association of Mining and Exploration Companies (AMEC) calls for more support for minerals exploration in Australia such as the government extending the Junior Minerals Exploration Incentive (JMEI) after the allocation expired in 2024 for the 2024-25 financial year.

This incentive encouraged investment in small minerals exploration companies that carry out greenfields mineral exploration in Australia. Eligible exploration companies would generate tax credits by choosing to give up a portion of their losses from greenfields mineral exploration expenditure.

However, this scheme reached its conclusion, when the final year of allocations were awarded to companies in June 2024 for 2024-2025.

During the election campaign ahead of the general election in Australia, AMEC called for the JMEI to be extended, which will need a new funding commitment.

Australia’s Mineral Exploration Expenditure Drops

Quarterly mineral exploration expenditure for the December quarter showed that mineral exploration remained constrained, recording a 2.4 percent drop in original terms to AU$992.3 million, compared to the September quarter 2024.

The data, released by the Australian Bureau of Statistics (ABS), reveals annual expenditure for the 2024 calendar year at AU$3.95 billion, down by 7.3 percent on the previous 12 months, despite a stronger second half of the year.

and all jurisdictions to meet global demand and energy transition objectives.”

Boost for Australia’s Critical Minerals Amid Tariff Chaos

The Australian Senate passed in February the Critical Minerals Production Tax Incentive (CMPTI), which AMEC welcomed as “a monumental moment” for Australia. The incentive provides a strong and clear endorsement of the importance the critical minerals sector plays now and will play well into the future.

This is the first time any Australian Government has put their money where their mouth is for the critical minerals industry

In the December quarter, expenditure on both new (greenfields) deposits and brownfields exploration dropped.

“The minerals exploration industry in Australia has endured another challenging quarter. Despite a strong end to the calendar year, activity was down on the September and previous December quarters,” commented AMEC Chief Executive Officer, Warren Pearce, said.

“Particularly concerning is the continuing drop in expenditure and drilling on greenfields deposits, pointing towards a level of caution and uncertainty around market sentiment for – and investments in – new projects,” Pearce added.

“This comes at a time when Australia should be ramping up activity across all commodities

“This is the first time any Australian Government has put their money where their mouth is for the critical minerals industry,” AMEC’s Pearce said.

“This will stimulate billions in new investment in critical minerals processing, which will be far more valuable than the incentives on offer.”

AMEC will be working with Treasury and the Australian Tax Office, to ensure the actual details of this new policy works for everyone.

“Australia has a lot to thank our traditional resources sector for, now and in the past. By backing the critical minerals needed for our future, be it renewables or defence, we are also lifting the entire economy,” Pearce noted.

AMEC, however, criticised the Federal Budget 2025-26 unveiled at the end of March as a “missed an opportunity to demonstrate support for the minerals exploration industry.”

AMEC has been calling on the Australian Government to extend the Junior Minerals Exploration Incentive (JMEI) after it reached its conclusion, when the final year of allocations were awarded to companies in June 2024 for the FY 2024-25.

For the programme to continue a new funding commitment will need to be made during the election campaign ahead of the May 3 vote.

“We are expecting that both major parties will address measures in the upcoming election to support the exploration sector in Australia, because without exploration you can’t find the mines of the future,” AMEC’s Pearce said.

“The JMEI is a proven program that supports junior exploration companies and is a substantial contributor to Australia’s economy and government revenue.”

“You can’t have a mining boom or downstream processing, if you don’t make the discoveries in the first place.”

An Economic Impact Assessment Report on the JMEI, commissioned by AMEC and released earlier this year, found the JMEI has stimulated AU$404 million in greenfield exploration activity since 2017, at a cost to taxpayers of AU$182.2 million in credits.

“Every dollar allocated results in more than $2 spent on exploration activity and more than $6 is raised on capital markets by companies,” Pearce said.

“The JMEI is a critical investment in Australia’s future and is needed to support mineral exploration – a long-term, high-risk activity.”

In early April, and in response to US President Donald Trump’s planned – now suspended –tariffs, AMEC welcomed the intention of the Federal Government to establish a Critical Minerals Strategic Reserve.

In critical minerals, Australia has a strong hand to play in negotiations with the US, and a ‘Critical Minerals Strategic Reserve’ “could be a very clever way of positioning ourselves in these strategic conversations,” AMEC said.

A potential strategic reserve for critical minerals could further incentivise critical minerals exploration and production in Australia. It could also create a strategic stockpile that provides Australia greater resilience against global trade measures, and greater influence over these critical mineral supply chains, the association said.

The Albanese government wants to incentivise not only mining but also processing of critical minerals, so that Australia will “not just be a quarry for our partners,” senior Labor sources told the ABC.

In response to calls for Australia to return fire with tariffs of our own, AMEC does not support such measures.

“The Prime Minister is right not to escalate this any further, knowing that Australia is a nation that benefits from and champions free trade. Australia is an exporting nation. We don’t stand to benefit from adding further fuel to the fire by imposing reciprocal tariffs,” the association said.

Some Australian states have already pledged state funding support for critical mineral exploration programmes.

New South Wales, for example, announced in early April the launch of a new AU$2.5 million co-investment seed funding program to unearth the state’s next major critical minerals projects.

The $2.5 million fund requires a 50% coinvestment from successful applicants and will encourage more exploration in the state, supporting companies to undertake drilling, geophysics and geochemistry, all crucial

steps to determine the scale of a critical minerals deposit.

The new Critical Minerals Exploration Program is a key part of the government’s Critical Minerals and High-Tech Metals Strategy and highlights its commitment to an industry which provides high-quality jobs in regional NSW and mines the materials needed to build the net-zero future.

“If we can get it right at the ground level, New South Wales can position itself as a major player in the critical minerals space,” AMEC’s Pearce said. 

APAC Energy Review

By Tsvetana Paraskova

Southeast Asia has emerged as a promising province of revival of offshore oil and gas exploration and has recently seen several large deals among international majors to work together in the basin.

Southeast Asia is close to the biggest oil and gas demand centres among the emerging economies – China and India – and can offer a lot to operators willing to bet on an oil and gas renaissance in the region, analysts say.

On the other hand, Southeast Asia is expected to be one of the biggest engines of energy demand growth globally over the next decade, according to the International Energy Agency (IEA).

Southeast Asia Gas Potential

Offshore gas production in Southeast Asia could unlock a $100 billion potential, driven by a flurry of planned final investment decisions (FIDs) expected to materialise by 2028, Rystad Energy said in a 2024 analysis.

This would be more than double the $45 billion worth of developments that reached FID from 2014 to 2023 and signals a surge for the region’s offshore gas industry, the independent research and energy intelligence company said.

The upcoming period of rapid growth is bolstered by deepwater projects, recent discoveries in Indonesia and Malaysia, and positive carbon capture and storage (CCS) advancements, which will be crucial in meeting the region’s sanctioning agenda in the years ahead.

By 2028, oil and gas majors are expected to drive 25 percent of these planned investments through 2028, while national oil companies (NOCs) will account for a 31-percent share. Notably, East Asia’s upstream companies are emerging with a 15-percent share and show potential for growth through their focus on mergers and acquisition (M&A) opportunities and upcoming exploration ventures. The role of majors could further expand to 27 percent, following TotalEnergies’ substantial acquisition efforts in Malaysia, Rystad Energy’s analysts reckon.

X“We recognize the potential of new project investments and capital commitments in the region, which surged from $9.5 billion in 20222023 to approximately $30 billion in 202425,” said Prateek Pandey, Vice President of Upstream Research, Rystad Energy.

“Recent discoveries and the involvement of NOCs will play a vital role in this growth, particularly in deepwater developments, which are pivotal in determining how much of this anticipated $100 billion boom can be realized,” Pandey added.

“We've identified options to add 250550 million new recoverable barrels that can be developed and produced over Johan Castberg.”

In Southeast Asia, governments have recently turned their focus on energy security amid soaring gas demand and dwindling production, analysts at Wood Mackenzie said last year.

“Rising LNG imports have refocused attention on Southeast Asia’s domestic upstream sectors. Governments have set their sights on attracting investment and rebooting exploration – fiscal terms have been improved and exploration acreage aggressively marketed,” WoodMac noted.

