As part of its measures to advance responsible offshore energy development, the Bureau of Ocean Energy Management has published the Final Programmatic Environmental Impact Statement for Gulf of America Regional OCS Oil and Gas Lease Sales and Post-Lease Activities.
It comes with a solid environmental review framework with a robust and transparent environmental evaluations for future exploration, development, and decommissioning activities in the Gulf. This development has also been supported by bodies such as the United States Government Accountability Office, which had expressed the need for clearly defined timelines, when it comes to decommissioning.
It had pushed for better enforcement of decommissioning deadlines in a safe manner on BOEM's part, ensuring thorough execution of the actions planned. GAO's proposals came on the basis of extensive reviewing of laws, regulations, implementing guidance, policies, procedures, budget justifications, and other documentation related to the bureau's decommissioning deadlines.
It had pointed out the urgency of addressing long-standing issues such as effectiveness of enforcement tools, deadlines delivery, supplemental bonding levels and operational standards.
On the status of bonding coverage for decommissioning liabilities, GAO proposed on adopting a reporting mechanism or additional direction laying out how BOEM can balance the priorities set by the Outer Continental Shelf Lands Act, including safety, environmental protection, development of resources, conservation of resources. This will help to promptly address the risks pertaining to decommissioning liabilities, enabling timely decisions on future mitigation measures.
Australia’s Woodside spent almost US$1bn on decommissioning activities around the globe last year, the company reported in an update recently.
“In 2025, Woodside continued execution of planned decommissioning activities spending approximately US$823mn across our portfolio.”
In Australia, it cited “significant progress” across the Enfield, Griffin and Stybarrow fields, offshore north west Western Australia, as well as the Minerva field, offshore Victoria.
Outside Australia, decommissioning is ongoing with work in Canada, at both the upstream Liard and Horn River basins and downstream Kitimat locations in British Columbia, and in the USA where one deepwater well has been plugged and abandoned and legacy site decommissioning is ongoing.
“Our priority as we conduct decommissioning work is the safety of our people and the environment,” the statement posted on its website added.
“We conduct this work using recovery methods developed by Woodside and our specialist contractors, who bring experience, technical know-how and specialist equipment required for the variety of activities in our decommissioning portfolio.”
Within Australia, work included the conclusion of the 10-well Stybarrow plugging campaign that commenced in 2024), the retrieval of the Echo Yodel umbilical and the completion of plugging and abandonment activities at the Minerva field.
“In 2025, final infrastructure was recovered from the Enfield field, concluding a multi-year decommissioning programme that included permanently plugging and abandoning all 18 Enfield wells, recovering and deconstructing the Nganhurra riser turret mooring, and removing flexible flowlines, umbilicals and other subsea structures,” the company stated.
“Deconstruction of the Nganhurra riser turret mooring reused, repurposed or recycled 99.6% of materials. Enfield is the first project that Woodside has taken from exploration through development and operations, to decommissioning. The remaining activity at Enfield is to complete final surveys, which are planned for 2026.”
The Gippsland Basin Joint Venture (GBJV), comprising Esso Australia and Woodside also continues planned decommissioning activities in the Bass Strait.
In 2025, 69 wells were plugged and abandoned, contributing to a cumulative total of more than 220 wells permanently plugged since the campaign commenced.
This includes the completion of plugging the Bream B and Kingfish A platform wells in the first half of 2025.
Woodside added that detailed engineering and execution planning, including submission of environmental approvals to regulators for assessment, is “well advanced” for the Bass Strait offshore platform removal campaign planned to commence in 2027.
Velesto Energy Berhad has kicked off 2026 on a strong note, securing a long term drilling contract from PETRONAS Carigali Sdn. Bhd. for its NAGA 2 jack-up rig. The deal spans a firm period of five years, with operations already underway as of February 2026 and expected to run through to 2030.
For a company that operates in one of the more demanding corners of the energy sector, this kind of contract is no small thing. A five year commitment from one of the region's most prominent operators signals genuine confidence in Velesto's capabilities and track record. It also gives the Group something that every drilling company values deeply — visibility. Knowing where your assets will be deployed, and for how long, makes planning far more straightforward and keeps revenue streams steady even when market conditions shift.
Megat Zariman Abdul Rahim, President of Velesto, said, "The award marks an important milestone for Velesto and an excellent start to 2026. The five-year engagement for NAGA 2 reflects our continued progress in maximising the utilisation of our core assets while strengthening earnings visibility. We appreciate the trust placed in Velesto and remain committed to delivering safe operations and consistent performance throughout the contract period."
