Issue 95 - Drilling + wells

ISSUE 95 - AUGUST 2025

DRILLING & WELLS GLOBAL ENERGY NEWS ENERGY PROJECTS MAP DRILLING & WELLS ON THE MOVE LEGAL RENEWABLES INNOVATION CONTRACT AWARDS DECOMMISSIONING EVENTS

The wells transition: Operators now need a supply chain that can shoulder regulatory risks

IN THIS ISSUE

READ ON PAGE 4  Elemental Energies Energy Reviews Projects Map Stena Drilling

P. 04 P. 10 P. 24 P. 28

McGregor Consultants Zenith Energy QHSE Aberdeen Cavitas Energy

P. 31 P. 32 P. 33 P. 34

J+S Subsea Brodies Leyton ATPI

P. 35 P. 40 P. 41 P. 46

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Issue 95

Drilling & Wells

Aus, Mining, APAC, UK, USA, Middle East

04 10 24 26 40 41 42 46 COVER FEATURE

WHAT'S INSIDE

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Welcome to the August edition of ‘OGV Energy Magazine’ where this month we are exploring the theme of ‘Drilling & Wells’ .

A big thank you to our front cover partner Elemental Energy this month and you can read a great piece by their CEO - Mike Adams on why Operators now need a supply chain that can shoulder regulatory burden, on pages 4-5.

We are also delighted to welcome contributions from Stena Drilling, Zenith Energy, Intervention Rentals, Wellpro, McGregor Consultants, Wellvene, Cavitas, Tess, J+S Subsea, QHSE Aberdeen and Brodies The rest of this month’s magazine as always provides you with a review of the Energy sector in the North Sea, Europe, Norway, Middle East, US and Australia, along with industry analysis and project updates.

Thanks as always to our corporate partners the Energy Industries Council, Leyton, Infinity-Partnerships, Elemental Energies and Archer - the Well company, Three60 Energy,

Contact: sales@ogvenergy.co.uk

Brimmond, Drager, Rotech Subsea, Stats-Group, Cegal, GDi, PTS Services, ESWL, Tess, Intervention Rentals, Vulcan Completion Products, Viper Innovations, J&S Subsea, Wellpro and Scotsbridge.

Enjoy this issue!

Dan Hyland Editor

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www.ogv.energy/magazine

A trifecta of rising demand for decommissioning, CCUS and new oil and gas projects, amidst the simultaneous downsizing of oil and gas workforces, is driving a transition to a new model. A restructuring of energy majors to find cost efficiencies, diversify skills and portfolios ahead of the energy transition is seeing traditional divisions such as wells, subsurface and projects being reduced. At the same time, these technical skills are highly sought-after amidst the rising demand for new gas supplies to replace Russian imports, an acceleration in regulatory driven decommissioning, and an upsurge in CCUS projects to meet looming emissions targets.

Cumulatively, this means responsibilities that were

www.ogv.energy I August 2025

engineering traditionally

the domain of major operators – from field development planning and well abandonment to regulatory engagement and quality control - are increasingly being transferred to third parties. This requires a parallel transformation of supply chains to shoulder new responsibilities, while reducing costs and risks, from the multi-skilling of workforces to digital transformation and new commercial models.

Burgeoning demand for wells skills Demand for a new model of oil and gas projects is being driven by a range of factors. Global gas demand is soaring due to accelerating coal-to-gas switching across the

industrial and power sectors, and as Europe seeks to replace Russian imports and replenish depleted gas stocks. This is spurring new projects in regions such as Norway, which launched new licensing for an estimated 76 new blocks for oil and gas exploration across the Barents and Norwegian Seas.

At the same time, declining production in some regions, alongside ageing infrastructure and the race to net zero, are fuelling demand for more decommissioning, with some 2,000 wells to be decommissioned over the next decade across the UK alone. In parallel to this, the need to balance new production with net zero regulations is creating a burgeoning CCUS market with new projects across the US and Europe.

COVER FEATURE Towards the ‘wells transition’ Taking on this task requires a new kind of supply chain partnership – one capable of shouldering these responsibilities seamlessly and managing end-to-end projects while unlocking cost efficiencies and reducing regulatory risks for operators. This is at the core of what we do at Elemental Energies, developing integrated engineering teams strategically located in key regions, with the ability to deliver projects across every stage of the well lifecycle – from new oil & gas development, through to complete asset decommissioning, CCUS and geothermal.

Critical to this is assuring operators that technical, operational, commercial and regulatory risks will be closely managed, and that through this model long term efficiencies will be achieved.

As a result, we harness new technology and integrated engineering efficiencies alongside innovative commercial models to reduce project costs and risks, creating a win-win for both operators and regulators.

We work to remove scope and reduce labour costs by creating integrated, multiskilled teams to streamline and accelerate project delivery. For example, our well decommissioning P&A teams comprise a wide range of engineering skills within a single team, including subsurface, well engineering and well services. This approach allows us to optimise sequencing and operational schedules from the earliest stages of decommission planning, in addition to optimised risk management, integration of technical efficiencies, and reduced interfaces between teams – both onshore and offshore.

The digital transformation of supply chains However, amongst the flurry of activity, energy majors are undergoing reorganisation and diversification of portfolios to curb operational costs and adapt to the accelerating energy transition. This is seeing oil and gas companies centralise teams or reduce hiring across traditional specialisms such as well, reservoir and facilities engineering. Yet dual pressures to downsize oil and gas workforces while sustaining rising demand for new projects – from gas to CCUS – risk creating a growing engineering skills gap. A recent report found that the oil and gas industry already has the oldest engineering workforce, with 68% of oil and gas employers experiencing challenges in hiring workers. This is driving growing demand for a new model – one where every aspect of well delivery, from subsurface to decommissioning, can be transferred to supply chain partners.

Suppliers are using digital tools to reduce costs and risks too, helping to unlock efficiencies in planning, enable real-time monitoring and drive highly efficient project delivery. For example, we use computational fluid dynamics to analyse and optimise fluid flow and transient flow modelling, which analyses the changing velocity and pressure of fluid flows, creating enhanced data-driven well production decision making. Similarly, remote real-time data visualisation is helping show how wells interact with subsurface geology to reduce environmental and regulatory risks.

Digital tools are connecting and consolidating different workflows, teams and processes to create more transparent, joined-up, efficient projects. As well as aligning teams more closely together, connected data can help transfer insights across multiple assets and even cross-basin.

As outsourcing increases, digital tools enable greater oversight and control of risk, approvals and ultimately cost across the supply chain. We are constantly pursuing

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evolution in how we deploy digital tools, supporting our management of QHSE and logistics to lessons learned and data visualisation. This work allows us to both improve efficiency across our global teams and increase transparency with clients.

Ultimately, by combining end-to-end data and insights across projects and divisions, we are creating a connected engineering solution capable of servicing the world’s largest projects across E&P, decommissioning, CCS and geothermal.

Sharing the burden with the supply chain With operators facing new regulations and financial constraints, successful outsourcing also requires supply chains to more closely align their models with the pressures and long-term goals of their clients - from cost and time-effective delivery to strict regulatory compliance. At Elemental Energies, we are coupling integrated engineering and operational processes with commercial models that allow for both aligned KPIs and incentivisation to ensure regulatory compliance, adopt best practice, new technology and improve schedule performance.

But it goes beyond commercial models and integrated working; the supply chain must truly align with the regulatory demands put on operators – from supporting submissions and tracking deadlines, to facilitating audits and technical compliance.

A new model of supplier As the energy transition creates the dual challenge of demand for new projects from gas to CCUS, alongside pressures to condense oil and gas divisions, we are witnessing a parallel transition towards the outsourcing of high-value engineering and project management. In future, everything from supply chain skills and technologies to engineering practices and commercial models must be aligned with the pressures and objectives of operators.

Suppliers will need to adopt these traditional operator roles, and in turn, take on increasing responsibilities. This will require major capability and capacity to be built in the supply chain, alongside resilience and long-term investment. It presents an exciting challenge for a supply chain that has been fundamental to the exploration and development of many assets in production today. But we must continue to build this momentum, attracting the best talent and investment into our industry as we navigate the energy transition. 

Scan the QR code to visit our website elementalenergies.com

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COMMUNITY NEWS

COMMUNITY news FIND ALL THE FULL COMMUNITY NEWS ARTICLES @ ogv.energy

Another Record-Breaking Year for THREE60 Energy

Jee Ltd Delivers Critical Pipeline Remediation in North Sea Amid Seabed Scour Threat

THREE60 Energy, a global life cycle solutions company specialising in engineering, operations and systems, has announced its financial results for the year ending 31st December 2024. The strongest year of growth to date and reinforcing its position as one of the fastest-growing companies in the energy services sector.

In a decisive response to escalating subsea risks, UK-based engineering firm Jee Ltd has successfully completed a high-priority pipeline remediation campaign in the North Sea, safeguarding vital offshore infrastructure from the growing threat of seabed scour.

The firm’s DNV and ISO certified containers are recognised for their superior durability, strength, and adaptability to harsh environments. The 500 refurbished units for Peterson Den Helder feature enhanced lashing points to enable faster and more efficient loading and unloading, enabling operational efficiency for the organisation’s supply chain.

Revenue increased by 36% year-on-year to £181.7 million, while EBITDA rose by 82% to £11.3 million.

The company also recorded an operating profit of £2.6 million, a 30% increase on the previous year, with growth in non-project service lines and increased tendering across project divisions, contributing to a record backlog of £299 million, up 86% from 2023.

The operation was triggered by routine subsea surveys that uncovered severe erosion around a key pipeline spool. The resulting freespans, unsupported sections of pipeline suspended above the seabed, posed a significant risk of vortex-induced vibration (VIV), a phenomenon that can lead to fatigue damage and eventual structural failure.

ModuSpec strengthens presence in the Caspian Sea

Hunting PLC $31 million Subsea Order for the Black Sea

Rig intake & inspection specialist ModuSpec has recently secured multiple project wins in the Caspian Sea valued at more than $500,000, contributing to a strong order book moving into Q3.

Hunting PLC, the precision engineering group, today announces that it has been awarded an order totalling $31 million for its titanium stress joints (“TSJs”), which forms part of a phase three deepwater gas development in the Turkish area of the Black Sea.

OEG to supply Peterson with 500 offshore containers through to 2030 OEG, a leading energy solutions business, has secured a significant five-year contract with Peterson Energy Logistics in Den Helder for 500 offshore containers to support its operations in the Dutch sector of the North Sea. The award builds on a successful 10-year relationship between the two businesses, previously managed by the company’s Norwegian team. To further enhance service delivery and response times, the project will now be managed out of OEG’s strategically located yard close to Peterson’s facility in Den Helder.

The contract awards include supporting major International Oil Companies (IOCs) with verification of drilling and intervention well control equipment For the IOCs, ModuSpec will cover two semisubmersible drilling rigs and one platform based drilling rig, verifying in between well maintenance and deployment of the blow out preventer (BOP) in compliance with company rules and international standards. All projects are expected to be completed by October.

Hunting’s Subsea Spring business unit, located in Houston, Texas, will supply six TSJs, which include the Group’s patented ‘Direct Pull-thru Tube’ technology, to be utilised on the second and third floating production, storage and offloading vessels operating on this deepwater development.

The contract is anticipated to be completed over the next 24 months, with the first delivery expected in Q1 2027.

COMET Welcomes New RGU Graduates to Growing Sales and Marketing Team Aberdeen-based software company COMET has appointed two recent graduates from Robert Gordon University (RGU), strengthening its sales and marketing functions as the business continues to grow across the UK and internationally.

Adam Redouani joins as Sales Development Representative after completing his MSc in International Marketing with Distinction. With a background in CRM strategy, sales enablement and digital campaigns, he brings valuable commercial experience that will support COMET’s plans to reach new markets.

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GLOBAL ENERGY REVIEW THEME HEADER

UK

North Sea

Energy Review

By Tsvetana Paraskova

New guidance for review and consent of oil and gas projects, the need for homegrown energy for security, and a number of approved or rumoured mergers and acquisitions featured in the UK North Sea oil and gas industry over the past weeks.

The UK government issued in June new guidance for environmental impact assessments of offshore oil and gas projects, to take into account last year’s Supreme Court ruling that North Sea operators for the first time are required to consider the impact of burning the extracted oil and gas in environmental impact assessments.

The guidance on assessing effects of downstream scope 3 emissions on climate is supplementary to existing guidance on Environmental Impact Assessments for oil and gas extraction projects.

The new guidance gives greater clarity and stability for North Sea operators, the government says, while industry welcomes what it sees as the restarting of the approval process for oil and gas projects in the North Sea.

www.ogv.energy I August 2025

The new guidance will ensure the full effects of fossil fuel extraction on the environment are recognised in consenting decisions. It sets out how environmental impacts of oil and gas should be assessed, providing a clear way forward for the industry, the UK government said.

Offshore oil and gas developers will now be able to submit their applications for consent to extract oil and gas in already-licensed fields, a process which has been on pause since the Finch Supreme Court judgment.

There is no change to the legislation and the process remains the same. Environmental statements are subject to public notice requirements for 30 days.

of the oil and gas produced in UK waters – industry says it is critical that home produced resources remain the provider of choice over imports, which are often produced with greater emissions, according to OEUK. The government’s independent advisers, the Climate Change Committee, say that even if the UK meets its current path toward the target of net zero carbon emissions by 2050, UK homes and businesses will still use between 13 and 15 billion barrels of oil and gas. Today, the UK is on track to produce only 4 billion of those barrels with companies warning even this is at risk, OEUK reckons.

It’s important that firms and their people can plan ahead and make investments in UK oil and gas projects critical to our economic and industrial future.

When deciding on an application, the Energy Secretary will consider the significance of a project’s environmental impact, while taking into account and balancing relevant factors on a case-by-case basis such as the potential economic impact and other implications of the project.

The government does not anticipate taking any decisions until autumn at the earliest, on applications received following the new guidance.

In response to the guidance, the leading representative body for the UK offshore energy sector, Offshore Energies UK (OEUK), welcomed the restart of the approval process for oil and gas projects in the North Sea. The guidance is an important step in ensuring the responsible production of oil and gas produced in UK waters, alongside the acceleration of homegrown renewables, OEUK said.

While the guidance focuses on so-called “scope 3” emissions – ensuring operator companies accurately report the full impact

“The publication of this guidance enables firms to move ahead with the process to responsibly develop projects that add jobs and value to the UK economy and boost energy security,” said OEUK Chief Executive David Whitehouse.

“It’s important that firms and their people can plan ahead and make investments in UK oil and gas projects critical to our economic and industrial future.”

A new independent study, produced for OEUK by energy experts Westwood Global Energy Group, finds that up to 7.5 billion barrels of oil and gas could still be produced from UK waters – 3.2 billion more than current government estimates.

This additional production could add £165 billion in economic value, with a total of £385 billion if the UK meets half its oil and gas demand from domestic sources, supporting jobs, investment, and public services across the country.

“While political rhetoric paints UK production in terminal decline, the subsurface still holds untapped potential. What is needed is a new perspective,” Westwood says.

UK ENERGY REVIEW Many of the barriers to unlocking the UK North Sea’s potential are not technical, they are policy driven and solvable, according to the report.

“A constructive outcome from the recent government consultations on the Future of the North Sea and the fiscal regime, combined with pragmatic policy change, could unlock significant value.”

Westwood analysts noted that “This is not an exercise in nostalgia – it is about building a balanced and secure future. The geology is unchanged. The skills remain, for now. With timely decisions, the North Sea can continue to contribute meaningfully to the UK’s energy system as it transitions to net zero.”