At the end of 2024, TotalEnergies finalised the acquisition of the interests of OMV (50 percent) and Sapura Upstream Assets (50 percent) in SapuraOMV Upstream (SapuraOMV), an independent gas producer in Malaysia.

The acquired assets have production costs below $5 per boe and an overall emission intensity below 10 kg CO2e per boe, TotalEnergies said.

The revival has already manifested in more exploration efforts in the region. For example, the number of exploration wells in Indonesia and Malaysia has doubled since 2021, and 2023 delivered Southeast Asia’s best results in over a decade, including several significant finds, WoodMac’s experts said.

A total of 20 discoveries in Malaysia from 25 wildcats is a remarkable success rate, adding over 1 billion boe of greenfield resource. Together with Eni’s 650-million boe Geng North and Harbour Energy’s 580-million boe Layaran gas finds in Indonesia, these discoveries catapulted the region’s deepwater sector towards the top of WoodMac’s scoreboard, together with global E&A hotspots like Guyana and Namibia.

“After years in the doldrums, Southeast Asia’s upstream sector is finally enjoying a renaissance. So far so good. But for the region to make a significant dent on its rising LNG imports, that momentum must be maintained,” WoodMac’s research team said.

Majors Boost Activity in Southeast Asia

International majors and NOCs are busy in Southeast Asia’s offshore sector.

Italian energy major Eni and Malaysian state oil and gas firm PETRONAS in February agreed to discuss a joint venture that would combine and oversee some of their upstream assets in Malaysia and Indonesia.

“Both companies believe that this joint venture will create significant opportunities for growth, both in Malaysia and Indonesia, and is expected to generate substantial synergies towards becoming a major LNG player in the region, while delivering in the medium term a sustainable 500 kboepd production,” Eni said.

“The joint venture will combine approximately 3 billion barrels of oil equivalent (boe) of reserves with an additional 10 billion boe of potential exploration upside.”

The future joint venture is planned to focus on investments in new gas development projects, reflecting the companies’ commitment to energy transition and supporting the increasing regional domestic gas demand.

Separately, PETRONAS has just launched an Integrated Basin Study to explore untapped resources in the Malay Basin, located off the coast of Peninsular Malaysia.

Since the 1970s, the Malay Basin has produced over nine billion barrels of oil equivalent, earning its status as a “super basin”, PETRONAS said, adding that recent exploration activities have uncovered significant new discoveries. Beyond hydrocarbons, the basin presents substantial opportunities for Carbon Capture and Storage (CCS), positioning it as a key player in sustainable energy development, according to the Malaysian national oil and gas firm.

The Integrated Basin Study uses advanced 4D modelling and machine learning technologies to analyse the subsurface architecture at both basin and reservoir scales.

PETRONAS will look to raise Malaysia’s oil and gas production to 2 million barrels of oil equivalent per day (boepd) through 2027, it said in its Activity Outlook 2025-2027.

As of 2024, Malaysia’s oil and gas output averaged 1.7 million boepd.

The increase in hydrocarbon production is expected to come from key development projects including Kasawari, the GumusutKakap Redevelopment, Bekok Oil Redevelopment, Tabu Redevelopment, and Seligi Redevelopment.

PETRONAS plans 69 development wells for 2025, up from 56 development wells in 2024. To ensure optimal production from producing fields and facilities, approximately 367 Facilities Improvement Plans (FIPs) are planned annually for the next three years, the company said.

In addition, PETRONAS expects to drill about 15 exploration wells each year over the next two years. The exploration efforts will focus on both shallow water wells and deepwater wells.

Southeast Asia Becomes Key Energy Growth Driver

Southeast Asia will be one of the world’s largest growth drivers of energy demand over the next decade as its rapid economic, population, and manufacturing expansions drive up consumption, the IEA said in a report in October 2024.

Based on today’s policy settings, the agency has estimated that Southeast Asia is on track to account for 25 percent of global energy demand growth by 2035, second only to India, and more than double the region’s share of growth since 2010. By 2050, energy demand in Southeast Asia is expected to overtake that of the European Union.

Energy growth will be led by a surge in electricity consumption, according to the IEA. Electricity demand in Southeast Asia is set to rise at an annual rate of 4 percent, as growing use of air conditioning amid more frequent heatwaves would be a big driver of higher electricity consumption. Clean energy sources such as wind and solar, alongside modern bioenergy and geothermal, are projected to meet more than a third of the growth in energy demand in the region by 2035.

“Countries in the region have a diverse mix of energy sources including highly competitive renewables. But clean energy technologies are not expanding quickly enough and the continued heavy reliance on fossil fuel imports is leaving countries highly exposed to future risks,” said IEA Executive Director Fatih Birol.

“Southeast Asia has made great progress on issues such as energy access, clean cooking and developing clean energy manufacturing, but now it must ramp up efforts to deploy those technologies at home,” Birol added.

“Access to finance and investment for the region’s fast-growing economies will play a pivotal role in strengthening their energy security and delivering on their emissions reduction goals.” 

UK North Sea Energy Review

By Tsvetana Paraskova

The implications of the Chancellor’s Spring Statement on the energy industry, the sentiment in the supply chain industry, and mergers and acquisitions were the highlights in the UK North Sea oil and gas industry in the past few weeks.

Offshore Energies

UK, the leading trade body representing more than 400 firms across the UK’s energy mix, responded to the Chancellor’s Spring Statement as it continues to campaign for a homegrown energy future that unlocks growth while safeguarding energy security, jobs, and communities.

“Energy security is national security and key to growth. In an increasingly volatile world, the widening gap between the energy we produce and what we import matters,” Whitehouse added.

“Producing our own domestic oil and gas alongside accelerating homegrown offshore wind, carbon capture and hydrogen pays UK taxes, supports jobs and retains the supply chains we need to build our energy future.”

The Spring Statement was published days after OEUK’s Business Outlook 2025 report, which showed that UK energy reserves could cut imports and boost growth.

Under the right business conditions half of the 13-15 billion barrels of oil and gas the UK is projected to need by 2050 could be produced at home, the report found. This would add up to £150 billion of gross value to the UK economy on top of the £200 billion from planned production, safeguarding energy security, jobs, and lower carbon emissions alongside an acceleration of renewables.

“We heard the Chancellor underline the need for all parts of the economy to drive growth. With the right policies in place to attract investment, the UK offshore energies sector and its highly skilled people can help deliver this opportunity,” said OEUK Chief Executive David Whitehouse.

The independent Climate Change Committee has estimated that the UK requires 13-15 billion barrels of oil and gas by 2050, the target date for the economy to achieve net zero. The UK is on track to produce 4 billion of these barrels. But the report finds with the right policies to encourage firms to invest, another 3 billion barrels could be produced at home to meet half of the UK’s needs rather than increasing its reliance on imports.

By 2050, when UK electricity demand is expected to more than double, oil and gas will still form a fifth of UK energy needs, according to the report.

“The future of the North Sea is in our hands. Our report shows as we work together to accelerate renewables the UK must make the most of its own oil and gas – or choose to increase reliance on imports,” OEUK’s Whitehouse commented.

OEUK has also published its 2025 Supply Chain report, which found that without a pipeline of domestic UK projects enabled by pragmatic policy, a sentiment survey reveals nine companies out of every 10 see more attractive opportunities to grow their business overseas due to uncertainty and a less positive business environment at home. Low revenues from renewables and declining investor confidence are key barriers the supply chain industry faces in the UK right now, according to the report.

The government and industry could take several key steps to anchor world class offshore energy companies in the UK. These include industry initiatives aimed at fostering better collaboration across the supply chain, as well as moves to ensure that the government champions the UK energy supply chain capability in offshore wind, hydrogen, and carbon capture and storage (CCS).

“The UK is competing internationally for energy investment so it’s concerning that many offshore energy supply chain firms see more attractive opportunities to grow their business overseas,” Katy Heidenreich, OEUK’s supply chain and people director, said.

“To grow the whole UK’s economy, we need energy policy that supports continued investment in homegrown oil and gas alongside an acceleration of renewable energy.”

Around 60 percent of companies surveyed for the report are diversifying into offshore wind, hydrogen, and carbon capture and storage. However, business revenues from renewables and CCS still represent a relatively low proportion as they make up between zero and a fifth of their turnover, Heidenreich said.

“It’s good to export our expertise but that should never come at a cost to work we need to get done in the UK,” Heidenreich noted.

The North Sea Transition Taskforce, backed by the British Chambers of Commerce, said in a report that the UK government needs to replace the current Energy Profits Levy on North Sea oil and gas operations as soon as practically possible and not wait until the sunset clause of the tax regime expires in 2030.

Waiting until the sunset clause expires in 2030, as suggested by the HMT consultation, is to wait too long.

“Central to this should be a replacement of the Energy Profits Levy as soon as is practicable by a new regime that is proportionate and adjustable in predictable ways in response to changes in the price of oil and gas,” the taskforce said in the report.

“Waiting until the sunset clause expires in 2030, as suggested by the HMT consultation, is to wait too long. Though the intent of the consultation appears to be positive, HMT should recognise that the current tax puts the industry in the UK at a competitive disadvantage and is throttling investment.”

In company news, NEO Energy has announced a strategic merger with Repsol Resources UK, creating a leading independent producer in the North Sea.

Under the terms of the deal, the combined business will be jointly owned by NEO (55 percent) and Repsol UK (45 percent) and have a large and diverse asset portfolio which is expected to generate material cash flows and provide a platform for organic and inorganic growth. Repsol will retain US$1.8 billion of the decommissioning liabilities related to its legacy assets, enhancing the cash flows of the combined business.

The combined group will be renamed NEO NEXT Energy Limited and is expected to become one of the largest producers in the region. Completion of the transaction remains subject to approvals from the relevant authorities and regulatory consents and is expected during the third quarter of 2025.

In another M&A transaction, UK independent production and growth company, Ithaca Energy, has signed a sale and purchase agreement to acquire the entire issued share capital of JAPEX UK E&P Limited (JUK) from Japan Petroleum Exploration Co. Ltd for an enterprise value of US$193 million based on an effective date of 1 January 2024.

JUK holds a 15-percent working interest in the Seagull oil field in the UK North Sea. The transaction, which is subject to the satisfaction of certain conditions including regulatory approval, will increase Ithaca Energy’s working interest in Seagull from 35 percent to 50 percent, equalling bp’s interest as the field operator. The Seagull oil field in the UK Central North Sea, with over 300 mmboe in place, is a high margin producing field, developed as a subsea tie back to the bp-operated central processing facility (CPF) of the Eastern Trough Area Project (ETAP).

The deal to buy JUK is in line with Ithaca Energy’s strategy to pursue valueaccretive mergers and acquisitions (M&A), adding high-quality assets in its core UK Continental Shelf market.

THREE60 and COMS Energy have announced a strategic alliance aimed at delivering industry-leading pre-commissioning, commissioning, and completions services. This initial three-year agreement will cover the oil and gas upstream, midstream, and downstream sectors, as well as energy transition industries.

The companies will partner to use the combined experience and capabilities. THREE60 have a successful track record in providing commissioning services to oil and gas

customers in UK, Africa, and the Middle East, while COMS Energy, through its parent company, provides a strong track record of delivery and growth in the highly regulated nuclear industry.

Peterson Energy Logistics has secured a contract to provide a comprehensive suite of services to support Spirit Energy’s operations across the North Sea and East Irish Sea. Peterson will deliver a range of work including technology, cargo operations, warehousing, quayside services and road transport until end of field life.

Imrandd, a data specialist and engineering consultancy, has successfully renewed its contract with Apache North Sea. This renewal extends Imrandd’s ongoing provision of integrity data analytics and onshore integrity engineering support across all seven of Apache’s North Sea assets.

In addition to maintaining the integrity of the topsides pressure systems equipment for Apache’s offshore assets, the contract has also expanded to pipeline capability including the provision of a senior pipelines engineer. This enhances Imrandd’s scope of work to deliver its advanced data-driven integrity management solutions across both topsides and subsea infrastructure.

Petrofac’s Asset Solutions division has been awarded a collection of scope expansions and new contracts in the first quarter of 2025, totalling US$500 million.

The awards – which realise growth in Asset Solutions’ core markets and target growth geographies, including the UK, Europe, Middle East, Africa, Asia Pacific, and US – span latelife asset management, decommissioning, and integrated services. 

USA Energy Review

By Tsvetana Paraskova

The US oil and gas industry welcomed many of the Trump Administration’s energy policies such as unlocking Alaska’s resources and new Gulf of America lease sales. However, executives in the anonymous Dallas Fed Energy Survey did not spare criticism of the uncertainty the new administration brings to the industry with its trade policies and desire to have oil prices around $50 per barrel.

Dallas Fed Energy Survey Shows Uncertainty Rises

Oil and gas activity in the Eleventh District— Texas, southern New Mexico, and northern Louisiana—rose slightly in the first quarter of 2025, according to oil and gas executives responding to the quarterly Dallas Fed Energy Survey.

The business activity index, the survey’s broadest measure of the conditions energy firms face in the Eleventh District, remained in positive territory but declined slightly from 6.0 in the fourth quarter 2024 to 3.8 in the first quarter.

The company outlook declined by 12 points to -4.9, suggesting slight pessimism among firms. At the same time, the outlook uncertainty index jumped by 21 points to 43.1.

For the entire sample of companies surveyed, firms need $65 per barrel WTI oil price on average to profitably drill a new well, higher than the $64-per-barrel price when this question was asked in last year’s first-quarter survey.

capital of our business, with public energy stocks down significantly more than oil prices over the last two months,” an executive at an exploration and production firm said in comments to the survey.

“This uncertainty is being caused by the conflicting messages coming from the new administration. There cannot be "U.S. energy dominance" and $50 per barrel oil; those two statements are contradictory,” the executive noted.

At $50-per-barrel oil, we will see U.S. oil production start to decline immediately and likely significantly (1 million barrels per day plus within a couple quarters).

“At $50-per-barrel oil, we will see U.S. oil production start to decline immediately and likely significantly (1 million barrels per day plus within a couple quarters). This is not “energy dominance.” The U.S. oil cost curve is in a different place than it was five years ago; $70 per barrel is the new $50 per barrel.”

Across regions, average breakeven prices to profitably drill range from $61 to $70 per barrel. Breakeven prices in the Permian Basin average $65 per barrel, unchanged from last year.

However, in early April, the WTI oil prices crashed to $60 per barrel in a market selloff triggered by the Trump Administration’s tariffs and the OPEC+ group’s plans to increase supply from May by more than expected.

Executives in the survey had already expressed in March concerns about how low oil prices would affect US drilling activity and production levels.

“The key word to describe 2025 so far is “uncertainty” and as a public company, our investors hate uncertainty. This has led to a marked increase in the implied cost of

Another executive was even more critical, saying that “The administration's chaos is a disaster for the commodity markets. "Drill, baby, drill" is nothing short of a myth and populist rallying cry. Tariff policy is impossible for us to predict and doesn't have a clear goal. We want more stability.”

A third E&P executive chimed in with “The threat of $50 oil prices by the administration has caused our firm to reduce its 2025 and 2026 capital expenditures.”

Added the executive, “Drill, baby, drill" does not work with $50 per barrel oil. Rigs will get dropped, employment in the oil industry will decrease, and U.S. oil production will decline as it did during COVID-19.”

Executives also pointed to the increased uncertainty around tariffs and steel product prices, which severely restricts producers’ ability to plan operations for any meaningful amount of time in the future.

Middle East Energy Review

By Tsvetana Paraskova

So OPEC+ producers “reaffirm commitment to market stability on healthier oil market outlook and adjust production upward,” OPEC said.

Lower-than-expected production from the US could help the Middle Eastern oil producers regain some market share with the supply increase they plan for May, analysts say.

The surprise production increase from the OPEC+ group and the efforts by the biggest national oil companies to diversify featured in the Middle East’s energy industry in the past month.

“In view of the continuing healthy market fundamentals and the positive market outlook,” the countries will raise their total production by 411,000 bpd in May. The increase for the month of May is equivalent to three monthly increments—comprising the increase of 138,000 bpd originally planned for May in addition to two monthly increments.

“The gradual increases may be paused or reversed subject to evolving market conditions. This flexibility will allow the group to continue to support oil market stability. The eight OPEC+ countries also noted that this measure will provide an opportunity for the participating countries to accelerate their compensation,” OPEC said.