Commenting on the report, OEUK warned that without government support for the sector the UK risks a faster North Sea decline which could see it become dependent on oil and gas imports for 80 percent of its needs within this decade.

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Viaro Energy is expanding its North Sea portfolio with an agreement to acquire Deltic Energy via its main operating subsidiary RockRose Energy.

Deltic’s licence interests present a highly complementary fit with Viaro’s existing portfolio, offering near-term development potential and enhancing the Group’s long-term resource base.

Viaro will prioritise the development of the Selene discovery – one of the largest gas fields in the UK Southern North Sea in the past decade.

Ithaca Energy has completed the acquisition of JAPEX UK E&P Limited, which increased Ithaca Energy’s interest in the Seagull field from 35 percent to 50 percent, equalling bp’s interest as the field operator.

The government’s Industrial Strategy, which sets out a ten-year plan for Britain’s industrial sectors, is welcome but must harness the UK’s whole energy mix, from oil and gas to wind, hydrogen, and carbon capture technology and their interlinked supply chains as a secure and affordable bedrock for long-term industrial success, OEUK said.

At the end of June, Shell addressed media speculation that it is in talks to buy bp, clarifying that “it has not been actively considering making an offer for BP and confirms it has not made an approach to, and no talks have taken place with, BP with regards to a possible offer.”

“Government is right to recognise the role of secure and affordable energy at the heart of industrial strategy – it must also be clear in its backing for the sectors that currently deliver it, including oil and gas alongside renewables,” OEUK’s Whitehouse commented.

Under UK market rules, Shell confirmed it has no intention of making an offer for BP and by confirming this, Shell will be bound by the restrictions in the rules not to make an offer for BP in the next six months.

In company news, several mergers and acquisitions were completed, while Shell denied it had talked to bp over a potential takeover in what would be a blockbuster deal in the energy sector globally.

Shell, however, did not rule out an offer in the future if a third party announces a firm intention to make an offer for BP, or “if there has been a material change of circumstances.”

Equinor and Shell announced they have chosen Adura as the name of their incorporated joint venture (IJV). Adura will be the UK North Sea’s largest independent oil and gas producer as the two majors proceed with the integration of most of their North Sea assets.

Orcadian Energy said that Phase B of the P2482 licence, which contains the Elke and Narwhal discoveries, has been extended until 14 July 2027.

The creation of Adura follows the announcement in December 2024 that Equinor and Shell would be combining their UK offshore oil and gas assets and world-class expertise to form a new company.

“Adura has been created to bring together the A of Aberdeen and the dura of durability. It’s a company built on firm foundations, much like the strong granite synonymous with the city,” Equinor and Shell said.

Adura will sustain domestic oil and gas production and security of energy supply in the UK and beyond, headquartered at the Silver Fin building in Aberdeen city centre.

Work continues towards securing regulatory approvals, with launch of the IJV expected by the end of this year.

“When Adura launches later this year it will become the UK’s largest independent producer. Through combining assets and expertise, we will create a robust portfolio, with a shared purpose, to unlock long term value,” Simon Roddy, Senior Vice President Shell UK Upstream, said.

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“We are delighted to have received this licence extension which maximises the probability of us designing an area development plan which optimises the development of all the viscous oil resources in the Pilot area,” Orcadian Energy CEO Steve Brown said.

“We believe that Pilot and Elke can form the basis of a new low-emissions hub for the development of the major resources in this area.”

EnerMech has been awarded a three-year fixed term contract with a further two by two-year extension option periods by Dana Petroleum.

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GLOBAL ENERGY REVIEW THEME HEADER

Europe Energy Review

By Tsvetana Paraskova

Project expansions and discoveries offshore Norway, the UK’s new wind and solar power strategies, and new power and energy storage investments featured in the European energy industry in the past month.

Oil & Gas Equinor and its partners in the Johan Sverdrup oilfield offshore Norway decided to invest $1.3 billion (13 billion Norwegian crowns) in the third development phase of the giant field, which will see new subsea infrastructure increasing recovery by 40–50 million barrels of oil equivalent.

Johan Sverdrup is the largest oil-producing field in Norway and ranks among the world’s most carbon-efficient oil fields.

The Phase 3 development includes two new subsea templates which will be tied into existing infrastructure via new pipelines.

Production from Phase 3 is expected to start in the fourth quarter of 2027.

www.ogv.energy I August 2025

“The project increases the recovery rate and value creation from Johan Sverdrup, one of the world’s most carbon-efficient oil and gas fields. At the same time, it contributes to stable energy supplies to Europe,” said Trond Bokn, senior vice president for project development in Equinor.

For the phase 3 project, TechnipFMC has been awarded the contract for engineering, procurement, construction, and installation (EPCI) for the subsea development, with a contract value of approximately $527 million (5.3 billion crowns). Additional contracts, including platform modifications and the drilling of eight wells, are planned to be awarded later in 2025, Equinor said.

The expected recovery rate from Johan Sverdrup is already world-class at 66 percent. The phase 3 project is an important step towards achieving Equinor’s ambition of 75 percent recovery rate.

The average for the Norwegian continental shelf (NCS) is 47 percent.

“In 2024, Johan Sverdrup set a production record with 260 million barrels of oil, the highest annual oil production ever from a Norwegian field. Every third barrel of oil from the Norwegian continental shelf now comes from the field,” says Marianne Bjelland, vice president for Johan Sverdrup.

“Phase 3 is an important contribution to maintaining high production from Johan Sverdrup in the years to come.”

Equinor has also recently announced an oil discovery in the Johan Castberg area in the Barents Sea. The Johan Castberg oilfield had just reached full capacity of 220,000 barrels per day (bpd) when Equinor said at the end of June it had struck oil in exploration well 7220/7-CD-1H, Drivis Tubåen, on the Johan Castberg field.

According to preliminary estimates the size of the discovery is 9-15 million barrels of oil.

“Only a short time after Johan Castberg came on stream and is producing at full capacity, we have made a new discovery that can provide additional reserves for the field,” said Grete Birgitte Haaland, Equinor’s senior vice president for Exploration & Production North.

“The Johan Castberg volume base originally estimated at 450–650 million barrels, our clear ambition is to increase the reserves by another 250–550 million barrels. To realise this, we are planning six new IOR (increased oil recovery) wells and continuous exploration activity.”

At the same time, Equinor will also develop Isflak as a rapid field expansion with planned start-up in 2028, Haaland said.

Low-Carbon Energy The UK government announced in July an Onshore Wind Taskforce strategy to double Britain’s onshore wind capacity.

“As one of the cheapest and fastest to build sources of power we have, onshore wind will play a critical role in boosting our energy independence with clean power by 2030. The reality is that every turbine we build helps protect families, businesses and the public finances from future fossil fuel shocks,” said Ed Miliband, Secretary of State for Energy Security and Net Zero.

In view of boosting onshore wind power installations, the Labour government last year lifted the de facto moratorium on onshore wind in England, which had been in place for nine years.

Now the new Onshore Wind Taskforce Strategy sets out more than 40 steps the government and industry will take to help deliver up to 29 gigawatts (GW) of onshore wind by 2030. That includes driving ambitious reforms to planning, grid connections, and routes to market, while building the supply chains and skilled workforce the UK needs.

“The gap to our 2030 onshore wind goals remains an underdeveloped pipeline of projects in England, following the lifting of planning restrictions last year,” said Chris Stark, Head of Clean Power 2030, Department of Energy Security and Net Zero.

“We are focused on rebuilding that pipeline, project by project, with new steps to build community support and foster strong relationships between onshore wind developers and their local communities.”

EUROPE ENERGY REVIEW RenewableUK welcomed the new onshore wind strategy, with RenewableUK’s Head of Onshore Wind Delivery, James Robottom, saying, “The measures outlined will increase confidence among investors and developers, so that we can attract billions in private investment and create thousands of highlyskilled jobs and new supply chains all over the country.”

RenewableUK also noted that the UK’s wind industry is celebrating a decade of substantial growth and progress.

Over the last ten years, the wind industry doubled the UK’s wind generation capacity, from 13.4 GW in 2015 to over 30 GW in 2025, and provided 30 percent of the country’s electricity in 2024, a year which also saw wind overtake gas generation for the first time.

The wind industry supply chain grew to almost 2,000 companies, located across more than 70 parliamentary constituencies throughout the country. During the past ten years, the industry also increased its workforce to over 55,000 people, and invested more than £550 million in local communities via community benefit funds, RenewableUK said.

The UK government launched on 30 June a pathway for the UK to rapidly accelerate the deployment of rooftop solar across the country, which could save around £500 a year on a family’s energy bills.

“Through solar, we are rolling out the quickest to build and one of the cheapest forms of energy for families to start saving hundreds on their energy bills, all whilst helping tackle the climate crisis,” Energy Minister Michael Shanks said.

The Marine Energy Taskforce (MET) launched in June, tasked with developing a roadmap to realise the UK’s marine energy potential and backed with funding by The Crown Estate and Crown Estate Scotland. The MET is a 12-month initiative that will explore what actions are required to realise the UK’s potential in a manner that maintains high levels of UK content.

The Crown Estate announced the results of Floating Offshore Wind Leasing Round 5 for sites in the Celtic Sea off the south coast of Wales and the south west coast of England.

The Crown Estate is set to partner with Equinor and Gwynt Glas – a joint venture between EDF Renewables UK and ESB – to drive the creation of new jobs and economic growth through new floating windfarms off the coasts of Wales and South West England.

“Awarding leases to the first two commercialscale sites for floating wind projects in the Celtic Sea marks a significant step forward for this innovative technology which is set to play a major role in the UK’s future clean energy mix,” said Jane Cooper, RenewableUK’s Deputy Chief Executive.

“Ports in south Wales and the south west of England have the potential to manufacture and assemble floating turbines, including giant platforms the size of football pitches, creating thousands of highly-skilled jobs.”

UK Energy Secretary Ed Miliband approved the largest offshore wind farm in the Irish Sea, the 1.5 GW Mona Offshore Wind Farm, developed

by Mona Offshore Wind Ltd, a joint venture of bp and Energie Baden-Württemberg AG (EnBW). It is estimated the Mona Offshore Wind Farm could generate enough electricity to power the equivalent of more than 1 million British homes, providing a major boost for the national mission to become a clean energy superpower.

Energy Storage System (BESS) project in the Vale of Glamorgan, Wales.

Elsewhere in Europe, Germany is halfway through reaching its 2030 solar power targets, industry group the German Solar Industry Association (BSW-Solar), said in early July.

The association, however, warned that solar power expansion has slowed and while Germany is halfway there on its solar goals, the next stage to reaching the 2030 targets cannot be taken for granted, the association’s Managing Director, Carsten Körnig, warned.

Germany also saw its latest onshore wind and innovation auctions significantly oversubscribed, suggesting continued interest in wind tenders in Europe’s biggest economy, the Federal Network Agency, Bundesnetzagentur, said in July.

“The onshore wind auction was again very well subscribed, with consequently a further decrease in award prices,” said the agency’s president Klaus Müller.

“The latest innovation auction set a new record: for the first time, the volume of bids exceeded 2 gigawatts. This indicates the continued high level of interest in the market in different forms of renewable generation.” 

British Solar Renewables (BSR) has secured financial close on a £345 million debt facility to fund a 609-MW portfolio of solar and battery energy storage projects across the UK. BSR’s portfolio consists of 12 solar and colocated solar-battery energy storage system (BESS) projects, which together will generate approximately 600 GWh of clean electricity each year. That’s enough to power around 160,000 homes and reduce carbon emissions by 140,000 tonnes annually.

Canterbury City Council consented in July a solar and battery energy storage system (BESS) that will generate enough renewable energy for up to 15,000 homes and provide valuable support to the existing grid network.

The 38 MW solar and 30 MW BESS site is located north of Tyler Hill, Kent.

Renewable Power Capital (RPC) and Greenfield have been granted planning permission for Cardiff – a 49.9 MW Battery

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HEADER

USA Energy Review

By Tsvetana Paraskova

US oil and gas activity has contracted in recent months amid elevated uncertainty for the industry, while Congress passed President Donald Trump’s Big Beautiful Bill, which the oil and gas industry welcomed as a progrowth tax bill.

The company outlook index was little changed and remained negative at -6.4, suggesting slight pessimism among firms. Meanwhile, the outlook uncertainty index increased by 4 points to 47.1, indicating elevated uncertainty among executives from 136 energy firms polled during the period 18-26 June.

Oil and gas production in the Eleventh District fell slightly in the second quarter, according to executives at exploration and production firms. The oil production index fell from 5.6 in the first quarter to -8.9 in the second quarter.

Meanwhile, the natural gas production index also turned negative, declining from 4.8 to -4.5.

Input costs for oilfield services firms rose at a slightly faster pace in the second quarter than in the prior quarter. Among exploration and production (E&P) firms, the finding and development costs index decreased slightly from 17.1 to 11.4. Also, the lease operating expenses index declined from 38.7 to 28.1.

This suggests costs for E&P firms rose at a slower pace relative to the prior quarter, the survey found.

Activity in the US oil and gas sector contracted slightly in the second quarter of 2025, according to the latest Dallas Fed Energy Survey of oil and gas executives in the Eleventh District encompassing Texas, northern Louisiana, and southern New Mexico.

On average, respondents expect a West Texas Intermediate (WTI) oil price of $68 per barrel at year-end 2025, with responses ranging from $50 to $85 per barrel. When asked about longer-term expectations, respondents on average said they expect a WTI oil price of $72 per barrel two years from now and $77 per barrel five years from now. Survey participants forecast a Henry Hub natural gas price of $3.66 per million British thermal units (MMBtu) at year-end 2025. For the longer term, respondents on average anticipate higher Henry Hub gas prices—of $4.12 per MMBtu two years from now and $4.50 per MMBtu five years from now. For reference, WTI spot prices averaged $69.81 per barrel during the survey collection period, and Henry Hub spot prices averaged $3.30 per MMBtu.

The business activity index, the survey’s broadest measure of the conditions energy firms face, turned negative, declining to -8.1 in the second quarter from 3.8 in the first quarter of 2025.

Almost half of E&P executives surveyed expect to drill fewer wells in 2025 than they planned at the start of the year. Twenty-six percent said they expect the number of wells they drill to “decrease significantly,” and 21 percent said it would “decrease slightly.”

US Drilling Activity Shrinks amid Uncertainties

www.ogv.energy I August 2025

Just 16 percent said drilling expectations “increased slightly” and only 3 percent said they “increased significantly.” Across all firms, 34 percent of executives said they anticipated “no change.”

A total of 46 percent of executives expect the increase in the US steel import tariff not to affect the number of wells their firms expect to drill over the second half of 2025. Twentyseven percent expect to drill slightly fewer wells, and an additional 5 percent expect to drill significantly fewer wells due to the tariff increase. Twenty-two percent said it is too soon to know.

A majority of executives—61 percent—expect their firms’ oil production would decrease slightly from June 2025 to June 2026 if the WTI price is at about $60 per barrel. Twentyfour percent expect production to remain close to June 2025 levels, the survey showed.

However, if the WTI price slumps to $50 per barrel, 46 percent of executives expect their firms’ oil production would decrease significantly from June 2025 to June 2026.

Another 42 percent anticipate their firms’ oil production would decrease slightly. The most selected response among executives at large E&P firms was “decrease slightly,” while among executives at small E&P firms it was “decrease significantly.”

Moreover, most executives expect challenges related to produced water management to constrain drilling and completion activity in the Permian Basin sometime over the coming five years.