The eight OPEC+ countries will now hold monthly meetings to review market conditions, conformity, and compensation. The eight countries decided to meet again on 5 May to decide on June production levels.

The OPEC+ announcement came hours after US President Donald Trump announced tariffs on nearly every country on what he described as “liberation day” for America on April 2. Since then, the White House has announced a 90-day pause on most tariffs, with the exception of China, on which the tariffs were raised to more than 100 percent.

OPEC+ To Raise Oil Supply More than Expected

The countries of the OPEC+ alliance that have been cutting oil production by a total of 2.2 million barrels per day (bpd) announced in early April that they would continue to ease these cuts in May. Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, and Oman reviewed during an online meeting the global market conditions and outlook and concluded that the oil market outlook is healthier and warrants a production increase.

The double whammy of tariff-fuelled recession fears and concerns about oversupply from the OPEC+ production hike crushed oil prices in the first half of April. Brent oil prices crashed to the low $60s per barrel, losing about 15 percent in the first ten days of April.

The decline in oil prices could put US oil production gains in jeopardy as the price of the US benchmark WTI crude oil slumped to below the levels that producers believe are enough to profitably drill a new well. In the Dallas Fed Energy Survey for the first quarter, producers in Texas, Louisiana, and New Mexico indicated that they need an average $65 per barrel price to profitably drill a new well.

On the other hand, oil prices in the low $60s are not enough to plug the budget deficits the top Middle Eastern oil-producing countries are running this year. Saudi Arabia, for example, needs oil prices at about $90 a barrel to balance its budget.

“While OPEC+ said the supply increase is due to a more positive outlook, it seems there is more behind this move,” Warren Patterson, Head of Commodities Strategy at ING, wrote in an analysis in early April.

“US President Trump is taking a more hawkish view towards Iran and Venezuela with stricter sanctions. OPEC+ might feel that this provides it with the opportunity to increase supply. OPEC+ might see this as an opportunity to boost supply, especially after Trump announced secondary tariffs for buyers of Venezuelan oil and threatened similar measures for buyers of Iranian and, potentially, Russian oil,” Patterson added.

“Finally, there are also suggestions that the group decided to increase supply to punish members who have been consistently producing above their production targets,” according to the commodities strategist.

Saudi Arabia Cuts Oil Prices to Asia

Days after OPEC+ announced a production hike for May, the leader of the group and the world’s largest crude oil exporter, Saudi Arabia, slashed the price of its oil loading for Asia in May to the lowest premium over regional benchmarks in nearly four years. The Saudi cut of $2.30 per barrel for the Arab Light grade loading in May for Asia was the steepest drop in the premium over the Oman/ Dubai average in two years. Arab Light in Asia will now sell at a premium of $1.20 per barrel over the Dubai/Oman benchmark, off which Middle Eastern producers price their crude going to Asia.

The steep drop in Saudi pricing, which is typically closely followed by other Middle Eastern exporters, increased speculation among analysts that Saudi Arabia is intent on regaining market share amid low prices.

Middle East NOCs Announce Diversification Moves

While oil markets are in turmoil, the largest national oil companies (NOCs) of the top Middle Eastern producers announced several major deals and milestones in carbon capture, hydrogen, and petrochemicals.

Saudi Aramco has launched the Kingdom’s first CO2 Direct Air Capture (DAC) test unit, capable of removing 12 tonnes of carbon dioxide per year from the atmosphere. The pilot plant is developed in collaboration with Siemens Energy and represents a significant step in Aramco’s efforts to expand on its DAC capabilities.

through the capture and storage of carbon dioxide. BHIG is expected to commence commercial operations to produce blue hydrogen in coordination with Aramco’s carbon capture and storage (CCS) activities in Jubail.

Saudi Aramco and the biggest Chinese refiner Sinopec signed an agreement for a planned petrochemical expansion at the Yanbu Aramco Sinopec Refining Company (Yasref) refining complex in Yanbu, on the west coast of Saudi Arabia.

The planned Yasref expansion aligns with our downstream strategy to unlock the full potential of our resources, including converting up to four million barrels per day of crude oil into petrochemicals by 2030

Aramco will look to achieve cost reductions that could help accelerate the deployment of DAC technologies in the region. Aramco and Siemens Energy intend to continue working closely together with the aim of scaling up the technology, potentially laying the foundations for large-scale DAC facilities in the future, the Saudi oil giant said.

Aramco has also completed the acquisition of a 50-percent equity interest in the Jubailbased Blue Hydrogen Industrial Gases Company (BHIG). The agreement brings together experts in their respective fields with the aim of providing the Jubail Industrial City area with hydrogen, including lower-carbon hydrogen, at scale.

BHIG targets the production of hydrogen, including lower-carbon hydrogen from natural gas, also referred to as “blue hydrogen”,

The agreement for petrochemical expansion comes as both Aramco and Sinopec look to diversify the use of crude oil into the production of petrochemicals. Demand

for petrochemicals will continue to drive oil demand, while transportation fuel demand has started to level off in many major markets, including China.

“The planned Yasref expansion aligns with our downstream strategy to unlock the full potential of our resources, including converting up to four million barrels per day of crude oil into petrochemicals by 2030,” said Mohammed Y. Al Qahtani, Aramco Downstream President.

Sinopec President, Zhao Dong, commented,

“The Yasref expansion project represents a significant milestone in our bilateral partnership, ushering in a new phase of deeper and more far-reaching collaboration. We expect the Yasref expansion project to unlock new dimensions of collaborative potential as we navigate the energy transition.” 

WANG GUOZHANG/FOR CHINA DAILY

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

Energy Firms Vie for International Growth

By Tsvetana Paraskova

Major oil and gas companies are looking to expand their operations to the world’s most promising basins as energy investments are rising and demand for hydrocarbons and electricity is growing with the advance of AI and data centres.

International oil and gas majors are moving to explore prospects offshore Namibia, Guyana, and Suriname, while the national oil companies in the Middle East are looking to establish a presence in the growing global LNG market and low-carbon projects.

Operators Prefer Low-Cost Exploration and Development

Outside frontier plays in which few companies are present, oil and gas exploration and production (E&P) firms focus their drilling and exploration efforts on areas adjacent to operating fields, platforms, and other infrastructure, to take advantage of lower development costs for tie-back fields.

E&P operators are prioritizing low-risk, low-cost near field or infrastructure-led exploration (ILX) prospects instead of expensive, high-risk exploration plays, independent research firm Rystad Energy says.

As price volatility, growing sustainability pressures and rigorous capital discipline take center stage, Rystad Energy predicts little growth of exploration budgets this year, standing at around $50 billion.

Indonesia, the US, and Norway will emerge as ILX hotspots in 2025, according to the company’s analysis.

“The global industry downturn, paired with emissions regulations, high costs and scarce frontier exploration prospects, have created an unfavorable environment for greenfield exploration,” said Aatisha Mahajan, Vice President, Exploration Research, at Rystad Energy.

“The surge in ILX activity reflects a strategic push for cost-effective resource recovery, signaling a dynamic year ahead for near-field exploration.”

Unlike greenfield projects that require significant capital for standalone infrastructure, ILX benefits from lower development costs, shorter lead times, and reduced emissions, the research firm said in its analysis published in April.

So far, this strategy has been a success, and nearly 900 ILX wildcat wells were drilled in the last five years. The exploration success rate over this period was at 42 percent, significantly exceeding the total global exploration success rate of 32 percent, according to Rystad Energy.

“With strong success rates and substantial resource additions, ILX drilling is vital for sustaining production and maximizing infrastructure use,” Rystad Energy’s Mahajan said.

“As the industry adapts, ILX remains a key driver of upstream exploration, enhancing efficiency and unlocking new reserves.”

Of the 100 ILX wells planned for 2025, Southeast Asia is set to witness the highest activity, followed by Western Europe and North America. In Southeast Asia, ILX drilling is spread across four countries –Indonesia, Malaysia, Vietnam, and Thailand – spanning 15 distinct basins, highlighting the region’s diverse ILX opportunities.

In Western Europe, ILX activity is concentrated entirely in Norway. Meanwhile, the deepwater region of the US Gulf of Mexico is expected to be a major ILX hotspot in 2025, according to Rystad Energy.

UK-Australia Subsea Collaboration

In a boost to international subsea cooperation, the UK’s Global Underwater Hub (GUH) and Subsea Innovation Cluster Australia (SICA) signed in April a Memorandum of Understanding to work together to grow the subsea sector in both hemispheres.

GUH, the trade and development body which represents the UK’s £9.2 billion underwater industry, has joined forces with SICA – a membership organisation of companies in the Australian subsea industry – to foster innovation, collaboration, and growth among companies and organisations in the subsea sector in the UK and Australia.

Under the agreement, the organisations will actively promote opportunities for their subsea supply chains in both countries and support each other’s members in entering their respective markets.

They also pledged to share market intelligence and learnings around diversification strategies, particularly in energy transition and defence, including the security and protection of critical underwater infrastructure.

Facilitating collaboration will be a top priority and will be supported by the establishment of partnership innovation programmes between UK and Australian firms to develop and implement technology suitable for both regions, GUH said.

“Australia has a broad conventional energy mix with strong ambitions towards net zero, powered by carbon capture and a growing pipeline of offshore wind projects in both the West and South East Australian regions,” GUH chief executive, Neil Gordon, said.

“Crucially, and similar to the UK, Australia champions a just transition which builds in energy resiliency and security with opportunities in sustained oil and gas production, decommissioning, offshore wind and carbon capture. Supply chain companies are encouraged to bring innovative, collaborative and sustainable solutions to this diversified market.”

Colin McIvor, SICA Cluster Manager, commented on the agreement,

“Both organisations bring unique strengths: SICA’s agility and cross-sector innovation focus and GUH’s depth of experience and established global networks. By sharing these, we can deliver real impact for established and emerging industries and accelerate significant growth for both countries.”

Australian Oil and Gas Firms Expand International Footprint

Woodside and Santos, two of the biggest Australian oil and gas companies, have recently announced successful project developments outside Australia.

In the middle of 2024, Woodside achieved first oil from the Sangomar field offshore Senegal, marking the safe delivery of the country’s first-ever offshore oil project.

The Sangomar Field Development Phase 1 is a deepwater project including a standalone floating production storage and offloading (FPSO) facility with a nameplate capacity of 100,000 barrels/day, and subsea infrastructure that is designed to allow subsequent development phases.

Woodside reported this year addition to its reserves, driven by strong performance at Sangomar, successful FIDs of projects in Australia and the US, and performancebased revisions across the portfolio, notably North West Shelf and Bass Strait.

Early performance from the Sangomar reservoirs has demonstrated excellent productivity, which has resulted in proved and proved plus probable reserves additions of 16.2 MMboe and 15.4 MMboe, respectively.

The Sangomar project is forecast to continue producing on plateau into the second quarter of 2025, approximately a year after first oil. Future development decisions will be informed by 12-24 months of production data, Woodside said in February 2025.

The company also completed last year a $1.2 billion deal to buy struggling U.S. firm Tellurian and its U.S. Gulf Coast project Driftwood. Woodside has renamed the Driftwood LNG development opportunity Woodside Louisiana LNG.

In early April, Woodside entered into a binding agreement with infrastructure investment firm Stonepeak for the sale of a 40% interest in Louisiana LNG Infrastructure LLC. Under the deal, Stonepeak will provide $5.7 billion towards the expected capital expenditure for the foundation development of the LNG export facility.

“The transaction significantly reduces Woodside’s capital expenditure profile and is a material step towards readiness for a final investment decision,” the Australian company said.

“This transaction further confirms Louisiana LNG’s position as a globally attractive investment set to deliver long-term value to our shareholders. It is the result of a highly competitive process that attracted leading global counterparties and significantly reduces Woodside’s capital expenditure for this world-class project,” Woodside CEO Meg O’Neill commented.

Santos, for its part, announced in March an oil discovery on Alaska’s North Slope from the Sockeye-2 exploration well in the Lagniappe area east of Prudhoe Bay. Santos holds a 25 percent stake in the joint venture with APA Corporation (50 percent) and Lagniappe Alaska, LLC (25 percent). The exploration well cost is carried by APA as part of a 2023 farm-in agreement.

Apart from the discovery, Santos announced that it is now 80 percent complete at its Pikka phase 1 project in Alaska.

“Pipeline installation is progressing well and set to be completed in two winter seasons, putting us in a good position to pursue acceleration to first oil around the end of 2025,” said Bruce Dingeman, Santos Executive Vice President and President Alaska.

“This will be dependent on logistics and weather allowing for the mobilisation of key production models by barge up the Hay River. Until we have more certainty, guidance remains unchanged with first oil in mid2026,” Dingeman added. 

THREE60 Energy: Accelerating Global Growth with a Focus on Decommissioning

THREE60 Energy is a leading solutions company specialising in engineering, operations and systems across the asset life cycle in the energy sector.

Headquartered in Aberdeen, UK, the company also has regional headquarters in Kuala Lumpur, Malaysia, Houston, USA and Stavanger, Norway. With a strong global presence, THREE60 employees over 1,100 staff across more than 20 sites worldwide. THREE60 has amassed decades of experience in offshore energy operations, covering everything from subsurface activities to drilling, wells, and topside operations and maintenance. Recently, they have established complementary subsea and product solutions service lines, bolstering their full lifecycle capabilities.

The company continues to project a strong trajectory of international expansion, driven by strategic vision and a commitment to delivering innovative solutions, worldwide. Central to this strategy is the company’s focus on emerging markets and global energy transition initiatives.

Gillian King, THREE60’s Group Strategic Growth Director, will represent the business at D&A AUS in Perth, Australia on the 10th & 11th June 2025, highlighting the company’s intent to build lasting partnerships in Australia, an identified area of growth for

THREE60. With a growing portfolio of aging offshore assets and a regulatory push for timely decommissioning, Australia presents substantial opportunities for service providers with proven expertise. The Australian Government estimates that offshore decommissioning will require approximately AUD 60 billion over the next 50 years—a reflection of the scale and urgency of the challenge.

“Australia’s energy landscape is evolving quickly,” said Gillian. “As the country balances conventional resource development with its net-zero ambitions, there’s an increasing need for expert-led, safe, and efficient decommissioning solutions. This aligns perfectly with THREE60’s unique approach and global expertise.”

THREE60 has already established itself as a trusted decommissioning partner across the UK Continental Shelf (UKCS) and beyond. With a flexible, menu-driven service model, the company offers everything from discrete consultancy to full-scope project delivery—covering subsurface, wells, pipelines, topsides, and infrastructure removal. Their proven Integrated Services Provider (ISP) model bundles services into streamlined packages simplifying operations, and enhancing cost certainty. Australia’s regulator, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA), has launched a five-year Decommissioning Compliance Strategy (2024–2029), further underlining the importance of timely, safe,

As decommissioning becomes a more prominent component of the global energy lifecycle, THREE60 is helping operators navigate complex projects with clarity and control. Their fully outsourced operating models allow clients to reduce overheads while focusing on core operations—a model that has already delivered measurable value. A recent North Sea project saw THREE60 deliver a 30% cost reduction while managing all aspects of duty holder operations, decommissioning, and support services. Beyond technical capabilities, THREE60’s international expansion has been built on solid foundations. The company has established entities across Europe, Southeast Asia, and the Americas, with a recent focus on the Middle East. Under the leadership of CEO Walter Thain, THREE60 has seen a 24% increase in revenue and a 26% rise in profitability, reflecting its ability to scale services in diverse markets.

Australia’s broader net-zero commitment by 2050, supported by its target of a 43% emissions reduction by 2050, further reinforces the need for responsible decommissioning and energy transition services. THREE60’s attendance at D&A AUS reflects a deepening commitment to this future.

“Decommissioning isn’t just about removing infrastructure, it’s about doing it smarter, safer, and more sustainably,” added Gillian. “At THREE60, we pride ourselves on partnering with clients to deliver solutions that make a real difference.”

As the global energy sector transitions, THREE60 is ready to support the industry’s changing needs, helping clients reduce

EnerQuip on track for $10 million quarter after global uptick in landmark year

Multi award-winning torque specialist EnerQuip has kicked off its landmark anniversary year by achieving record levels of new business worth $10 million in the current quarter as it prepares to surpass ambitious growth targets.