In comments to the survey, an E&P executive said “The Liberation Day chaos and tariff antics have harmed the domestic energy industry.

Drill, baby, drill will not happen with this level of volatility. Companies will continue to lay down rigs and frack spreads.”

Another executive noted “Oil and gas markets look good in the long term (two to five years out). Short term 2025 and 2026 will have a lot of volatility.”

USA ENERGY REVIEW

15 15

An executive at an oil and gas support services firm said “Tariffs are increasing our product costs. Despite efforts to mitigate their impact, the scale and breadth of the tariffs have forced us to pass these costs on to our customers.”

Steel tariffs are impacting oilfield services and drilling decisions by E&P companies, say many executives in the oilfield services industry.

“Price volatility and the ability to plan is an issue, more so than previous years,” one executive said.

Oil and Gas Industry Welcomes Tax Reconciliation Bill Congress passed the 2025 tax reconciliation package, the so-called One Big Beautiful Bill Act, ahead of the July 4 holiday.

American Petroleum Institute (API) President and CEO Mike Sommers welcomed the passing of the Act, which he described as “the most important energy bill in a generation.”

The package significantly expands energy development by requiring 30 offshore lease sales in the US Gulf of Mexico, as well as quarterly onshore lease sales. The legislation also advances tax policy that supports continued investment in oil and natural gas production and helps American energy remain competitive in the global market, API noted.

“President Trump has delivered on his promise to unleash American energy by unlocking opportunities for investment, supporting global competitiveness and opening lease sales onshore and offshore from the Gulf of America to Alaska,” API’s Sommers said.

“We applaud President Trump and Congress on this historic legislation that cements American energy leadership for years to come and ushers in a new era of energy development.”

In another move from the federal government to unleash America’s energy resources, the US Department of the Interior’s Bureau of

©James Jones Jr/Shutterstock.

©Reuters: Umit Bektas

Ocean Energy Management announced at the end of June a planned Lease Sale in the Gulf of America. Lease Sale 262 will offer about 15,000 unleased blocks located 3 to 231 miles offshore across the Gulf’s Western, Central, and Eastern Planning Areas. Covering roughly 80 million acres, these blocks are situated in water depths ranging from 9 feet to more than 11,100 feet (3 to 3,400 meters).

The sale will be the first of three planned lease sales in the Gulf of America under the 2024–2029 Outer Continental Shelf Oil and Gas Leasing Program, BOEM said.

API welcomed the announcement, hailed by Senior Vice President of Policy, Economics, and Regulatory Affairs, Dustin Meyer, as “another step in a new path forward for safe and responsible U.S. offshore development after years of roadblocks that hampered energy investment in the Gulf of America.”

We applaud Secretary Burgum for leveraging our nation’s vast offshore resources to support energy affordability and national security.

“To support robust industry participation, lower production costs, and unleash the full potential of the Gulf of America’s offshore energy reserves, BOEM is proposing a royalty rate of 16 ⅔ percent for both shallow and deepwater leases—the lowest rate for deepwater since 2007,” said BOEM’s Acting Regional Director for the GOA Laura Robbins.

Added Meyer, “We applaud Secretary Burgum for leveraging our nation’s vast offshore resources to support energy affordability and national security.”

The Gulf of America is the nation’s primary source of offshore oil and natural gas production, accounting for 97 percent of all oil and natural gas production in offshore waters. Today, 14 percent of total US crude oil production and 2 percent of natural gas production comes from the Gulf of America. 

Adnoc

GLOBAL ENERGY REVIEW 16 16

THEME HEADER

Middle East Energy Review

By Tsvetana Paraskova

The surprise OPEC+ production hike for August wrapped up an eventful month in the Middle East and its energy industry.

Oil and Gas Market Scare from Iran-Israel Conflict The oil and gas markets saw wild price swings in June with the Israeli attack on Iran’s nuclear sites, the Iranian retaliation with missiles towards Israel, and the threat to close the Strait of Hormuz, the most important global waterway for seaborne oil and gas shipments.

Energy commodity markets reacted to the latest escalation of tensions in the Middle East, as several major gas-producing platforms offshore Israel were temporarily shut-in for two weeks in June under orders from the Israeli authorities.

www.ogv.energy I August 2025

Moreover, the oil market did not rule out an attempt by Iran to try to block the Strait of Hormuz, the world’s most critical oil transit chokepoint between Oman and Iran in the Persian Gulf. The Strait of Hormuz, which connects the Persian Gulf with the Gulf of Oman and the Arabian Sea, is critical to the oil exports of all Middle Eastern oil producers and to the LNG exports of Qatar, one of the world’s top exporters of the super-chilled fuel.

Large volumes of oil and LNG flow through the strait, and very few alternative options exist to move oil out of the strait if it is closed.

During the 12-day Israel-Iran conflict, which ended after the US bombed three Iranian nuclear sites, oil prices surged to their highest level in four months. Before the ceasefire announced by US President Donald Trump after the bombings on Iran, the oil market was fearing that an escalation of the conflict and potential Iranian retaliation on energy infrastructure in neighboring Gulf producers – or even an attempted blockade of the Strait of Hormuz – could disrupt oil and gas supply from the Middle East. As a result, prices spiked for two weeks, before easing down to pre-conflict levels by the end of June.

In 2024, oil flow through the strait averaged 20 million barrels per day (bpd), or the equivalent of about 20 percent of global petroleum liquids consumption. In the first quarter of 2025, total oil flows through the Strait of Hormuz remained relatively flat compared with 2024, according to data from the US Energy Information Administration (EIA).

OPEC+ Raises Output by More Than Expected

The Administration estimates that 84 percent of the crude oil and condensate and 83 percent of the liquefied natural gas that moved through the Strait of Hormuz went to Asian markets in 2024. China, India, Japan, and South Korea were the top destinations for crude oil moving through the Strait of Hormuz to Asia, accounting for a combined 69 percent of all Hormuz crude oil and condensate flows in 2024.

In early July, geopolitics in energy markets gave way to the supply decisions of the OPEC+ group led by the top Middle Eastern oil producers. The eight OPEC+ producers that have been implementing production cuts since 2023 – Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria, and Oman – decided on 5 July to raise their collective oil production in August by 548,000 barrels per day (bpd). The OPEC+ participants cited “steady global economic outlook and current healthy market fundamentals, as reflected in the low oil inventories,” to justify the production hike, which was bigger than the market was expecting. The three previous monthly output increases were of 411,000 bpd.

MIDDLE EAST ENERGY REVIEW

17

Following the larger-than-expected output hike for August, investment banks and analysts expect the OPEC+ alliance to raise production by a similarly big volume in September, which would unwind all 2.2 million bpd cuts a year earlier than previously planned.

The big hike for August “will provide an opportunity for the participating countries to accelerate their compensation,” OPEC said, referring to the compensation expected from overproducers, most notably Iraq, Russia, and Kazakhstan. Iraq has shown in recent weeks that it is trying to fall in line by pumping lower volumes of crude oil than its quota.

Russia is not hiking output either, also due to the sanctions on its oil. But Kazakhstan continues to overproduce at a level of about 300,000 bpd-400,000 bpd above its quota as it says it cannot enforce production cuts on foreign majors that have recently expanded projects in the country. The supermajors are not discussing OPEC or OPEC+ with Kazakhstan, either.

OPEC left the door open to flexibility in supply to the market, saying that “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 actual OPEC+ production boost will be lower than the headline figure implies, due to the compensation from overproducers.

Nevertheless, the supersized output increase for August accelerates the coming oversupply on the market, analysts say.

“Larger supply hikes increase the scale of the surplus in the oil market later in the year. This supports the view that there’s further downside for oil prices,” ING commodities strategists Warren Patterson and Ewa Manthey wrote in a note after the July meeting of the OPEC+ group.

As of early July, ING still expected Brent oil prices to trade down towards $60 per barrel by the end of the year amid expectations the group would increase supply again in September.

“A more bearish supply outlook, combined with demand uncertainty, doesn’t bode well for prices,” ING’s strategists said.

Saudi Arabia Signs $27 Billion Energy Deals with Indonesia

Saudi Arabia, the world’s biggest crude oil exporter, and Indonesia agreed to boost cooperation in supply of crude oil and its derivatives, petrochemicals, and joint work to exploit investment opportunities in refining and petrochemicals. The two sides will also work on cooperation in electricity, renewable energy, and energy storage, as well as in energy efficiency and conservation.

Saudi Arabia and Indonesia signed in early July a number of agreements and memoranda of understanding (MoUs) in the energy sector in a bid to further boost their Both sides agreed to economic partnership. cooperate to foster The deals, signed innovation, apply during the visit of Indonesia’s President emerging technologies Prabowo Subianto to such as artificial the Kingdom, reflects intelligence in the energy “the aspirations of both sides towards an sector, and develop an advanced economic enabling environment partnership,” the Saudi for them Press Agency reported.

The agreements include such in clean energy, petrochemicals, and aviation fuel services, the Saudi state news agency noted.

“The two sides emphasized the importance of enhancing investment cooperation and intensifying efforts to enable strategic partnerships in priority sectors, most notably energy, financial services, mining and industry downstreaming, logistic services, tourism, agriculture and green technologies, in line with Saudi Vision 2030 and Golden Indonesia 2045 and Indonesia’s national development priorities,” a joint Saudi-Indonesian statement reads.

“Both sides agreed to cooperate to foster innovation, apply emerging technologies such as artificial intelligence in the energy sector, and develop an enabling environment for them,” Saudi Arabia and Indonesia said.

Saudi Arabia is Indonesia’s largest trading partner in the region, with trade reaching $6.5 billion by the end of 2024, the Saudi news agency said.

Saudi oil giant Aramco dominates Indonesia’s petrol market, holding a 25-30 percent share over the past four years, and is its largest oil supplier, averaging 11 million barrels annually. Both nations are eager to explore energy technology cooperation, leveraging opportunities presented by Saudi Vision 2030 and its major projects. 

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GLOBAL ENERGY REVIEW THEME HEADER

Norway Energy Review

By Tsvetana Paraskova

75 percent recovery rate. To compare, the average for the Norwegian continental shelf (NCS) is 47 percent.

Start-ups of oil and gas projects, new discoveries and final investment decisions, and the launch of a landmark carbon capture and storage (CCS) project were the highlights of Norway’s energy industry in the past weeks.

New Oil and Gas Projects Equinor and its partners are investing $1.3 billion (NOK 13 billion) in the third development phase of the giant Johan Sverdrup in Norway’s North Sea. Two new subsea templates which will be tied into existing infrastructure via new pipelines are expected to increase recovery at the field by 40–50 million barrels of oil equivalent (boe). Production from the Phase 3 expansion is set to begin in the fourth quarter of 2027.

The expected recovery rate from Johan Sverdrup is already world-class at 66 percent.

The Phase 3 project is an important step towards achieving Equinor’s ambition of a

www.ogv.energy I August 2025

“Every third barrel of oil from the Norwegian continental shelf now comes from the field.

Phase 3 is an important contribution to maintaining high production from Johan Sverdrup in the years to come,” said Marianne Bjelland, vice president for Johan Sverdrup.

Shell and its partners have started up two subsea compression stations to increase the recovery rate at the Ormen Lange natural gas field in the Norwegian Sea, the UK-based supermajor, which operates the field, said in June.

Ormen Lange’s gas, processed at Nyhamna on the west coast of Norway, is being exported to the UK and the EU. The new compression stations are expected to raise the gas recovery rate at Ormen Lange to 85% from the current 75%.

The two new compressor stations are installed on the seabed 120 kilometres from shore and are directly connected to the processing plant at Nyhamna.

The increased recovery rate will allow the extraction of 30–50 billion cubic meters more gas from Ormen Lange, Shell said.

Norway, which has already become Europe’s single largest gas supplier replacing Russia after 2022, is thus set to boost further its gas supply to the EU and the UK.

The start of production at the Jotun Floating Production Storage and Offloading (FPSO) unit extends the life of the first production license, PL001, on the Norwegian Continental Shelf, towards 2045 and beyond, said Var Energi.

With the start-up of Jotun FPSO, production at Balder is expected to increase by about 80,000 boepd within three to four months, adding to the current production of approximately 30,000 boepd gross through the Balder FPU and Ringhorne facilities.

The Jotun FPSO will have a low operating cost of around $5 per barrel and estimated gross proved plus probable recoverable reserves from the project at 150 million barrels of oil equivalent, Var Energi said.

All 14 production wells have been completed and will be brought onstream during the ramp-up period to reach peak production.

Together with the Balder Phase V project starting up later this year, the project has a payback time of around two years.

With infrastructure and facilities designed to extend production beyond 2045, the startup of the Jotun FPSO opens up wide potential for continued value creation from the area

In another project launch, independent Norwegian oil and producer Var Energi has announced the start up of its Balder X project in Norway’s North Sea, which will boost output from the Balder field by about 80,000 barrels of oil equivalent per day (boepd).

“With infrastructure and facilities designed to extend production beyond 2045, the startup of the Jotun FPSO opens up wide potential for continued value creation from the area,” Nick Walker, chief executive of Var Energi, commented.

“Also, the support by the Norwegian authorities has been fundamental, and much appreciated,” Walker added.

Now that the Jotun FPSO is installed as an area host, Var Energi is taking necessary steps to add new production through infill drilling, exploration and tie-back developments with short time to market, the company noted.

NORWAY ENERGY REVIEW The Equinor-operated Johan Castberg oilfield in the Barents Sea had reached full capacity of 220,000 barrels per day (bpd), just three months after the field in Norway’s Arctic waters came on stream.

The peak capacity at the field increases energy deliveries from the Barents Sea by 150 percent, the Norwegian energy major said.

The new production vessel (FPSO) at Johan Castberg came on stream on 31 March, opening a new area for production in the Barents Sea. The first cargo was loaded by the tanker Bodil Knutsen on 25 May, shipping around 700,000 barrels to Spain. Almost all oil from the Norwegian Continental Shelf is currently delivered to Europe.

Equinor also plans to drill one or two exploration wells annually near Johan Castberg.

“Every three to four days, tank loads now depart from Johan Castberg, each of them worth around half a billion Norwegian kroner.

The field will remain on stream for at least 30 years, delivering stable energy to Europe, generating high value for Norway, and ripple effects and jobs in Northern Norway,” said Kjetil Hove, Equinor’s executive vice president for Exploration & Production Norway.

“The Johan Castberg volume base was initially estimated at 450-650 million barrels, our ambition is to increase the reserves by between 250-550 million barrels,” Hove added.

“We are already planning six new wells to extend plateau production,” the executive noted.

Going forward, two rigs will be drilling new exploration wells in the areas around Johan Castberg and Goliat. They will also drill production wells for the fields, Equinor said.

Days after this announcement, Equinor reported an oil discovery in exploration well 7720/7-DD-1H, Drivis Tubåen, on the Johan Castberg field. Preliminary estimates put the size of the discovery at 9-15 million barrels of oil.

“Only a short time after Johan Castberg came on stream and is producing at full capacity, we have made a new discovery that can provide additional reserves for the field,” said Grete Birgitte Haaland, Equinor’s senior vice president for Exploration & Production North.

Gas production from Norway’s shelf is also set to rise as Equinor and its Fram partners agreed to invest more than 21 billion Norwegian crowns, or $2.1 billion, in a new oil and gas subsea development in the Fram and Troll area.

The Fram Sør development “will put new oil and gas resources on stream by connecting new infrastructure to existing facilities that provide good and robust profitability,” said Geir Tungesvik, Equinor’s executive vice president, Projects, Drilling & Procurement.

The Fram Sør project is a combined development of several discoveries that will export oil and gas via Troll C. Recoverable volumes are estimated at 116 million barrels of oil equivalent, 75 percent of which is oil and 25 percent is gas. Production is scheduled to start at the end of 2029.

Longship CCS Project Launch Norway launched in June the world’s first full-scale value chain for carbon capture and storage (CCS)—the Longship project. Longship marks a milestone in reducing industrial emissions – both in Norway and internationally, the Norwegian government said.

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Longship is Norway’s largest climate investment ever and Europe’s first complete CCS value chain. The project includes CO₂ capture at Heidelberg Materials’ cement plant in Brevik and the planned facility at Hafslund Celsio’s waste-to-energy plant in Oslo.

The CO₂ is transported by ship and safely stored 2,600 metres beneath the seabed at Øygarden, near Bergen, managed by Northern Lights – a joint venture between Equinor, Shell, and TotalEnergies.

The first shipment of CO₂ was transported from the Brevik cement plant to the Northern Lights facility in Øygarden in early June. The CO₂ has now been transferred to storage tanks, and injection into the subsea reservoirs is scheduled to begin in August.

“We have built a complete value chain for CO₂ management that will have significant impact far beyond our borders,” Norway’s Minister of Energy Terje Aasland said.

Norway’s Energy Ministry has also approved the expansion of Northern Lights with Phase 2, which is set to increase the transport and storage capacity from 1.5 million to at least 5 million tonnes of CO₂ per year.

The project includes expanding the onshore terminal at Øygarden with a new jetty, constructing additional storage tanks, and increasing the pump capacity. Offshore, the number of injection wells will be increased from two to four.

In connection with its investment decision for Phase 2, Northern Lights has signed an agreement with Stockholm Exergi to receive up to 0.9 million tonnes of CO₂ annually from a bioenergy facility in the Stockholm region.

“We have now reached the point where Norway can offer CO₂ storage services to European companies with large point source emissions, on commercial terms. This presents great opportunities,” minister Aasland said. 

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GLOBAL ENERGY REVIEW THEME HEADER

Australia

Energy Review

By Tsvetana Paraskova

Australia Boosts LNG Supply

as Support for Renewables Grows

A

ustralia’s energy majors sign new overseas LNG supply deals and proceed with new projects at home and abroad, while the re-election of the Labor government secured continued support for clean energy in Australia.

Meanwhile, one of the biggest Australian energy companies, Santos, has entered into an exclusive due diligence agreement and has provisionally said it would accept an offer from a consortium to be acquired by the group led by ADNOC’s new company XRG.

Major Energy Deal in the Works XRG, the energy investment company of Abu Dhabi’s national oil and gas firm ADNOC, has teamed up in a consortium with ADQ and investment firm Carlyle to announce a nonbinding indicative proposal to acquire all of the ordinary shares of Santos by way of a scheme of arrangement.

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

www.ogv.energy I August 2025

Santos said that its Board, subject to reaching agreement on acceptable terms of a binding scheme implementation agreement (SIA), intends to unanimously recommend the Proposal to Santos shareholders in the absence of a superior proposal and, subject to an independent expert concluding and continuing to conclude that the Proposal is fair and reasonable and in the best interests of Santos shareholders.

The XRG-led consortium aims to build on Santos’ strong and longstanding legacy as a trusted and reliable energy producer, unlocking additional gas supply for Santos' customers, and strengthening domestic and international energy security. The proposed transaction is aligned with XRG’s strategy and ambition to build a leading integrated global gas and LNG business.

LNG Deals and Projects While the process of acquisition is under way, Santos signed in early July a midterm LNG supply contract with QatarEnergy Trading LLC (QET). The contract is to supply approximately 0.5 million tonnes of LNG per annum over a period of two years from 2026 with LNG being supplied from Santos’ portfolio of world-class LNG assets on a delivered ex-ship basis.

The LNG supply deal with QET is an extension of Santos’ existing strong business relationship and a great opportunity for both Santos and QET to leverage their expertise in Asian LNG markets, Santos Managing Director and CEO Kevin Gallagher said.

The company’s portfolio is around 90 per cent contracted and around 85 percent oil linked on average between 2025 and 2029. Average contract pricing across the whole portfolio is estimated at around 14.7-percent slope to Brent over 2025 to 2027.

If a deal is reached, the XRG-led consortium expects to maintain Santos’ headquarters in Adelaide, brand, and operational footprint in Australia and key international operating hubs.

Following a “We continue to see potential transaction, the very strong demand consortium intends to in Asia for high heating value LNG invest in Santos’ growth We continue to see from projects such as and further development very strong demand Barossa and PNG LNG, of its gas and LNG in Asia for high as well as for reliable focused business which heating value LNG regional supply. Santos will provide reliable and from projects such as remains committed to affordable energy and Barossa and PNG LNG, supporting the energy low carbon solutions to security and emissions as well as for reliable customers in Australia, reduction strategies of regional supply the Asia Pacific, and our valued customers across Asia,” CEO beyond.

This will Gallagher said. reinforce Australia’s position as a responsible Referring to Barossa, Santos announced in energy partner and contributor to domestic June the arrival of the BW Opal FPSO (floating and regional energy security, Santos said in a production, storage and offloading) vessel statement in the middle of June. at the Barossa gas field approximately 285 km north of Darwin. The arrival of the FPSO At the end of June, Santos entered into a marks a critical milestone on the path to first process and exclusivity deed with the XRG gas in the third quarter of 2025. The FPSO has Consortium in relation to the non-binding since been successfully hooked up, and final indicative proposal to acquire 100% of the commissioning activities are progressing to issued shares of Santos. plan, Santos said.

The XRG Consortium has been granted exclusive due diligence access for a period of six weeks beginning on 27 June.

Five wells of the six-well programme have now been drilled with the fifth well being prepared for flow testing. The final well is

AUSTRALIA ENERGY REVIEW expected to be completed in the third quarter.

Production from three wells can deliver full production rates at the Darwin LNG plant if required. The 262 km Gas Export Pipeline and 123 km Darwin Pipeline Duplication are complete, in addition to subsea infrastructure required for first gas.

“Barossa is a world class asset and, together with the Pikka phase one project in Alaska, is expected to deliver a 30 per cent increase in production over the next eighteen months or so compared to 2024,” CEO Gallagher said.

“These projects will set the company up with long-term, stable cash flows to underpin compelling shareholder returns.”

The other major gas producer in Australia, Woodside Energy, signed in June a nonbinding Heads of Agreement with PETRONAS for the supply of 1 million tonnes per annum of LNG to Malaysia from 2028 for a period of 15 years.

The LNG would be supplied from Woodside’s global portfolio and may include the recently approved Louisiana LNG project in the United States.

The agreement is expected to support PETRONAS’ efforts to ensure secure, flexible LNG supply to meet growing demand in Peninsular Malaysia and the broader AsiaPacific region.

“This agreement marks the beginning of a new era of collaboration between Woodside and PETRONAS and is an important step towards what would be our first long-term LNG sales to Malaysia,” said Mark Abbotsford, Woodside Executive Vice President & Chief Commercial Officer.

In another LNG supply deal, Woodside Energy Trading Singapore Pte Ltd and JERA Co. have entered into a nonbinding heads of agreement (HOA) for the sale and purchase of LNG cargoes during Japan’s peak winter period.

Under the HOA, Woodside will supply LNG cargoes on a delivered ex-ship basis to Japan during the winter months (December to February) from 2027 for a period of at least five years, subject to contract.

The agreement follows the previously announced sale of two non-operating participating interests in the Scarborough Joint Venture to JERA (15.1 percent) and LNG Japan (10 percent) and loan agreement with JBIC to support the Scarborough Energy Project.

This agreement strengthens Woodside’s long-standing relationship with JERA and further supports Japan’s energy security, Woodside said.

“We look forward to further collaboration with Japanese partners as we progress towards the startup of our new LNG projects, including the Scarborough Energy Project, where first cargo is targeted for the second half of 2026,” Woodside’s Abbotsford said.

In the US, Woodside completed the sell-down of a 40-percent interest in Louisiana LNG Infrastructure LLC to Stonepeak, a global investment firm specialising in infrastructure and real assets.

Under the transaction, Stonepeak will provide US$5.7 billion towards the expected capital expenditure for the foundation development of Louisiana LNG on an accelerated basis, contributing 75 percent of project capital expenditure in both 2025 and 2026.

Australia’s Renewable Energy Transition The re-elected Labor government has renewed its commitment to accelerating the energy transition following the 2025 federal election. The administration has pledged to uphold its ambitious renewable energy targets while introducing new policies to increase energy storage capacity and advance critical mineral development, Wood Mackenzie said in a report following the federal elections.

The re-elected Labor Government has recommitted to its target of 82 percent renewable electricity generation by 2030 and an economy-wide strategy to reduce emissions by 43 percent during the same period.

“Despite the federal government’s ambitious targets, our analysis indicates that Australia is currently on track to achieve only 58% renewable electricity generation by 2030,” said Natalie Thompson, senior analyst, energy storage and solar at Wood Mackenzie.

“This highlights the urgent need for increased investment and greater coordination across all levels of government to accelerate the energy transition,” Thompson added.

“Efforts may be further complicated by moves from some state governments, such as Queensland and the Northern Territory, to repeal

or scale back their renewable energy targets.”

Australia’s utility-scale storage capacity is expected to jump sixfold from the current 2.5 GW to over 16 GW by 2030, according to Wood Mackenzie.

However, “continued policy support is crucial to overcome grid connection and project planning barriers,” WoodMac’s Thompson said.

Until renewables scale up, gas will step into the interim to fill the gap left by coal power plant closures. With accelerated coal closures, gas is anticipated to remain a part of the energy mix for peaking support and interim system reliability.

Still, more support is needed to overcome roadblocks in grid connection and planning processes, ensure a smooth transition, and meet planned coal plant closure timeframes, WoodMac said.

The Clean Energy Council (CEC), Australia’s peak body for the renewable energy industry, has just launched a new Clean energy, job ready programme featuring industry-agreed skills, training, career pathways, and a digital skills passport to support and attract more apprentices and job-seekers to the clean energy industry. This would help close critical skills gaps as Australia transitions to a clean energy future.

The programme will, for the first time, make it easier for job seekers, primarily in Victoria in Queensland, to understand and attain the relevant skills needed to work and seamlessly transition between large-scale wind, solar and storage projects, while helping employers mobilise a safe, competent, and qualified trade workforce.

“One of the greatest opportunities and challenges for the clean energy industry over the next five years is that it will need to recruit an additional 40,000 workers to deliver Australia’s clean energy transition to meet the Government’s renewable energy targets,” said Arron Wood, Clean Energy Council Chief Policy and Impact Officer.

“The Clean energy, job ready program is the result of our close collaboration with industry in Victoria and Queensland to define a common, consistent set of skills and training requirements for clean energy projects. This sector-wide standardisation is key to closing workforce gaps, and accelerating our shift to a green economy,” Wood noted. 

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RCP-EDR T

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.

www.rcpat.com

+44 (0)1224 798312

sales@rcpat.com

BRENT OIL PRICES Over The Years TODAY $67.22

1

Community

YEAR AGO

1 Year Ago (August 2024): Oil prices fell, with Brent settling at its lowest since January, after data showed the U.S. economy added fewer jobs than expected and weak Chinese economic data added pressure. Falling manufacturing activity in China raised concerns about demand growth after June data showed imports and refinery activity lower than a year prior.

5

YEARS AGO

5 Years Ago (August 2020) Greenpeace activists from Germany launched a protest in the North Sea to call out Shell’s plans to abandon an estimated 11,000 tonnes of oil in the sea. According to the group, their ship approached the 500m exclusion zone of Shell’s platforms in the Brent oil field, off the Shetland Islands, with protestors on board waving banners calling on Shell to clean up their mess.

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10

YEARS AGO

10 Years Ago (August 2015): The price of Brent fell nearly 4%, taking a mighty toll on companies in the sector. It was suggested that even if prices doubled it would continue to fall a long way short of filling the hole in Scotland’s public finances. Big companies such as BP, Shell, and Wood Group’s profits were much lower, leading them to shed thousands of jobs.

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OGV.ENERGY sales@ogvenergy.co.uk NEWS / MAGAZINE / EVENTS / JOBS / PODCASTS

ENERGY PROJECTS MAP

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Energy projects and business intelligence in the energy sector

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

The EIC is the leading Trade Association providing dedicated services to help members understand, identify and pursue business opportunities globally.

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

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

Energy Projects Map

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Equinor ASA NO-4035 Stavanger Norway Telephone +47 51 99 0 0 0 0 www.equinor.com

www.ogv.energy I August 2025

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ENERGY PROJECTS MAP 1

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CYPRUS

GHANA

SURINAME

TANZANIA

EXXONMOBIL

ENI

Petronas

ARA PETROLEUM

$500 Million

$1 BILLION

Following an appraisal drilling campaign on the Akoma and Eban discoveries, Eni has submitted a Declaration of Commerciality to the government. The discoveries are expected to be developed as subsea tie-backs to the John Agyekum Kufor FPSO.

Following the final investment decision being taken in December, contracts have been formally awarded.

TechnipFMC has been awarded a contract to supply Subsea 2.0 production systems for the project, while a consortia led by Saipem has an EPCI contract for risers, flowlines, subsea umbilicals and associated subsea structures.

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$250 Million

BLOCK 52 EXPLORATION DRILLING CAMPAIGN

EBAN OIL DISCOVERY

PEGASUS GAS DISCOVERY

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$1 BIllion

NTORYA GAS FIELD China Petroleum Pipeline and China Petroleum Technology & Development Corporation have been awarded an EPC contract for the construction of the 35km gas pipeline from the Ntorya field to the Madimba gas processing plant.

Petronas has started drilling the Caiman-1 exploration well in Block 52. The country’s environmental regulator Nationale Milieu Autoriteit (NMA) had issued a favourable decision around mid-June 2025. The drilling activities are supported from a shore base in Paramaribo and logistics service provider Blue Water Shipping is involved in supporting the operations.

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NORWAY

INDONESIA

MALAYSIA

NORWAY

Equinor

Prima Energi

PTTEP

Equinor

$800 Million

$1 Billion

FRAM SOUTH CLUSTER DEVELOPMENT

ANDE ANDE LUMUT OIL FIELD

Equinor has announced the project’s FID and PDO submission to the Norwegian government.

The project’s concept design encompasses a subsea development utilising 4x4 subsea templates and all-electric Christmas trees. Initial plans include twelve wells for start-up, with four additional slots reserved for future development within the project area. Aker Solutions has been awarded the EPCIC contract for modifications to the topside of the Troll C platform, as well as services for the new subsea template for the project.

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The FEED work for the project is expected to be completed

by August 2025. Additionally, the project is scheduled for completion in October 2027 with peak production targeted for 2028.

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NAMIBIA

Finder Exploration Pty Ltd

Rhino Resources Ltd

KUDA-TASI & JAHAL OIL FIELDS

Finder has formed an alliance with SLB to fast-track the development of the Kuda Tasi and Jahal oil fields (KTJ Project). The completion of key drilling and subsea FEED components is now expected to be delivered one year ahead of schedule. Under the accelerated FEED agreement, the work will cover a range of technical domains, including subsurface, well construction, reservoir, SPS, and SURF.