During the first three months of the company’s tenth anniversary year, the Aberdeenshire-based company has achieved new contract awards valued at $10 million with almost half of that figure coming from activity in January alone. The numbers double the firm’s previous best three-month period for capital equipment sales, with recent capital sales including four Mobile Torque Units (MTUs) to Abu Dhabi as investment in people and facilities in the region continues to pay dividends.

Other Middle East work has also been forthcoming from Saudi Arabia in the early part of 2025, along with the company’s firstever contract in Turkmenistan. Elsewhere, contracts in the likes of Norway, Brazil and India have further demonstrated the reach of EnerQuip’s expansive geographic footprint, and solid customer relationships.

Making up a substantial portion of the overall figure, the company’s maintenance and servicing work is proving to be a prime area for growth and is already valued at more than $1 million per month in new awards. Anticipated future growth in volume is likely to prompt the need for additional members of staff, including a 50% increase in the size of the technical team in the Middle East.

EnerQuip had previously set its sights on a “25 by 25” goal, aiming to hit $25 million turnover by 2025, but achieved the milestone two years earlier than planned. The focus has now turned to uplevelling the same goal

towards achieving £25 million turnover this year with the busy first quarter setting the company on a solid path towards realising the revised ambition.

Managing Director, Andrew Robins said: “A patient and strategic approach has enabled us to create sustainable growth and adopting a global vision from the start has ensured that we have correctly positioned the company to capitalise on opportunities, wherever they may be.

“EnerQuip started in a downturn meaning that the company learned the resilience needed to withstand many and varied challenges throughout our ten years in business, but our ability to overcome allows us to face the future with confidence and optimism as we welcome the next chapter in the EnerQuip story.”

Commenting on the contract awards in Q1, Darren Bragg , Head of Sales – Global, who relocated to the United Arab Emirates in 2023 said: “The real strength of the first three months of the year has been testament to the investment made in the Middle East region. Our Mobile Torque Unit (MTU) equipment has continued to be in high demand in the UAE, and countries such as KSA continue to be strong markets for EnerQuip. Recently it was estimated the global market for torque equipment and services is estimated at $75 million per year. This year we are aiming to break the £25 million barrier, which would make EnerQuip a near $33m business and demonstrably a true market leader which is testament to the hard work of all the team.” 

Valaris Lands $135 Million Drillship Contract in West Africa

Valaris Limited announced that it has been awarded a five-well contract offshore West Africa for drillship VALARIS DS-15.

Offshore drilling contractor Valaris Limited has secured a significant new contract for its high-specification drillship, VALARIS DS-15, marking a strategic win in the competitive deepwater exploration sector. The five-well contract, awarded for work offshore West Africa, is expected to commence in the third quarter of 2026. Valued at approximately $135 million, the agreement covers an estimated 250 days of operations and includes upfront payments for rig upgrades and mobilization.

The total contract value excludes the provision of any additional services but does include priced options for up to five more wells. These optional wells could extend the campaign by an additional 80 to 100 days, further strengthening Valaris’s footprint in the region.

As part of the engagement, the VALARIS DS15 will receive a major equipment upgrade, including the installation of an enhanced Managed Pressure Drilling (MPD) system. This investment positions the rig to deliver improved performance in technically demanding drilling environments—an increasingly critical factor in today’s offshore energy landscape.

“We are excited to have secured another contract for one of our high-specification drillships,” said Anton Dibowitz, President and Chief Executive Officer of Valaris. “This contract reflects the market’s preference for contractors that can deliver complex drilling solutions with seventh-generation assets. It also adds to our growing presence in West Africa, where we are well positioned for future contracting opportunities.”

The announcement underscores Valaris’s focus on leveraging its fleet of technologically advanced rigs to meet rising global demand for deepwater drilling. West Africa, in particular, continues to emerge as a key growth region for offshore exploration, attracting renewed interest from energy companies seeking highperformance solutions. 

AI – an assistant, not an assassin

Previous waves of technology have gently lapped at the shores of the legal sector: big data, blockchain, metaverse to pick a few from recent years. But when generative AI arrived, it threatened a tsunami for lawyers. Here was a tool that could generate text and replicate style, tone and structure. Following the recent two-year anniversary of the launch of ChatGPT, which forced generative AI into the public consciousness, what has the actual impact on professional services been?

The fear was that AI would replace everything from engineers to artists to lawyers. It could pass exams, give plausible answers to complex questions and draft convincing text. Initially however, the failures were as visible as the successes, with lawyers reprimanded for submitting briefs written by ChatGPT, citing fictitious cases. Answers were generic and sometimes included hallucinations (formerly known as factual errors).

However, in 2024, the solutions started to mature. Existing legal technology providers wove AI into their products, and experiments helped firms to understand the use cases and the pros and cons of this seemingly magical technology.

Has AI transformed the legal sector? Undoubtedly, but perhaps not in the ways that were first envisaged. Perhaps the biggest impact of generative AI has been to show lawyers that technology is a significant part of their future. Interest in legal technology in general has increased and the trojan horse of AI has allowed firms to drive adoption of existing, as well as new, technologies. But rather than replacing humans, it's being used to augment them - performing as an assistant rather than an assassin. Firms started to realise that they could automate some of the tedious work and admin that does not add value, but does consume precious time.

Two years on, the hype has died down and the benefits of generative AI are starting to emerge. Less as a tsunami and more of a steady stream. It is being built into the tools we use already, by Microsoft through Copilot and by vendors of document, case and practice management systems and more. That is, it is making our systems smarter, and allowing our humans to work smarter too.

It's been touted as the saviour of humanity by some and the augur of its demise by others; a calculator for words and an automated mansplaining machine, a work enhancer and a destroyer of jobs. What we can be sure of is that AI has generated a huge amount of investment and a multitude of headlines and think pieces. Want

As organisations identify and exploit the use cases where AI can help them, we will start to see it become part of the furniture. That gives us challenges about how we train our people, how we value the work that we do and how we control quality and risk, but these are all surmountable. In the coming years agentic AI is sure to become the next big thing, allowing AI to not just give answers, but to carry out complex tasks by working with other AIs and systems.

What we can be sure of is that AI is here to stay. Notwithstanding the cost and environmental concerns (both of which are likely to reduce over time), AI will continue to seep into the bedrock of many organisations and to feed new growth, as well as potentially increasing access to justice and making it cheaper to solve certain types of problems. 

Damien Behan is director of innovation and technology at Brodies LLP.

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Digital Twins: Decarbonising Oil & Gas in a Virtual World

The oil and gas industry remains under a frequent level of significant transformation, with software playing an increasingly vital role in driving energy innovation.

From optimising operations to enhancing safety and sustainability, digital solutions are becoming indispensable for companies looking to thrive in a rapidly evolving energy landscape. Although many innovations have been iterative in nature, building on previous experience and systems, there are also examples of systems which have only recently become a viable option for the Oil & Gas industry – even in their infancy. Among these technologies, Digital Twins are emerging as a powerful tool, offering virtual replicas of physical assets and processes that can unlock substantial benefits in the pursuit of effective decarbonisation.

A Digital Twin is essentially a dynamic, datadriven virtual model. It mirrors real-world assets using sensor data, AI, and cloud computing, providing a continuous, up-to-date representation. This allows operators to gain unprecedented insight into their operations, enabling them to identify inefficiencies and explore decarbonisation strategies in a riskfree environment. The oil and gas industry, under increasing pressure to decarbonise, is turning to innovative technologies like Digital Twins. These virtual replicas of physical assets and processes offer a powerful tool to optimise operations, reduce emissions, and navigate the complex energy transition. In essence, think of a Digital Twin like having a super-smart virtual copy of a real machine or oil rig. This copy gets all the real-time information from the actual thing and can be used to see how

Authored by Brendan Rorrison, Product Owner

it's doing, predict when it might need fixing, or even test out changes without touching the real equipment. It's like a flight simulator for an entire industrial operation.

The requirement for more bleeding edge technology is due to the fact that decarbonisation is a multifaceted challenge for the sector. Companies are striving for net-zero emissions, reducing methane leaks, integrating renewables, and implementing carbon capture technologies. However, technological hurdles, regulatory uncertainties, and economic considerations complicate these efforts and add a multitude of characteristics that are substantially difficult to model and analyse without empirical real world-driven data. Digital Twins offer a pathway to address these challenges head-on through its simulation and recreation of ‘live’ architecture and environments.