BLOCK SK 410B – PAPRIKA GAS DISCOVERY

$500 Million

CAPRICORNUS OIL DISCOVERY

Rhino is targeting an exploration well in the Volans prospect instead of further appraisal of Capricornus. The Volans-1X well will be drilled by the Deepsea Mira semisubmersible rig. The well is anticipated to spud between the end of July and the beginning of August, with 52 to 55 days of drilling activity. If successful, Rhino could move its development forward first, instead of the current project.

JOHAN SVERDRUP DEVELOPMENT PHASE III

Equinor has announced the project’s sanction. Additional contracts, including platform modifications and the drilling of eight wells, are anticipated to be awarded in 2025.

Furthermore, notification to the authorities has been submitted following the existing plan for development and operation (PDO), subject to government approval.

The development of these discoveries will follow a cluster development approach involving the Sirung, Chenda, Paprika, and Dokong fields that is collectively known as PTTEP’s Malaysia Greenfield project. PTTEP is currently working towards achieving a FID, which is expected to be reached in Q4 2025 or Q1 2026.

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EAST TIMOR $250 Million

$1.2 Billion

$100 Million

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CONGO (BRAZZAVILLE) $200 Million

Perenco

KOMBI 2 PLATFORM PROJECT

Perenco has announced the construction of the Kombi 2 platform in the Netherlands at the Nieuwdorp shipyard, with work being conducted

by Dixstone. The unit is anticipated to leave the country in October 2025, and to be operational in Congo in Q1 2026. Perenco estimates the construction and upcoming drilling phases will see an investment of over USD$200m.

WORLD PROJECTS SPONSORED BY

BRAZIL

$180 Million

Brava Energia

KOMBI 2 PLATFORM PROJECT

Brava has awarded McDermott an offshore transportation and installation (T&I) contract for the Papa-Terra and Atlanta Phase 2 projects. The contract entails the transportation and installation of flexible pipelines, umbilicals and associated subsea equipment for two new wells at the Papa-Terra field and two new wells for the Atlanta Phase 2 development.

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DRILLING & WELLS

The Importance of Drilling and Wells in Energy Supply Upstream companies are focusing their exploration efforts on lower-cost and lower-risk infrastructure-led exploration prospects amid volatile commodity prices and many uncertainties about the global economy this year.

By Tsvetana Paraskova

www.ogv.energy I August 2025

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Infrastructure-led exploration (ILX) has soared in rece nt years in many maturing offshore basins, while the UK government has restarted the approval process for already licensed oil and gas fields under new guidance for environmental impact assessments.

Offshore developers will now be able to submit their applications for consent to develop already-licensed oil and gas fields—a process which has been on pause since the Finch Supreme Court judgment last year.

The Supreme Court’s landmark ruling from 2024 means that UK North Sea operators for the first time are required to consider the impact of burning the extracted oil and gas in environmental impact assessments.

Near-Field Exploration Drilling Thrives Volatile commodity prices and tightened budgets have prompted many exploration and production (E&P) companies to focus on low-risk, low-cost near field or infrastructure-led exploration (ILX) prospects instead of expensive, high-risk exploration plays, independent research and energy intelligence company Rystad Energy said in a recent report.

Norway, Indonesia, and the US will emerge as ILX hotspots this year, according to Rystad Energy analysis.

“The surge in ILX activity reflects a strategic push for cost-effective resource recovery, signaling a dynamic year ahead for nearfield exploration,” Aatisha Mahajan, Vice President, Exploration Research, Rystad Energy, said in April.

Unlike greenfield projects that require significant capital for standalone infrastructure, ILX benefits from lower development costs, shorter lead times, and reduced emissions. The strategy has so far proven to be a success, according to Rystad Energy. The last five years saw nearly 900 ILX wildcat wells drilled, with a 42-percent exploration success rate over this period, significantly exceeding the global exploration success rate of 32 percent.

“With strong success rates and substantial resource additions, ILX drilling is vital for sustaining production and maximizing infrastructure use,” Mahajan noted.

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

UK Restarts Approval Process for Licensed North Sea Fields New UK government guidance, published in June, will ensure the full effects of fossil fuel extraction on the environment are recognised in consenting decisions. It sets out how environmental impacts of oil and gas should be assessed, providing a clear way forward for the industry.

“When deciding on an application, the Energy Secretary will consider the significance of a

project’s environmental impact, while taking into account and balancing relevant factors on a case-by-case basis - such as the potential economic impact and other implications of the project,” the UK government said.

The leading representative body for the UK offshore energy sector, Offshore Energies UK (OEUK), welcomed the restarting of the approval process, adding that the new guidance is “an important step in ensuring the responsible production of oil and gas produced in UK waters, alongside the acceleration of homegrown renewables.”

This guidance comes at a pivotal moment for the UK economy and its North Sea energy sector, as the government prepares to make major decisions on the future of the oil and gas fiscal regime and licensing, OEUK said.

“The publication of this guidance enables firms to move ahead with the process to responsibly develop projects that add jobs and value to the UK economy and boost energy security,” commented OEUK Chief Executive David Whitehouse.

“It’s important that firms and their people can plan ahead and make investments in UK oil and gas projects critical to our economic and industrial future.”

With the current high volumes of well P&A activity, I encourage operators to offer field trials to progress innovation and make the most of the savings on offer.”

While working on technology to make decommissioning more efficient, operators in the North Sea also have a chance to maximise the value and production from existing assets, the NSTA said in its Overview 2025 earlier this year.

NSTA analysis has shown that there is an opportunity to secure cheaper, easier, and cleaner production by restarting production from existing wells which have been shut-in or are underperforming, the regulator said.

Operators could focus on well intervention, which currently accounts for 7 percent of total oil and gas production in the UKCS. There is a big opportunity to maximise existing assets with an increase in intervention activity, the NSTA said.

For well intervention, the estimated cost of intervention work is about £12 per barrel, according to NTSA’s analysis.

Infill drilling on existing licences can yield additional production, but NSTA forecasts show a decrease in spend out to 2030.

New Technology Could Cement UK as Well Decommissioning Leader

The regulator also notes that deployment of technologies designed to boost production, aid decommissioning, and cut emissions has increased in the UK North Sea.

Operators in the UKCS have rolled out in recent years smart decommissioning technologies, helping the sector build its reputation for innovation and cost-efficiency, the North Sea Transition Authority (NSTA) said at a showcase event early this year.

Technologies were used 1,250 times in 2023, up from 1,200 in 2022 and 1,080 in 2021, according to the latest Technology Insights Report from the NSTA.

While progress is being made, many more technologies are waiting for all-important field trials, attendees at the event heard.

The event aimed to raise awareness of the technologies and encourage operators to facilitate more field trials every year.

Technologies included alternative materials with the potential to create barriers in the well, such as resins, polymers, and bismuth, and logging and perforating tools designed to make the plugging and abandonment (P&A) process more efficient.

Around 1,500 wells will be due for decommissioning in the UKCS between 2026 and 2030. This would be a golden opportunity for industry players to test innovative well P&A technologies, demonstrating how they can save operators time and money, the NSTA said.

“In the UK, we’re fortunate to have a supply chain which consistently produces ground-breaking technologies for offshore operations, including well decommissioning,” commented Carlo Procaccini, Chief Technical Officer at the NSTA. “However, the full potential of this innovation can only be unleashed if suppliers are given a chance to show what they can do in the field.

According to a survey of 50 UKCS operators in the report, there was strong evidence of a continuing focus on technologies for the effective and cost-efficient development of remaining hydrocarbon resources, complemented by efforts to reduce emissions.

Over half of the technologies, 60 percent, are being sourced directly from vendors and/or suppliers and this trend continues to increase, the report found.

UKCS operators used technologies to support well intervention work, including a high-pressure, high-temperature “storm choke” for reactivating shut-in wells whose safety valves had failed. They also saved vessel time by using real-time slickline, a type of cable which can operate various tools for checking and enhancing the condition of wells in a single run.

“The North Sea has an established reputation as a world-renowned testbed for groundbreaking technologies which can help solve challenging industry problems, and the rising uptake of these, once proven, offers significant benefits to end users,” NSTA Technology Manager Ernie Lamza said.

“It is encouraging that operators and suppliers continue to invest and work together on the deployment of many hundreds of innovative solutions.” 

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THEME

Engineering Excellence at Depth: Stena Drilling Leads with Integrated MPD Solutions.

In late July, Stena Evolution drillship completed operations on the King Embayment well in the US Gulf, helping achieve a major operational milestone for Stena Drilling.

This celebrated milestone comes nearly eight years to the day since Stena Drilling commenced its very first MPD well, drilled on August 1st, 2017, aboard the Stena Carron offshore Guyana. That inaugural operation utilised a purely Surface Backpressure (SBP) technique and laid the foundation for a strong and enduring collaboration between Stena Drilling and our client, a multinational energy corporation. Since then, the partnership has yielded an impressive 37 MPD wells across multiple MPD-capable rigs worldwide.

T

he well was the fourth to be drilled using the rigs CML+ system, an advanced Managed Pressure Drilling (MPD) system which incorporates both Controlled Mud Level (CML) and Surface Backpressure (SBP) capabilities, enhancing safety and precision in pressure control.

More significantly however, the project also marked a corporate milestone—delivery of Stena Drilling’s 50th MPD well globally. Given the relative size of Stena Drilling’s fleet this accomplishment places the company as one of, if not the most prolific deepwater MPD Drilling Contractor in the industry, highlighting its leadership in applying MPD techniques to help its clients achieve best in class well construction through optimised well design, heightened well control, reduced operational risk, and operational efficiency in increasingly complex offshore environments.

www.ogv.energy I August 2025

Beyond this key alliance, Stena Drilling has also executed MPD operations for major international operators worldwide. These projects have spanned multiple continents and operational environments, collectively contributing to the company’s achievement of 50 MPD wells—a milestone that represents over 4,000 MPD well days delivered across its global fleet.

This growing adoption of Managed Pressure Drilling (MPD) techniques—particularly Surface Backpressure (SBP)—amongst Stena Drilling’s clients and within the wider deepwater sector has been significantly influenced by the ‘OwnerOperated’ MPD model which Stena Drilling has helped pioneer. Under this approach, the drilling contractor assumes full ownership and operational responsibility for the specialist MPD equipment, representing a departure from the traditional model where operators would engage third-party MPD service providers.

This fully integrated service model has not only delivered substantial cost and operational efficiencies for clients, but— critically—it has also enhanced both personal and process safety. By streamlining interfaces and maintaining tighter control over MPD systems, Stena Drilling has helped reduce safety risks to the lowest practicable levels, setting a new benchmark for safe and efficient deepwater drilling operations.

The progression from delivering a single MPD well to achieving a fleet-wide total of 50 has been the result of sustained collaboration among multiple stakeholders—including equipment OEMs, major Operators, and Stena Drilling’s onshore and offshore teams.

Together, they have worked to overcome the technical and operational challenges of embedding a highly specialised drilling service into a rig environment traditionally governed by well-defined, rigid service boundaries.

Arguably the most significant achievement of this journey has been the successful redefinition of the Drilling Contractor’s role—expanding it to safely and efficiently incorporate the complexities of MPD operations. This required not only the installation of new and sophisticated equipment on board the rigs, but also the development of new operational procedures to ensure safety, reliability, and performance.

Rig crews were entrusted with expanded

DRILLING & WELLS

These examples underscore the transformative potential of MPD in enhancing well economics, reducing risk, and enabling successful outcomes in some of the world’s most demanding drilling environments.

responsibilities, and where necessary, new crew positions were introduced to ensure comprehensive support and integration of the MPD system across all phases of operation.

In particular, Stena Drilling’s creation and investment in the MPD Toolpusher position has provided a knowledgeable focal point able to create cohesion between the traditional drilling responsibilities of the drilling contractor and these newer MPD responsibilities.

The success of MPD utilisation has also been driven by forward-thinking Operators who have recognised the strategic value of the technology and actively pushed its application to deliver increasingly complex wells. By leveraging MPD techniques, these Operators have been able to streamline well designs— reducing casing requirements, minimizing material usage, and, most importantly, saving valuable rig time in reaching total depth.

In one early example, an Operator eliminated the need for a contingency liner by using MPD, achieving cost savings of over $5 million inclusive of material costs and rig time saved. In another case, while drilling through a notoriously loss-prone formation, the rig team faced downhole losses exceeding 200 barrels per hour. With rapid application of MPD methods, losses were reduced to zero, and drilling resumed within 30 minutes—a scenario that might otherwise have led to weeks of non-productive time.

Adoption of the ‘OwnerOperated’ model has helped drive accelerated innovation and performance improvement within the MPD field. Through close collaboration with the original equipment manufacturer (OEM), Stena Drilling successfully established a fully equipped Bearing Assembly maintenance workshop onboard the rig. This initiative included comprehensive training programs to upskill crew members, enabling them to perform all required maintenance tasks independently. By transitioning from a traditional rental and remotely maintained model to owning and servicing its own RCD Bearing Assemblies in-house, Stena Drilling significantly enhanced its operational autonomy. The outcome of this strategic shift has been a marked improvement in system reliability, with a tenfold reduction in failure rates and a substantial increase in equipment uptime—further reinforcing the value of inhouse capability and integrated rig services.

Stena Drilling’s latest advancement in Managed Pressure Drilling (MPD) is the successful deployment of a fully integrated MPD system aboard Stena Evolution drillship.

Mobilised to the US Gulf in April 2024, the vessel began a five-year contract with a major energy company. Unlike previous Stena Drilling Surface Backpressure (SBP) systems— Stena Evolution combines SBP and Controlled Mud Level (CML) capabilities. This advanced system is one of only two currently in operation across the global offshore industry.

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under a single, integrated agreement. This milestone not only redefines service delivery expectations but also reinforces Stena Drilling’s leadership in pioneering safe, efficient, and innovative deepwater MPD solutions.

Over the course of Stena Evolution’s five-year campaign in the Gulf of America, the majority of wells are expected to utilise Controlled Mud Level (CML) technology. This continued application will significantly contribute to the year-on-year growth of Stena Drilling’s Managed Pressure Drilling (MPD) well count. In parallel, the company has a strong pipeline of Surface Backpressure (SBP) MPD projects planned across its DrillMAX series fleet, further accelerating deployment across multiple assets.

This combined growth strategy reflects not only increased operator confidence in MPD technologies and Stena Drilling’s ability to deliver them but also the tangible benefits realised through operational experience and technical innovation. The integration of advanced pressure control systems, supported by highly trained personnel and efficient onboard processes, positions Stena Drilling to deliver its next 50 MPD wells at a substantially faster rate than the initial milestone. This momentum underscores the company’s leadership in MPD-enabled drilling and its commitment to advancing performance in complex offshore environments.

Stena Drilling’s unwavering commitment to delivering a world-class Managed Pressure Drilling (MPD) service across its fleet has firmly established its reputation among major operators as a premier MPD-capable drilling contractor. Through continuous innovation, technical excellence, and a forward-thinking approach, Stena Drilling consistently pushes the boundaries of what’s possible—cementing its position at the forefront of next-generation deepwater drilling technology. 

The technology is instrumental in helping our client deliver high-performance development wells in the US Gulf, from spud to completion.

Notably, the contract structure itself is an industry first for a CML system: Stena Drilling provides the complete CML+ service within its ‘Owner-Operated’ model—including equipment, personnel, and consumables—

Maximum Safety & Operational Excellence For more information visit www.stena-drilling.com

THEME

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McGregor Consultants – Global Talent Solutions for Drilling, Wells & Beyond Since 2008, Aberdeen-based McGregor Consultants Ltd has delivered expert recruitment and contracting solutions to the global oil, gas, and renewables sectors. The company has grown from a two-person outfit to a globally recognised recruitment partner, trusted on some of the industry’s most technically demanding projects.

Core Strength: Drilling & Well Engineering With over 60 years of combined team experience, drilling and wells remains our core focus. We provide specialist personnel across drilling, completions, HSE, contracts, logistics, materials, and cost roles worldwide. Our in-depth knowledge of the market allows us to act not only as recruiters but as a valued source of insight—

keeping our clients connected to industry movements and project opportunities.

Contracting with Confidence We manage LTD and PAYE contractor placements with full support on IR35, legislation, and compliance. Our secure, reliable finance team ensures timely payments and tailored service. In 2024, we reached a record number of active payroll contractors— testament to our trusted, full-service offering, which includes contracts,logistics, visas, and flights.

Permanent & Executive Recruitment Our approach to permanent hiring is qualitydriven—we focus on cultural fit, technical ability, and long-term success. We’ve built a

reputation for placing senior professionals into key staff positions, with a deep understanding of client expectations.

Our executive search practice, led by Jo McGregor, delivers discreet, informed recruitment for C-suite and director-level roles across the globe.

We don’t just fill roles—we form partnerships.

Our consultants are supported, our clients are listened to, and our delivery is consistent.

We integrate seamlessly with internal teams, becoming an extension of your organisation with the insight, agility, and care that underpin every project’s success. 

Scan QR to visit our website nrg-group.com/mr-home/

The Pinnacle of Well Engineering & Project Management SUPPORTING PROJECTS AT ALL STAGES OF THE WELL LIFE CYCLE As one of the UK’s largest privately owned independent well management companies, we are experts in providing all aspects of well engineering and project management to our global client base.

Owned and managed by well engineers with over 40 years of experience in the industry Skilled and multi-disciplined team with experience in all types of well projects Drilling, completion, well integrity, intervention & decommissioning Delivery of 160+ projects for 65+ clients since 2012 Operations performed across all phases of the well life cycle Projects delivered in the UK, Australia, Europe, South America & Africa Specialists in Onshore, Offshore, Rig Less, HPHT, Deepwater, High H2S, Geothermal and CCUS

For further information visit: www.zenith-energy.com

UK

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AUSTRALIA

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ABU DHABI

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SENEGAL

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The ISO Certification Journey: How Small Businesses Can Achieve ISO Certification & Keep It For many small and medium-sized enterprises (SMEs), achieving ISO certification marks a significant milestone. It’s a symbol of professionalism, consistency, and global recognition, but more importantly, it signals a business’s commitment to quality, safety, environmental responsibility, or information security, depending on the standard being pursued.

From ISO 9001 for quality management to ISO 14001 for environmental impact, ISO 45001 for occupational health and safety, and ISO 27001 for information security, each standard comes with its own expectations. And for SMEs juggling daily operations, the path to certification, and what follows, can feel daunting. That’s where QHSE Aberdeen come in.

Why ISO Certification Matters ISO standards are structured frameworks developed by the International Organization for Standardization to help organizations improve systems, meet regulatory requirements, and demonstrate excellence to clients and partners. For SMEs, certification can lead to increased client trust, better contract opportunities, and streamlined internal processes.

However, the path to certification isn’t as simple as submitting an application.

It involves understanding the standard’s requirements, adjusting internal processes, documenting practices, training staff, and passing a thorough third-party audit. After certification, companies must maintain these standards through ongoing audits and continuous improvement.

A Phased, Practical Approach Most businesses begin with a gap analysis to assess where current practices fall short of the standard. This step is crucial to understand what documentation, systems, or processes are missing.

From there, organizations typically develop the required documentation: policies, procedures, and manuals tailored to their specific operations. But paper alone doesn’t make a system work. Employees must be trained, processes implemented, and internal audits conducted before facing the formal external certification audit.

What many SMEs find challenging is fitting this into their existing workflow.

That’s where support services from experienced consultants come into play.

The Role of External QHSE Partners Quality, Health, Safety, and Environmental (QHSE) consultancies help companies interpret standards, build tailored systems, and prepare for audits, all while minimising operational disruption. In the North East of Scotland, QHSE Aberdeen has become a recognised name for supporting SMEs through the ISO journey.

Rather than just offering templates or checklists, the consultancy provides fullspectrum support, from initial readiness reviews and bespoke policy creation to staff training, internal audits, and even postcertification maintenance.

Importantly, they function as a dedicated QHSE department for businesses that might not have one. This model is particularly useful for SMEs that need ongoing support but can’t justify a full-time internal hire.

Maintaining the certification also means responding to any changes in the standard itself, training new staff, and keeping risk assessments current. External support ensures businesses stay on track without letting standards slip due to day-to-day operational pressures.

An Outsourced Department with a Proven Track Record QHSE Aberdeen have earned their reputation not only through technical expertise but also through results. With a reported 100% success rate in helping clients pass audits, they provide peace of mind, especially for first-time applicants.

While based in Aberdeen, the company works with clients across various sectors, including nuclear, construction, food & drink, manufacturing, technology, and energy.

Their ability to develop ISO 9001, 14001, 45001, and 27001 Systems — and support their maintenance, has positioned them as a valuable partner in operational excellence.

Balancing Efficiency and Compliance For SMEs, the challenge is always a balance: achieving compliance without losing agility.

ISO certification is sometimes viewed as bureaucratic or overly complex. But with the right guidance, it becomes a framework for better performance, clearer roles, reduced risk, and increased customer satisfaction.

What Happens After Certification?

As more clients and regulators demand certified systems, the incentive to pursue ISO standards only grows. Fortunately, with expert partners to guide the process and maintain systems thereafter, even the smallest certified businesses can stand shoulder to shoulder with larger, competitors.

Gaining ISO certification isn’t the end; it’s the beginning of a continuous improvement cycle. Each certified company must undergo annual surveillance audits to ensure ongoing compliance. This requires updated documentation, evidence of management reviews, and demonstration of improvements.

Note: For businesses seeking ISO certification or support in maintaining compliance, leading industry consultancy QHSE Aberdeen continue to play a crucial role, allowing SMEs to focus on what they do best, while the management system experts ensure their systems meet global standards. 

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THEME

35

J+S Subsea Completes First Offshore Electrical Fault-Finding Job in Australian Waters J+S Subsea is proud to announce a major milestone in its international Expansion — the successful completion of their first offshore electrical fault-finding project in Australian waters. This project not only marks their inaugural deployment to Australia but also highlights their rapid mobilisation capabilities and technical excellence on a global scale.

🇦🇺

T

he job came at short notice from a wellknown vessel operator who required urgent assistance with a critical offshore issue. The client turned to J+S Subsea for their recognised expertise in electrical diagnostics and subsea controls. The team responded immediately, coordinating logistics and personnel across time zones to ensure we could meet the client’s needs with speed, precision, and reliability.

This operation is a prime example of what sets J+S Subsea apart — a combination of deep technical knowledge, a responsive team, and a strong commitment to client success.

Working closely with the client, the offshore team ensured the job was completed efficiently and, above all, safely.

Barry Barbour, a valued member of the J+S Subsea engineering team, was deployed for his first assignment in Australian waters — and judging by the big grin in the project photos, it’s safe to say he embraced the

opportunity! Barry’s expertise and handson approach were key to ensuring the tools were operated effectively and the fault was accurately diagnosed.

technical confidence, and tailored solutions.

At J+S Subsea, they’re proud to be that trusted partner — now with proven capabilities in the Australasian offshore sector.

J+S Subsea in-country Business Development Manager Thomas Hutchinson commented “Despite the short notice, our team stepped up - highlighting both our agility and commitment to growth in the region. The operational challenges in this basin differ greatly from the North Sea, but our ability to offer adaptive solutions positions us well to support operators with fast, fit-for-purpose engineering and controls expertise. This is a key step in expanding our presence in the Australian market”.

This achievement is not just a first for the company geographically — it’s a demonstration of their readiness to take on complex subsea challenges under pressure and deliver results that matter. It also reinforces the company’s strategic growth plan, which includes strengthening their footprint in key international regions, with Australia being a primary focus.

The success of this mobilisation underscores their commitment to providing world-class subsea services, wherever they are needed.

As offshore energy developments continue to expand globally, operators are looking for partners who can respond with urgency,

If you would like to learn more about how J+S Subsea can support your operations, please contact us today www.jands.co.uk

Looking ahead, they’re excited about the opportunities this successful deployment opens up. J+S Subsea are committed to supporting more clients in the region and will continue to build strong, reliable partnerships founded on trust, innovation, and results From our base in Aberdeen to offshore platforms across the globe, J+S Subsea is here to support. 

36

ON THE MOVE

ExxonMobil Names Chairman ExxonMobil has appointed an Australian, Mr. Jagir Baxi, as chairman and managing director of its Nigerian affiliates, including Esso Exploration and Production Nigeria Limited and Esso Exploration and Production Nigeria (Offshore East) Limited.

Baxi will also serve as the lead country manager, succeeding Mr. Shane Harris, who is transitioning to ExxonMobil’s corporate headquarters in Houston, Texas.

He obtained degrees in engineering and science from Monash University and Master of Business Administration (MBA) degree from Melbourne Business School.

The company explained in a statement that his appointment signals ExxonMobil’s continued commitment to developing Nigeria’s vast energy resources through innovation, collaboration, and global expertise.

TenneT Germany appoints BP offshore wind chief Ina Kamps as COO

In his new role, Baxi would be responsible for overseeing the company’s operations and strategic direction in Nigeria.

He expressed his enthusiasm and commitment to deepening partnerships and unlocking growth potential in the country’s oil and gas sector.

Before this appointment, Baxi served as executive director for production across ExxonMobil’s Nigerian operations.

Since joining the company in 1999, he has held several senior leadership positions in deepwater and LNG sectors, with assignments in Australia, Angola, Iraq, Qatar, Papua New Guinea, and the United States. 

Dan McGrail Appointed Permanent CEO of Great British Energy

bp announces nonexecutive director appointment

TenneT Germany has appointed Ina Kamps, most recently head of Offshore Wind Germany at BP, as its Chief Operating Officer (COO).

Experienced energy leader to drive the UK’s flagship public energy company from its Aberdeen headquarters

BP p.l.c. announced the appointment to its board of Simon Henry as a nonexecutive director with effect from 1 September 2025.

Kamps is appointed to TenneT Germany’s executive board with effect from 1 December 2025.

Great British Energy has officially welcomed Dan McGrail as its permanent Chief Executive Officer. His appointment, effective July 8, 2025, marks a seamless transition from his successful interim leadership since March 2025, during which he was on secondment from RenewableUK. McGrail will be based at the organisation’s Aberdeen headquarters, underscoring a strong commitment to locally anchored leadership and the UK’s wider energy transition.

Helge Lund, chair of bp, said: “I am delighted to welcome Simon to bp. The board will benefit from his deep and broad experience of the global upstream and downstream energy industry and his financial and commercial understanding of global markets, together with his extensive and varied board experience.”

As COO, she will oversee TenneT Germany’s operational activities, with a particular focus on grid expansion, both onshore and offshore, as well as grid maintenance and safety.

Following her appointment, the management team at TenneT Germany is now complete.

Alongside Tim Meyerjürgens (CEO), Dr Markus Binder (CFO) and Kathrin Günther (CTO), she will form the four-person Executive Board of Germany’s largest TSO. Kamps was most recently head of Offshore Wind Germany at BP, where she was responsible for the company’s offshore wind activities in Germany.

She brings international experience from the energy sector and is actively involved in associations such as German Offshore Wind Energy Association (BWO), promoting dialogue between industry and politics on issues such as grid connection, infrastructure planning and decarbonisation targets.. 

This appointment builds on the company’s strong governance foundations laid in January 2025, when five highly regarded nonexecutive directors—Frances O’Grady, Frank Mitchell, Kate Gilmartin, Nina Skorupska, and Valerie Todd—joined the start-up board.

Together, this leadership team brings deep expertise in energy policy, infrastructure, and innovation, positioning Great British Energy to deliver on its mission of accelerating domestic clean energy development and supporting the UK’s long-term energy security. 

Simon has wide-ranging expertise and experience in global finance, strategy, governance and management, gained across the energy industry internationally. In a career of 35 years with Shell, he held senior finance and management roles internationally and was chief financial officer and a member of the board from 2009 until 2017.

Simon is currently a non-executive director of Rio Tinto plc and Rio Tinto Limited. Rio Tinto announced in February that he will step down from those roles in the second half of 2025.

Harbour Energy plc announced that Simon will step down from its board with immediate effect. Within the past five years, Simon resigned as a director from Lloyds Banking Group plc and PetroChina Ltd in September 2020 and May 2022, respectively. There are no additional matters that require disclosure under 6.4.8R of the UK Listing Rules. 

For more of the latest appointments visit www.ogv.energy/news/all/appointments >>>

ON THE MOVE Hydraulics Specialist Announces Key Appointments on International Growth Journey

ATPI General Manager Appointment Key to National Growth Goals

ATPI, the global travel management company (TMC), is celebrating several promotions within its Aberdeen team as part of plans to bolster Scottish operations and global customer support.

At the centre of these changes is Nicola Reith, who has been appointed as General Manager, Scotland, progressing from her position as Operations Director, Scotland.

Under Nicola’s leadership, ATPI aims to expand its market share in corporate travel partnerships across diverse industries in Scotland and, ultimately, throughout the UK, with a strong focus on tailored travel solutions for the UK energy sector. Nicola brings eight years of experience at ATPI and over 17 years at FCM Travel Solutions UK and Munro’s Travel Ltd. Her career features senior leadership and management roles where she has driven business growth, improved service quality, and broadened ATPI’s travel offerings. Nicola has also shaped duty of care and wellbeing practices, supporting colleagues and clients with safe, efficient, and effective travel. 

Rathlin Energy Appoints Paul Harris as Independent NonExecutive Director Seasoned energy leader to enhance governance and drive UK gas development strategy

Reabold Resources PLC (AIM: RBD) has appointed Paul Harris as a non-executive director at Rathlin Energy, operator of the West Newton gas project. Harris, with over 35 years’ energy experience, led NEO Energy as COO and CEO, driving major acquisitions and growth that positioned it among the UK’s top producers. 

Credit: NEO Energy

A leading hydraulics specialist has unveiled a raft of key appointments as part of its ambitious plans for international growth.

Following the recent announcement that multimillion-dollar investment is planned to uplevel Saturn Fluid Engineering operations in Australia, Dave Mackay has been appointed to a business development role in the region where the naval defence and oil and gas decommissioning sectors will form the nucleus for the company’s growth.

With the Middle East also pinpointed as a key area for expansion, Anas Ahmad has been employed to lead business development while the appointments of UK-based chief financial officer Scott Davidson, global technical lead Mike Smith and Graham Forrest as the Type 26 Frigate project manager to support Saturn’s contract with BAE Systems on their 8 ship UK Type 26 and their Commonwealth Global Combat frigate build programs will further bolster operations at Saturn’s global headquarters in Dundee and Aberdeen. 

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38

RENEWABLES

Government raises maximum price for wind energy The government has increased the maximum price it is prepared to guarantee companies generating electricity from new wind farms.

She claimed Ed Miliband was putting “Net zero zealotry above the economy or the cost of living”.

The government argues that switching to renewables will protect consumers from volatile gas prices and bring bills down “for good.”

Johnny Gowdy, from not-for-profit group Regen, which advises on transitioning to net zero, said the ASP was about “setting the starting point for the auction; with competitive bids we would expect the actual auction strike price to be much lower” “There is also a trade-off between volume and price. If the bid prices are high then the government will procure less capacity. If the price is low then the government will be able to buy more capacity.”