By providing real-time energy consumption data, Digital Twins help identify areas for improvement. Operators can simulate process changes, optimise resource allocation, and minimise waste, leading to substantial emission reductions. For instance, refineries have used Digital Twins to significantly reduce steam usage and energy consumption.

Predictive maintenance is another crucial application. By analysing sensor data and predicting equipment failures, Digital Twins prevent unplanned downtime and potential environmental incidents like leaks and spills. This proactive approach enhances safety

and reduces the environmental footprint of operations. Furthermore, Digital Twins are invaluable for asset integrity management, streamlining inspections and turnarounds.

The integration of renewable energy and carbon capture technologies is vital for decarbonisation. Digital Twins facilitate this by simulating the optimal placement and operation of renewable energy assets, like wind turbines on offshore platforms. They also assist in optimising carbon capture systems, ensuring efficient CO2 capture and secure storage.

However, it can be argued that scenario planning is where Digital Twins truly shine. This is because Digital Twins allow companies to model and evaluate the impact of different decarbonisation strategies before implementation. This enables informed decision-making and helps identify the most effective pathways to achieving emission reduction targets.

Industry leaders like BP, Shell, and Equinor have successfully implemented Digital Twins, achieving tangible benefits. BP, for example, is using the technology to calculate real-time carbon intensity at its Clair Ridge facility, aiming for carbon-aware operations globally. Shell has reported a 20% improvement in operational efficiency at its Prelude FLNG facility, thanks to Digital Twins. Equinor leverages the technology to optimise offshore drilling and enhance safety.

Looking ahead, the integration of AI and machine learning will further enhance the predictive capabilities of Digital Twins. More diverse data sources, including environmental and market data, will be incorporated, providing a holistic view of operations. Immersive technologies like AR and VR will improve collaboration and decisionmaking. Lifecycle Digital Twins will offer a comprehensive approach to decarbonisation, from design to decommissioning.

Ultimately, Digital Twins are more than just virtual models; they are powerful tools for driving sustainable change in the oil and gas industry. By enabling data-driven decisionmaking and facilitating the adoption of cleaner technologies, Digital Twins are paving the way for a lower-carbon future. Although the bestcase examples of their use currently sit with some of the biggest players in the industry, this is definitely a technology worth keeping an eye on for the innovation it could offer to the energy sector in the near (and far) future as AI and Internet of Things (IoT) technologies continue to expand into prominence. 

Noble wins rig contract extension with Petrobras offshore Colombia

Decision will keep the Noble Discoverer employed in the South American nation until August 2026

Petrobras has so far unlocked in place volumes of more than 6 trillion cubic feet of natural gas with the drilling of the Sirius-1 and Sirius-2 wells in Block GUA-OFF-0 in the Guajira Offshore basin in the Colombian Caribbean Sea.

In a brief post on LinkedIn, Noble informed that Petrobras has exercised an option to keep the semi-submersible drilling rig Noble Discoverer for an additional 390 days in Colombia.

The move extends the contract from July 2025 to August 2026. Financial terms were not disclosed. Noble said Petrobras also has an unpriced option for an additional extension of the Noble Discoverer into the third quarter of 2027.

Petrobras intends to drill at least two more wells in the block this year, including the Buena Sorte-1 wildcat, but the contract extension suggests the oil giant will carry out extra drilling in Colombia.

A drillstem test conducted earlier this year in the Sirius-2 probe at 804 metres of water assessed about 100 metres of reservoir interval, and according to Petrobras demonstrated “good productivity.”

Petrobras already has a plan to begin output from Sirius by the end of the decade via a subsea-to-shore solution through the installation of manifolds in the seabed and with production lines connected to shore.

Petrobras operates the Sirius development with a 44.44% stake and is partnered by Colombia’s Ecopetrol with the remaining 55.56% interest. 

Transocean rig arrives to start major Australian gas exploration campaign

Multi-well programme for several operators starting with ConocoPhillips could boost Australia’s energy security

Transocean’s semi-submersible rig Transocean Equinox has arrived in Australia’s Otway basin ahead of a multi-well campaign that will kick off with a ConocoPhillips-operated exploration campaign in offshore blocks Vic/P79 and T/49P.

Two firm wells are to be drilled this year as phase one of the programme, followed by up to four optional wells (phase two) between 2026 and 2028 on the two permits.

The initial wildcat is scheduled to commence in the third quarter depending on factors including the receipt of all regulatory approvals, and pending weather delays and any operational delays within the four-company operating consortium, said ConocoPhillips’ coventurer ASX-listed 3D Energi.

Seabed surveys in Vic/P79 in commonwealth waters are scheduled to start this month — and expected to take four weeks to complete — ahead of exploration drilling, . The final selection of well locations is yet to be confirmed pending completion of subsurface 3D seismic interpretation studies across the two exploration permits.

The drilling campaign is focusing on lowrisk gas prospects with direct hydrocarbon indicators in the offshore Otway basin, where proximity to existing infrastructure and Australia’s east coast gas market “further enhances the commercial viability of potential finds”, said 3D.

The company added the Otway exploration drilling programme (OEDP) is critical to the future gas needs of southern Australia, given the rapidly declining production from the Bass Strait and forecast shortfall risks from 2028 and structural supply gaps from the following year.

Australia’s independent regulator Nopsema in late February accepted the Environment Plan for ConocoPhillips’ OEDP that proposes up to six exploration wells in water depths ranging from 53 to 200 metres on the Vic/679 and T/49P permits in Commonwealth waters off the coasts of the states of Victoria and Tasmania, respectively.

MODEC wins ExxonMobil Guyana’s Hammerhead FPSO contract

MODEC, Inc. (MODEC) is pleased to announce that it has been awarded a contract by ExxonMobil Guyana Limited (ExxonMobil) Floating Production, Storage, and Offloading (FPSO) vessel for the Hammerhead project.

The contract is a Limited Notice To Proceed (LNTP) by ExxonMobil Guyana, pending necessary government and regulatory approval. Phase one encompasses FrontEnd Engineering and Design (FEED) while phase two covers Engineering, Procurement, Construction, and Installation (EPCI).

The LNTP allows MODEC to start activities related to the FPSO design to ensure the earliest possible project startup in 2029, should the project receive the necessary government approvals. The performance of the second phase (i.e., construction and installation) is subject to government and regulatory approval as well as project sanction by ExxonMobil Guyana Limited and its Stabroek Block co-venturers.

Simultaneously, the Operations and Maintenance Enabling Agreement (OMEA) for MODEC’s Guyana fleet has been established to enable the operations and maintenance of multiple FPSOs under a long-term contractual arrangement.

The Hammerhead FPSO will have the capacity to produce 150,000 barrels of oil per day (BOPD), along with associated gas and water. It will be moored at a water depth of approximately 1,025 meters using a SOFEC Spread Mooring System.

The Hammerhead FPSO will be MODEC’s second for use in Guyana, following the Errea Wittu, which is currently being built for ExxonMobil Guyana’s Uaru project.

MODEC Group President and CEO, Mr. Hirohiko Miyata, expressed his delight for securing the Hammerhead FPSO project.

“We are incredibly honored and excited to have been awarded this contract. It is a testament to our team’s dedication, expertise, and commitment to delivering innovative and reliable offshore floating solutions. We look forward to collaborating closely with ExxonMobil Guyana to ensure the successful delivery of this second FPSO, contributing to the advancement of the offshore energy sector in Guyana.” 

PBR to Commence Well Decommissioning in Sergipe Basin Offshore Brazil

Petrobras S.A. PBR, the Brazilian state-owned energy giant, has stated that Borr Drilling’s jack-up rig, namely Arabia I, has arrived in Brazilian waters to begin decommissioning activities in the Sergipe Basin. The Arabia I jack-up rig secured a fouryear contract from Petrobras in Brazil. The contract includes a four-year option to extend the jack-up rig’s stay with Petrobras. However, the option currently remains unpriced.

The Arabia I jack-up rig was expected to begin its contract with PBR in the first quarter of 2025. The Brazilian energy firm mentioned that the rig arrived in Brazil on April 13, 2025, and is on its way to the Guaricema field in the Sergipe basin to commence well decommissioning tasks. The Guaricema field is a shallow water field located about 9 kilometers off the coast.