It comes as ministers are trying to meet challenging pledges to bring down household bills and create an electricity grid that it is almost entirely free of fossil fuels by 2030.

Firms put in bids below the ASP to win project contracts and then the government sets a new guaranteed price, known as the clearing price, based on those.

The Department for Energy Security and Net Zero published the details ahead of the latest auction for government-backed contracts.

If electricity market prices are above the price set, the companies pay the excess back to energy suppliers, with an expectation it should lower bills for consumers.

The auction opens in August and will be one of the last which can deliver projects in time to meet the government’s target of Clean Power by 2030.

The Conservatives have described the new prices for offshore wind as “eye-watering”.

The government said the prices did not represent the final guaranteed amount, as companies will put in lower bids to win contracts.

A spokesperson for Energy Secretary Ed Miliband said “the auction will reveal the true price, just like it did last year, where the auction cleared at prices significantly lower”.

Each year, companies who want to build renewable energy projects bid for government-backed contracts.

The government agrees to pay them a fixed price for the electricity they produce for a set period, now up to 20 years, and up to a maximum price known as the Administrative Strike Price, or ASP.

If prices fall below the guaranteed price the energy suppliers – and customers – pay the companies the difference.

This year, the maximum guaranteed price for offshore wind will be £113 per megawatthour, up from £102 in 2024.

Floating offshore wind, which is a newer technology, is more expensive at £271/MWh, up from £245.

Onshore wind has seen a smaller rise from £89/MWh to £92 while the price for solar energy has come down to £75/MWh from £85/MWh. Conservative Shadow Energy Secretary Claire Coutinho said: “These are eye-watering prices – the highest in a decade and way above the average cost of electricity last year. And this is before the hidden costs of grid, storage and wasted wind which all end up on our energy bills”

More new decommissioning news available @ www.ogv.energy/news/renewables/

www.ogv.energy I August 2025

He says that the cost of producing offshore wind “probably has risen over the past couple of years” but he adds “we will have to wait and see the auction outcome” to find out how much.

Previous auctions have resulted in a clearing price that was lower than the maximum offered.

There is a risk to setting the maximum price too low.

In 2023, under the Conservatives, no offshore wind developers bid for any projects as they said they weren’t viable at the price offered.

The government has made changes to the system in the hope of attracting more bids to create competition.

For the first time this year, offshore wind projects which don’t have yet have full planning permission will be able to apply for a contract.

The contract lengths have also been extended for wind and solar projects from 15 years to 20 and the Energy Secretary will be able to see developer’s bids before he sets the final overall budget.

A spokesperson for DESNZ said its reforms to the system would “enable a competitive auction that secures the best possible price for consumers while securing the clean energy we need to get us off the fossil fuel rollercoaster.” 

READ MORE DECOMMISSIONING NEWS ON OUR WEBSITE

RENEWABLES

39

Iberdrola Powers Ahead with Major Renewable and Infrastructure Investments times. The capital will primarily go toward enhancing electricity grids in the United States and United Kingdom, two priority markets in the company’s international strategy. Grid modernisation remains crucial to supporting clean energy integration and meeting rising demand.

Adding another feather to its cap, Iberdrola and Masdar also celebrated the full commissioning of the 476 MW Baltic Eagle offshore wind farm in the German Baltic Sea, further strengthening the company’s position in European offshore wind.

With strategic alliances, a diversified portfolio, and financial strength, Iberdrola is positioning itself at the heart of the global clean energy revolution—balancing infrastructure, digital innovation, and decarbonisation with scale and confidence.

From offshore wind to digital infrastructure, the Spanish energy giant accelerates its global growth strategy In a period marked by ambitious energy targets and global decarbonisation efforts, Iberdrola is emerging as one of the defining players in the clean energy transition. With a series of high-impact investments across renewables, digital infrastructure, and transatlantic grids, the Spanish utility giant is reinforcing its role not only as a renewable leader but as a multidimensional energy innovator.

On 24th July, Iberdrola and long-standing strategic partner Masdar reached financial close on the East Anglia THREE offshore wind farm in the UK. Valued at £4.5 billion (€5.2 billion), the project represents one of the largest offshore wind transactions in recent history. It will deliver 1.4 GW of clean energy—enough to power more than one million homes. With both companies holding equal 50% stakes and joint governance, the scale and shared commitment reflect the increasing complexity and collaboration required in delivering largescale renewable infrastructure.

Securing £3.6 billion (€4.1 billion) in project financing from a consortium of 23 banks and Denmark’s Export Credit Agency (EIFO), the project is also a testament to investor confidence in the sector. As offshore wind becomes more central to Europe’s energy future, East Anglia THREE cements the UK’s strategic importance within Iberdrola’s global operations.

We are not just building energy infrastructure—we’re building the backbone of a sustainable, digital economy

Fortum Accelerates Nordic Wind Ambitions with Major Project Acquisition

Iberdrola spokesperson

€40 million deal with ABO Energy adds 4.4 GW of onshore wind

projects to Fortum’s Finnish pipeline On 29th July, Iberdrola announced a joint venture with Echelon Data Centres to codevelop next-generation data infrastructure in Spain. Through its specialist subsidiary, CPD4Green, Iberdrola will hold a 20% stake, bringing its expertise in identifying energy-secure locations and delivering 24/7 renewable electricity. Their first project, Madrid Sur, is an expansive 160,000 m² site with a planned 144 MW of processing capacity and a 230 MW secured grid connection—a major step in aligning digital infrastructure with sustainability.

To fund this rapid expansion, Iberdrola successfully completed a €5 billion capital increase on 28th July, oversubscribed by 3.8

Finnish energy company Fortum has made a strategic acquisition to bolster its development pipeline in the Nordic region.

Fortum recently signed an agreement to acquire a wind power project development portfolio from the German renewables developer and constructor ABO Energy.

This acquisition significantly strengthens Fortum’s future renewable power generation capacity, adding approximately 4.4 GW of onshore wind development projects across various stages in Finland. The initial purchase price, on a debt-and-cash-free basis, stands at approximately €40 million, with potential future earn-outs up to €70 million. 

40

LEGAL

Mandatory Identity Verification: Steps companies should take now The Economic Crime and Corporate Transparency Act 2023 (ECCTA) is ushering in a new era of corporate accountability in the UK. Aimed at curbing the misuse of companies by

criminals, one of the Act’s most significant reforms is the introduction of mandatory identity verification (IDV) for company directors and Persons with Significant Control (PSCs).

Paul McLaughlin, Brodies LLP Companies House will eventually display IDV status on the public register, enhancing transparency. ACSPs must also declare IDV completion, which will be publicly visible.

Non-compliance carries serious consequences. Directors acting without verified ID commit a criminal offence, and companies allowing such actions may face penalties. Although unverified directors can still legally bind the company, market practices may evolve to limit dealings with companies lacking ID verified leadership.

To prepare, companies should: - Inform all directors of the IDV requirement and necessary documentation.

The new rules are set to come into force from autumn 2025, requiring all directors of UK companies and overseas companies with UK establishments to have their identity verified to act in their roles. This requirement also applies to new company incorporations—no director can be appointed without prior ID verification. Existing directors must complete IDV before submitting their company’s first confirmation statement after the rules take effect, which is likely to be in autumn 2025.

Initially, IDV status will have to be confirmed for every directorship, but future updates to Companies House systems may streamline this process so IDV status flows automatically to multiple directorships and PSC positions.

The IDV process is designed to be a one-off requirement, although Companies House retains the authority to request re-verification if fraudulent activity is suspected. Failure to comply is a criminal offence, potentially resulting in fines and disqualification under the Company Directors Disqualification Act 1986.

PSCs are also subject to the new IDV rules.

Individual PSCs must verify their identity, and for relevant legal entities (RLEs), such as other

www.ogv.energy I August 2025

UK companies, a designated officer must complete the process. While companies are not responsible for ensuring PSC compliance, full adherence is encouraged. Companies House may issue notices or set deadlines for PSCs to comply during a transitional period.

By 2026, anyone filing documents with Companies House must also undergo ID verification, unless filing through an Authorised Corporate Services Provider (ACSP).

There are two primary routes for ID verification. The first is through Companies House, which offers a free and efficient service for individuals with biometric passports. The process, accessible via the GOV.UK One login system, takes about five minutes and requires an email address, home address, full name, date of birth, and supporting documents such as a biometric passport or UK driving licence. A personal code is issued upon completion, which should be securely stored.

The second route is through ACSPs, which offer broader document acceptance and cater to individuals without biometric passports.

- Identify directors needing ACSP services and arrange verification.

- Encourage early IDV completion.

- If using the Companies House route, ensure directors record and share their personal codes with the relevant internal teams responsible for Comapanies House filings.

- Update HR procedures.

and

company

secretarial

- Notify PSCs of their obligations and identify responsible officers for RLEs. The ECCTA represents a pivotal shift in corporate governance, reinforcing the UK’s commitment to transparency and economic integrity. Companies are urged to act now to ensure compliance and avoid future disruptions. 

Want to know more?

Brodies LLP is a UK top 50 law firm with offices in London and across Scotland. For more legal insight and details of our energy expertise visit brodies.com.

INNOVATION AND TECHNOLOGY

41

SPONSORED BY

The UK’s largest innovation funding consultancy Leyton is an international consulting firm that helps businesses leverage financial non-dilutive incentives to accelerate their growth and achieve long lasting performance.

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

LEYTON.COM and resolve problems swiftly. Continuous monitoring of well pressure and temperature means operators can ensure their oil fields function smoothly even in the most challenging environments. No more sending teams into dangerous conditions to collect data that can now be gathered continuously and automatically.

Autonomous Drilling: The Future of Drilling Operations Article by Benson John MSc CEng MIMechE

P

icture this: A massive drilling rig operates thousands of feet underground with surgical precision, guided not by a human hand but by intelligent systems that can “see” dangers before they happen. What sounds like science fiction became reality in July 2024 when Romania deployed its first “robotic rig.”

Just months later, Norway took it even further.

In February 2025, something remarkable happened on the Norwegian Continental Shelf. With the simple push of a button, operators launched the world’s first fully integrated automated drilling system. This was not just a remote control but a complete orchestration of autonomous directional drilling that could optimise drilling parameters in real-time while keeping operations safely within predetermined boundaries.

The system represents a dramatic shift from the days when drilling crews had to brave treacherous conditions, manually inspecting wells in environments that could turn deadly in seconds. Today’s autonomous rigs entirely eliminate human exposure to hazardous zones, transforming one of the world’s most dangerous jobs into a safer, precise operation.

The transformation is happening faster than anyone expected. Traditional rig selection based on basic parameters has been completely revolutionised. Modern operations now focus on performance-driven criteria like rig mobility and tripping speed, slashing

both drilling costs and environmental impact.

These next-generation rigs operate with significantly reduced crew requirements while incorporating automated pipe handling and smart mud systems. Real-time tracking of tubulars, the massive pipes that form the well’s backbone, requires redesigned steel structures and advanced sensors that enable control precise enough to navigate underground formations with pinpoint accuracy.

At the heart of these systems lies the most fascinating innovation: digital twin technology.

Think of it as creating a perfect virtual replica of the entire drilling operation, complete with hydraulic, thermal, and mechanical models that mirror every aspect of the real-world process. These digital doubles continuously calibrate themselves using real-time data, maintaining model accuracy that would have been impossible just a few years ago. The system compares the ideal behaviour of the digital twin with actual behaviour observed from downhole and rig sensors, generating real-time diagnostics that can spot potential problems before they become disasters.

The benefits extend far beyond keeping workers safe, though that alone would justify the technology. Remote monitoring has proven dramatically more cost-effective than traditional manual techniques, while real-time data accessibility enables companies to make informed decisions that maximise output

The Halliburton and Sekal deployment for Equinor showcases what’s possible when these systems work in harmony. Their breakthrough system incorporates intelligent safeguards through real-time advanced modelling of subsurface conditions, wellbore fluids, and pressure systems, creating a safety net that thinks ahead. This is not theoretical anymore. Companies are already analysing historical drilling data to predict optimal parameters for new wells, maximising penetration rates while minimising equipment wear and environmental impact. The technology can now identify the perfect balance between speed and sustainability.

What makes this revolution truly compelling is not the technology itself, but how it changes human lives. Engineers who once faced life-threatening conditions daily now work in comfortable control centres, using their expertise to guide operations from safety.

The industry is attracting a new generation of tech-savvy professionals who bring fresh perspectives to age-old challenges.

This transformation represents more than technological advancement; it fundamentally reimagines how we approach energy extraction. The industry is moving toward operations that are not just safer and more efficient, but also more environmentally responsible. As these systems continue evolving, we are witnessing the emergence of an industry that balances energy needs with sustainability goals in ways previous generations could only dream of. The journey toward fully autonomous drilling operations is not just changing how we extract oil and gas; it’s redefining what’s possible when human ingenuity meets cutting- edge innovation.

The future of drilling is not just autonomous, it’s here, operating right now beneath our feet, proving that sometimes the most revolutionary changes happen not with a bang, but with the quiet precision of a button push. 

For more information visit: leyton.com

42

CONTRACTS SPONSORED BY

Transocean Scoops $199M in Second Quarter Drilling Rig Deals Offshore drilling contractor Transocean has secured four new contracts and extensions for its semisubmersible rigs and drillships during the second quarter of 2025, worth approximately $199 million.

Subsea 7 wins new Equinor contract for North Sea development Offshore engineering and services provider Subsea 7 has secured a contract for work on Equinor’s Fram Sør development project, locatedoffshore Norway.

The project’s work scope encompasses engineering, procurement, construction, and installation of subsea structures and flowlines, including 53 km of production, gas lift, and water injection lines. It also includes the installation of the umbilical system.

It follows the award of a contract for front-end engineering and design in January, which finalised the technical definition of the development.

Engineering and project management will begin immediately in Subsea 7’s offices in Norway and the UK. Offshore installation activities are expected in 2026, 2027, and 2028.

The exact financial details of the deal were not revealed, but the company did describe it as a large contract, which puts it in the $300m to $500m range.

The Fram Sør area is located 10-30 km north of the Equinor-operated Troll C platform, some 70 km northwest of Bergen. The Fram Sør project will be connected to the existing Fram and Troll C infrastructure.

During the quarter, Transocean secured a contract extension with Equinor, which exercised a two-well option for Transocean Spitsbergen semi-submersible drilling rig for work off Norway, at the dayrate of $395,000.

Transocean also reported that an unnamed customer exercised two one-well in Australia for the Equinox semi-submersible drilling rig, at a dayrate of $540,00.

As for the drillships, Transocean secured a three-well contract in Ivory Coast with Murphy Oil for Deepwater Skyros drillship, which also includes a one-well option at a dayrate of $361,000. The drillship is currently on contract with TotalEnergies in Angola until September 2025, while the Murphy Oil contract is scheduled to run from December 2025.

Also, Transocean signed a 60-day contract extension with Petrobras for its Deepwater Mykonos drillships, with options up to an incremental 120 days.

The aggregate incremental backlog associated with the contracts and extension is approximately $199 million, Trasocean said, adding its total backlog as of July 16, 2025, is approximately $7.2 billion. 

www.ogv.energy I August 2025

The contract is subject to the approval of a plan for development and operations. 

CONTRACTS

43

TechnipFMC Partners With Equinor to Enhance Heidrun Field TechnipFMC plc FTI, a Houston, TX-based oil and gas equipment and services company, has been awarded a significant integrated Engineering, Procurement, Construction, and Installation (iEPCI) contract by Norway-based integrated oil and gas company Equinor ASA EQNR for the Heidrun extension project located in the Norwegian North Sea. This award, which is classified as “significant” by TechnipFMC, is valued between $75 million and $250 million.

This lifecycle extension project not only leverages TechnipFMC’s subsea expertise but also affirms Equinor’s strategic commitment to maximizing the value of existing infrastructure in the North Sea. As operating fields age, technological innovation and precision engineering become indispensable for sustaining production efficiency and safety standards.

This prestigious award was recorded as part of TechnipFMC’s inbound orders for the second quarter of 2025, further reinforcing the company’s growing influence in one of the world’s most mature offshore oil and gas regions.

Optimized Design Through Integrated iFEED and iEPCI Execution Before the official contract award, TechnipFMC undertook a Front-End Engineering and Design (iFEED) study in close collaboration with Equinor. This early-phase engagement enabled a holistic and optimized subsea layout, addressing technical complexities while minimizing lifecycle costs. The transition from iFEED to full iEPCI scope exemplifies TechnipFMC’s ability to seamlessly integrate conceptual design with execution, setting a new benchmark for project delivery in subsea engineering.

Jonathan Landes, president of Subsea at TechnipFMC, emphasized the importance of early collaboration, noting that the direct contract showcases the benefits of joint efforts in achieving an optimized field design.

Landes expressed eagerness to apply the iEPCI integrated execution approach to enhance this vital asset for Equinor. His statement highlights the strength of TechnipFMC’s integrated model in delivering value-driven solutions that align with client goals.

Enhancing Heidrun’s Production Lifecycle and Subsea Infrastructure The Heidrun platform, operational since 1995, plays a critical role in Norway’s offshore oil production. By extending the platform’s production lifecycle, this new project supports long-term energy output while maximizing recovery from a mature field. The scope of work includes the design, procurement, fabrication and installation of subsea infrastructure that will tie back to existing assets, reducing environmental impact and capital expenditure.

TechnipFMC’s Proven iEPCI Model Delivers Efficiency and Cost Certainty TechnipFMC’s integrated approach — combining engineering, procurement, construction and installation — has become a cornerstone of its value proposition.

The iEPCI model simplifies execution by eliminating interface risks and delivering streamlined project management under a single contract. This methodology has proven to significantly reduce lead times and capital costs compared with traditional fragmented contracting models.

By offering a one-stop subsea solution, TechnipFMC ensures faster project turnaround, optimized resource allocation and lower total cost of ownership for its clients.

These advantages are particularly beneficial in high-cost environments such as Norway’s Continental Shelf, where efficiency gains translate into substantial economic benefits.

Strategic Collaboration Between TechnipFMC and Equinor The longstanding partnership between TechnipFMC and Equinor continues to evolve, driven by shared values of innovation, efficiency and environmental responsibility.

This latest contract builds on a series of successful collaborations, with both companies leveraging digital technologies and integrated project strategies to improve operational outcomes.

The award for the Heidrun extension reflects Equinor’s confidence in TechnipFMC’s technical capability and project delivery performance. The companies’ ability to align on long-term field development strategies demonstrates a model for sustainable subsea operations in a rapidly changing energy landscape.

Driving Innovation in Subsea Engineering TechnipFMC remains at the forefront of subsea engineering innovation, continuously

advancing its technology portfolio to support complex offshore projects. From advanced ROV systems and modular manifolds to cutting-edge digital twins and real-time data analytics, the company is redefining subsea operational excellence.

This contract showcases the strength of TechnipFMC’s integrated solutions and its capacity to deliver high-performance subsea systems in technically demanding environments. The deployment of cuttingedge technologies in the Heidrun extension will enhance field recovery, reduce emissions and extend the asset’s lifespan.

Key Milestone in TechnipFMC’s 2025 Strategy The Heidrun project award is a vital addition to TechnipFMC’s 2025 strategic roadmap.

By securing high-value contracts across core markets, the company is reinforcing its financial resilience and accelerating growth in integrated subsea services. The order intake from Equinor also supports TechnipFMC’s goal of expanding its project backlog and maintaining a robust pipeline of long-term revenues.

As global energy demand shifts and decarbonization targets intensify, TechnipFMC is uniquely positioned to support operators with low-carbon, cost-efficient subsea solutions.

The Heidrun extension further validates TechnipFMC’s role as a trusted partner in energy transition strategies, delivering projects that balance production sustainability with environmental stewardship.

Conclusion: Elevating Subsea Excellence Through Strategic Execution The significant iEPCI contract awarded to TechnipFMC by Equinor for the Heidrun extension project marks a key moment in subsea field development in Norway’s North Sea. It demonstrates the effectiveness of early collaboration, the power of integrated execution and the value of long-term partnerships in the energy sector.

With its iEPCI model, TechnipFMC continues to redefine how subsea projects are conceptualized, engineered and delivered, making it a global leader in the offshore oil and gas industry. As the company executes this project, this will not only reinforce its technical credibility but also strengthen the commitment to delivering transformative subsea solutions for a sustainable energy future. 

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DECOMMISSIONING Addressing the Legacy of Abandoned Oil and Gas Wells in UK Waters The United Kingdom faces a significant challenge with the increasing number of abandoned oil and gas wells in its waters, particularly in the North Sea. These wells, often relics of past energy extraction, pose environmental risks and require substantial effort and investment for proper decommissioning.

A primary concern is the potential for methane emissions from these inactive wells.

Studies indicate that a considerable number of abandoned offshore wells in the North Sea could be releasing thousands of tonnes of methane annually. Methane, a potent greenhouse gas, contributes significantly to atmospheric warming. Alarmingly, these emissions are not consistently monitored by regulators or operators, leading to a critical regulatory gap. Research suggests that a substantial portion of the leaking methane from these offshore wells ultimately reaches the atmosphere.

The scale of the decommissioning challenge is considerable. The North Sea energy industry is striving to seal approximately 200 abandoned wells each year to meet targets. However, fluctuating tax regimes are introducing economic and fiscal uncertainties, which can impede the pace of these essential activities. Decommissioning is recognised as a central component of the broader energy transition, highlighting the importance of cross-sector collaboration and information sharing to ensure successful and efficient operations.

Beyond offshore sites, the UK also has over 2,000 onshore deep wells, with roughly two-thirds already decommissioned. While current reports do not indicate widespread groundwater pollution from these sites, there is some evidence of limited methane

www.ogv.energy I August 2025

emissions into the air. Studies on onshore well integrity have yielded varied results, with more recent assessments sometimes contradicting earlier findings regarding methane leaks.

The regulatory framework plays a crucial role in managing these assets. Authorities like the UK Government’s Oil and Gas Authority (OGA) issue directives for well abandonment, as seen with the shale wells at Preston New Road. Comprehensive guidelines are in place for well suspension and abandonment, emphasising the need to prevent any unplanned escape of fluids and requiring specific permits for such operations.

Looking to the future, there are innovative proposals for repurposing abandoned wells.

Initiatives such as the Net Zero Rise project explore the use of exhausted boreholes as test sites for carbon capture and storage (CCS) technologies, as well as for geothermal and hydrogen energy development. This approach not only addresses the environmental legacy of these wells but also offers a more costeffective alternative to drilling new ones, aligning with the UK’s broader objectives for cleaner energy.

The management and decommissioning of abandoned oil and gas wells represent a complex, long-term endeavor that requires sustained effort, robust regulation, and innovative solutions to mitigate environmental risks and potentially contribute to the UK’s future energy landscape. 

Allseas vessels complete work for two Aker BP development projects in the North Sea The Pioneering Spirit vessel completed heavy-lift removals for the Valhall project, and the Solitaire vessel finished pipelaying work for the Yggdrasil development.

Allseas’ Pioneering Spirit vessel completed the final heavy-lift removals in late June for Aker BP for the original Valhall Field center in the southern Norwegian sector of the North Sea. For the Original Valhall Development & Hod Decommissioning Project, the vessel removed the 9,500-mt PCP jacket and 5,000mt Hod A platform.

Allseas’ team employed a specially designed “fishing rod” to hook conductor sections 28 m underwater using repurposed pipelay strakes; the goal was to achieve the single-lift execution in rough weather conditions.

Farther north, the company also just finished pipelay duties for the Aker BP-operated Yggdrasil development in the Norwegian North Sea, with the Solitaire vessel installing 122 km of offshore oil and gas export pipelines.

According to Allseas, the vessel performed the full scope on its own, from touchdown monitoring to tight “snake curves,” installing an in-line tee at the edge of the vessel’s tensioner geometric limits and laying more than 86,000 mt of steel and concrete on the seabed.

The Oceanic vessel provided support in the form of pipe supply logistics from shore, and Lorelay will perform as-laid survey scopes later this summer. 

Find out more at: www.archerwell.com I elementalenergies.com

DECOMMISSIONING

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Removals completed of offshore Malaysia South Angsi Alpha platform, wellhead facility Marine Masters successfully completed the decommissioning of the South Angsi Alpha platform, repurposing its substructure as part of Malaysia’s largest rig-to-reef project.

Marine Masters has completed an offshore decommissioning work scope for the South Angsi Alpha (SAA) platform offshore Malaysia, operated

by Hibiscus Oil & Gas Malaysia Ltd. The campaign marks a major milestone in the repurposing of retired offshore infrastructure, with the platform’s substructure now resting on the seabed as part of Malaysia’s largest rig-to-reef project.

SAA, situated 130 km from the Terengganu coast, was a 4,000-metric-ton four-legged mobile offshore application barge (MOAB), which served as a production platform for more than 15 years.

Following cessation of production, the topside and substructure underwent preparations for removal and partial reefing in compliance with Malaysia’s regulatory approvals process.

According to Marine Masters, it was also the largest platform decommissioned/repurposing/ reefing program offshore Malaysia to date.

The company was tasked with removal of the MOAB via a combination of the reversed installation method and removal of various associated components for subsequent disposal onshore.

Following severing of the jacket at -55 m LAT and vertical separation, the sections were laid on the seafloor to serve as artificial reef structures for Malaysia’s largest rig-to-reef project. In addition, Marine Masters recovered all 13 conductors, the four MOAB support legs, and performed cutting and transport of the wellhead access platform.

The company said it deployed various techniques and special procedures for remotely operated underwater cutting, assisted by ROVs; high-speed PVL hand cutting, using divers; personnel transfer arrangements between the work barge and the MOAB; and specially designed lifting systems to avoid the need for costlier heavy-lift vessels.

Following transportation, the MOAB topside has since been skidded to shore at Labuan Shipyard, and all loose items offloaded. The ENA WB400 accommodation work barge has been demobilized and the two transport barges are heading to their respective demobilization ports.

This marks the conclusion of Marine Masters’ active offshore operations on the project. Although the offshore scope is complete, the project continues with the final handling and disposal of the topside components. 

ExxonMobil Taps Helix for Three-Year Decommissioning Deal in Gulf of Mexico Helix Energy Solutions, a leading U.S.-headquartered offshore energy services provider, has secured a significant plug and abandonment (P&A) agreement with U.S. energy major ExxonMobil in the Gulf of Mexico. This three-year framework agreement, awarded to Helix’s Louisiana-based shallow water abandonment group, Helix Alliance, solidifies their role in crucial decommissioning services for offshore infrastructure. 

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Your Trusted Global Travel Partner

UPCOMING GLOBAL EVENTS SPE Offshore Europe V 2-5 September 2025 , P&J Live Aberdeen OGV Recruitment Fair V 17 September 2025 , Houston African Energy Week 2025 V 29 Sept - 03 Oct , Cape Town Geofluid V 1-4 October 2025 , Piacenza, Italy OTD Energy V 15 - 16 October 2025 , Norway, Stavanger Offshore Energy 2025 V 25 - 26 October 2025 , Amsterdam, Netherland Wider African Energy Summit V 18 - 19 November , Aberdeen Adipec 2025 V 03 - 06 November , Abu Dhabi

Your Trusted Global Travel Partner

From the Boardroom to the Offshore Rig: Travel Management Support for the Drilling Industry Lauren Durno, Head of Sales – Energy, UK

For offshore drilling operators, transporting the workforce from their homes to offshore platforms and vessels is a task that can come with numerous challenges and considerations.

Remote locations, multiple starting points, significant numbers of personnel, unforeseen weather, and factors outside of your control can cause a logistical headache for many administration and booking managers.

Navigating these hurdles to get personnel from various locations into the one place, via transfers and additional stops is a requirement that can overwhelm, as well as exceeding budget and time constraints.

This is a job that could be made simpler by having a resource with an in-depth knowledge of travel arrangements and a dedication to overcoming last-minute disruptions to ensure operations and workforce rotation remains on schedule.

ATPI’s Offshore Travel

ATPI prides itself on being a partner to the global energy industry and the diverse mix that includes, from traditional energy sources to renewables. Despite the emergence of new energy portfolio’s, conventional oil and gas remains a key sector for us, and one we are proud to support. That pride is reciprocated within the industry, with 80% of drilling contractors partnering with ATPI for their corporate and workforce travel needs.

Like our established track record in many industries (energy related or not), our position within the drilling sector comes down to a variety of competitive factors. ⁃ Extensive sector know-how: Thanks to our decades of experience in oil, gas, and offshore travel, our drilling customers benefit from our insights and tailor-made solutions to meet the unique demands of the industry. ⁃ Seamless end-to-end solutions: Our team is always available to handle every little detail, all the way from the planning stages through to the execution. Our aim is to create a hassle-free travel experience that saves your crew managers time and effort. ⁃ Innovative technology solutions: Our portfolio of specialised tools and products has been designed for specific energy sector challenges. This allows administrative managers to stay ahead with efficient solutions that enhance productivity and streamline processes.

VIEW ALL EVENTS AT www.ogv.energy/events

⁃ Navigating complex destinations: With drilling rigs and sites in diverse locations, our gateway solutions enable smooth travel even in more challenging regions. Our goal is to overcome logistical obstacles and ensure business continuity, wherever operations take the team.

Seadrill Partnership & Case Study

Offshore drilling operator Seadrill has benefited from the wide array of support we provide in the industry. As a longstanding client of ours, we have supported Seadrill with both proactive planning and reactive requests.

When a key member of the team responsible for coordinating events and meetings departed four weeks before an Annual General Meeting (AGM), Seadrill was against the clock to ensure that the meeting would go ahead as intended without disruption.

Recognising the challenge at hand, Seadrill turned to ATPI for a solution. ATPI’s Events Team, working in collaboration with ATPI Management, engaged with Seadrill’s HR team to formulate a comprehensive plan. In response to the unique circumstances, ATPI proposed a novel approach. Unlike the traditional model where ATPI handles pre-booking, planning, and logistics remotely, this time, an experienced ATPI staff member was proposed to be on-site throughout the event. This individual would work hand-in-hand with on-site Seadrill personnel coordinating the meetings and guaranteeing a flawless event execution.

The selected ATPI staff member, armed with a wealth of knowledge gained from working on previous Seadrill board meetings, seamlessly collaborated with Seadrill’s coordinator.

Together, they took charge of overseeing the entire event, from start to finish. Despite the challenges presented by personnel changes, the event unfolded without a hitch. Seadrill’s Chair of the Board acknowledged their joint efforts and toasted to the success of the event during the main board and management dinner.

As the drilling industry is no stranger to unexpected challenges, our agile and collaborative approach plays a pivotal role in ensuring operations remain on track, whether in the boardroom or on the rig.  If you would like to find out how ATPI can help streamline your travel management, email:

atpienergytravel@atpi.com

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