Strategic Focus on Decommissioning in Sergipe

The company’s operations in the Guaricema field are part of a broader decommissioning program in the Sergipe region. Petrobras’ strong focus on decommissioning activities in the area, which involve safely shutting down oil and gas facilities that have reached the end of their lifecycle, underscores its commitment to conducting safe and sustainable operations. In its Strategic Business Plan for the 2025-2029 period, PBR has projected an investment of nearly $1.7 billion in the region for the decommissioning of oil and gas infrastructure.

Details of the Arabia I Jack-Up Rig

Borr Drilling’s Arabia I jack-up rig, which was constructed in 2020, boasts a Keppel FELS B Class design. The rig has a maximum drilling depth of up to 30,000 feet and can operate in depths of 400 feet underwater. The rig has the capacity to accommodate 150 people. Its assignment in Brazil includes well intervention

activities involving old oil and natural gas wells. This implies that the oil and natural gas wells that have reached the end of their asset life will be safely deactivated and capped.

The initial campaign for PBR is expected to last for seven months. After that, the rig will move on to work on other wells in the region. Petrobras has mentioned that it plans to decommission approximately 26 units in the Sergipe Basin.

PBR’s Commitment to Safety and Sustainability

PBR has prioritized safely shutting down its operations associated with the assets that are no longer in production while adhering to the highest level of environmental standards and regulations. It has noted that the decommissioning activities conducted in the Sergipe Basin are using the best and most advanced techniques, which are in line with the regulations being followed in the industry at present. This step has been described as a natural progression for the infrastructure in place, as they have been in use for well over 25 years.

The Brazilian energy giant would require the approval of designated authorities like the National Agency of Petroleum, Natural Gas and Biofuels, the federal government agency that oversees the regulations of the oil and gas industry in Brazil, the Brazilian Navy, and IBAMA to execute the required steps associated with the decommissioning process. 

Petrobras to start Guaricema field decommissioning

Expected operations are part of Petrobras’ estimated $1.7-billion infrastructure decommissioning program in Sergipe basin as part of the company’s overall 2025-29 strategic and business plan.

The rig will carry out intervention activities for deactivation and plugging. The initial campaign will last about 7 months, with subsequent movement to other wells.

Petrobras is expected to decommission 26 production units in Sergipe. 

Petrobras received the PA38 jack-up rig for Guaricema field shallow water well decommissioning about 9 km from the coast of Brazil. More new decommissioning news available @ https://ogvenergy.au/ decommissioning/

Genesis in action: Oil platform comes back to life as artificial reef

A new lease on life has been bestowed upon an offshore platform that brought over 120 million barrels of oil to the energy market during its lifetime. This decommissioned oil platform shed its previous skin to transform into an underwater artificial reef, enabling it to live on as a thriving habitat for marine life in the Gulf of America, formerly the U.S. Gulf of Mexico (GoM).

The tale of Genesis, Chevron’s first deepwater platform, dates back to its construction in the late 1990s, when it became the first 705-ft, 28,700ton floating steel spar to house drilling and production facilities.

After coming online in 1999, the oil platform operated half a mile underwater, servicing 20 wellheads arranged on the seafloor. The U.S. energy player decided to retire the giant offshore structure from active service duty in 2019, about 20 years after it produced its first oil.

Decommissioning Genesis required the expertise of a vast number of people and years of effort before the wells were turned off. Chevron has now turned its former platform into an artificial reef for marine life as part of the Louisiana Rigs to Reefs program.

Erin Englert, Chevron’s Regulatory Affairs Advisor, who facilitates programs that transform decommissioned oil and gas platforms into marine life habitats, said: “I’ve seen videos and pictures of the results, and it’s just beautiful. I would love to go down there and visit one.”

Last year, the Genesis’ spar was submerged deep off Louisiana’s coast, just as other decommissioned structures had been before it, since it is not unusual for offshore energy industry components to be repurposed.

This recent project involved turning the spar, or hull, of the former Genesis platform into a gathering spot for creatures like coral, tropical fish, and anemones. As it is believed that marine life is attracted to offshore platforms, U.S. and Louisiana state officials want the structures to continue to provide ecological benefits when decommissioned.

“Fish are reliant upon them as a habitat, It’s rewarding to see them thrive,” emphasized Mike McDonough, Artificial Reef Program Coordinator with the Louisiana Department of Wildlife and Fisheries.

A new life was also breathed into a decommissioned oil field infrastructure offshore Malaysia with a rig-to-reef project, as confirmed by Hibiscus Petroleum, a Malaysian independent oil and gas exploration and production company.

Transforming these huge structures within the offshore energy landscape at the end of their service life into something innovative yet sustainable has become a popular endeavor over the years.

In line with this, Saudi Arabia is paying homage to its oil and gas heritage by pursuing the development of an offshore oil platform-style ‘extreme’ adventure hub as a tourism project in the Arabian Gulf. 

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TMC Excellence in North America

Ettienne De Swardt, USA Managing Director

In North America, as around the globe, ATPI’s legacy is built on innovation and exceptional client service, powered by our outstanding team and visionary leadership. As the new Managing Director for the US, I feel honoured to continue that legacy and apply my expertise to help the Group achieve the exciting goals we have mapped out over the coming months.

Servicing the US and the many incredible companies of all sizes that comprise its energy industry, both traditional oil and gas and developing renewable sources, is tantamount to our aims. Already, we have a wealth of clients that, on a day-to-day basis, demonstrate their importance in supporting the nation’s energy infrastructure. We are proud to support them by ensuring that their workforce, whether C-Suite, Onshore personnel, or Offshore crew, has the necessary travel management support to instead focus on their role. By assuming responsibility for how individuals and crews get from A to B and supporting rotation, our inhouse experts handle a significant and timeconsuming administrative burden.

As I step into this new position, aligned with our global energy strategy, as a team we are aiming to keep the momentum going by strengthening existing relationships while creating new ones and exploring how we can further support our customers. The integration of technology and duty of care are among the priorities on my list.

Embracing Technological Innovations

The technology we have at our disposal is one of our USPs and, combined with our knowledge and customer service support, helps us unlock streamlined travel logistics. We have invested significantly in advanced technologies, including AI platforms, to improve operational efficiency internally and the holistic support we provide clients. Like all sectors, digital transformation continues to reshape business travel.

The innovative platforms at our disposal enable dynamic pricing models and personalised travel experiences to help improve travel planning and manage potential disruptions. It’s going to be exciting to share how we are further enhancing our technology offerings in line with industry trends and the desire for methodical and tailored services.

With the launch of our crewing online booking technology, CrewHub, and ongoing enhancements to our Duty of Care solutions, we will further strengthen seamless crew

logistics and continue to elevate the level of care and safety we provide to our travellers.

By leveraging data analytics, we can offer clients detailed insights into travel expenditures and patterns. This approach allows for more informed decision-making, cost optimisation, and the development of travel strategies that align with clients' operational goals. Technology is still a tool at our disposal and only works at optimal capacity when united with our experienced and dedicated team.

Duty of Care

In every project and client we support, duty of care is always our number one priority. It brings me immense pride to witness how the team handles delicate situations while placing the customer's wellbeing at the core. In recognition of the complexities of modern travel, we are always looking at ways to enhance our duty of care offerings. Proactive risk assessments, unrivalled 24/7 global support, and our advanced travel tracking systems are just some of the measures taken, each ensuring the safety and wellbeing of clients’ personnel – particularly in challenging environments.

Naturally, shifts in economic and geopolitical conditions, including US trade tariffs and evolving visa requirements, are expected to impact corporate and crew travel. This places new responsibilities on how we look after our customers. Amidst volatile market conditions, we are always closely monitoring changes to ensure smooth visa processing, border entry compliance, and cost-effective travel planning for clients' operations out of and into the US and throughout regions.

Looking Ahead

As the year progresses, in the US and globally, we expect continued advancements in travel technology, increased focus on cost efficiency, and further regulatory changes impacting global mobility. ATPI remains committed to delivering tailored travel solutions, leveraging our expertise and global reach to support energy and marine clients with seamless, efficient, and future-ready travel management.

With a strong foundation built on innovation and customer-centric travel solutions, ATPI is well-positioned to navigate the evolving travel landscape in 2025 and beyond. 