The rig at the heart of this contract is no ordinary piece of kit. NAGA 2 is an independent leg cantilever jack-up drilling rig built to handle serious operational demands. It carries a drilling depth capability of 30,000 feet and is rated for operating water depths of up to 350 feet, making it well suited for the offshore environments found across Malaysia and the broader Southeast Asian region.
This latest award fits neatly into Velesto's wider strategy of disciplined asset management and focused execution across its core operating markets. With NAGA 2 now firmly committed for the next five years, the Group looks to be in a solid position heading into the rest of the decade.
Lufkin Industries has secured a multi-year performance contract from Petroleum Development Oman (PDO) to supply rod driven progressive cavity pumping systems across the Marmul-Rahab-Thuleilat-Qaharir fields.
The award covers operations in the Marmul and RTQ areas and reinforces Lufkin’s long-standing role in supporting PDO’s production optimisation strategy.
The company will deliver high-performance rod driven progressive cavity pump (RDPCP) equipment, along with installation, workover and life-of-well support services.
The latest contract builds on a partnership that began in the early 2000s.
Over two decades, Lufkin has expanded its footprint in Oman’s artificial lift market, installing more than 2,000 rod lift systems and maintaining a record of zero non-productive time during new well deployments and replacements, according to company data.
Average pump run life for its PCP systems in the country has exceeded 760 days.
Brent Baumann, chief executive officer of Lufkin Industries, said the agreement reflects the strength of the company’s collaboration with PDO and a shared focus on long-term field performance.
He noted that the firm’s approach extends beyond equipment supply to include service integration, engineering support and localisation initiatives aligned with Oman’s production objectives.
PDO representatives described Lufkin as a high-performing partner capable of delivering in challenging operating conditions while contributing to the development of in-country expertise.
Craig Guillory, vice president of international sales and operations at Lufkin, said the company’s field teams have built trust through technical consistency and close cooperation with PDO.
He added that the Marmul and RTQ scope represents both recognition of past results and a responsibility to maintain high standards in future operations.
A key component of the contract is Lufkin’s continued commitment to In Country Value. The company reports that 87% of its field workforce in Oman are Omani nationals.
It has also invested in local infrastructure to support equipment deployment, maintenance and optimisation services.
Beyond operational delivery, Lufkin has collaborated with PDO on technical research, including published papers and conference presentations addressing advances in remote-controlled RDPCP systems and pump optimisation strategies.
These initiatives have aimed to enhance well performance and extend asset life.
The newly awarded scope includes new well installations, workovers and long-term optimisation support, forming part of PDO’s broader strategy to sustain output from mature fields.
With production targets remaining a priority, the Marmul-RTQ contract is expected to play a significant role in maintaining efficiency and reliability across the operator’s southern assets.
Buccaneer Energy that operates exploration and production activities in Texas, United States, has completed an organic oil recovery pilot project in its Pine Mills field in East Texas.
One injector and two of four producing wells in the Northern section of Pine Mills (Battery 3 area) were subjected to treatment, resulting to a 100% production boost. To facilitate the process of organic oil recovery, a nutrient mixture was injected into the reservoir to stimulate the growth of naturally occurring microorganisms. The rapid growth of these microbes converts the surface properties from hydrophilic (attracted to water) to hydrophobic (repelled by water). This leads to better mobility of residual oil within mature waterflood systems, as the microbial action reduce the interfacial tension between the rock face and the reservoir oil. One treated producer experienced a significant reduction in water cut immediately following treatment.
The post-treatment period has not only recorded an increase from 15 bopd to approximately 30 bopd but maintained consistency. Water cut was nil from 80% in one of the treated wells.
With costs akin to any routine field workover, the company is currently planning follow-up treatment of the remaining two producing wells.
The company will continue to evaluate production performance at the treated wells while also designing the next phase of field implementation.
Paul Welch, Buccaneer Energy's Chief Executive Officer, said, "We are very encouraged by the success of the Pilot Project where average production from the area treated increased 100% to 30 bopd. The initial results significantly exceeded our expectations. The process is well-suited to mature waterfloods, like Pine Mills, where the "easier oil" has been produced and a large amount of residual oil remains in place. Efficiently dislodging this residual oil has a significant impact on production rates. One of the treated producers in the Pilot went from an 80% water cut to a 0% water cut after treatment, a remarkable result.
"Most importantly, the cost of this treatment is modest and comparable to a routine workover, meaning it can be applied without a material capital investment.
"As highlighted in our recent reserve update, Pine Mills carries an NPV10 of approximately $9.6 million at $60 oil pricing. Our current market capitalisation is approximately £1.3 million. Our focus is on closing that gap through incremental production growth, improved recovery and disciplined execution. We see this programme as a practical step toward converting underlying reserve value into cash flow and look forward to updating shareholders as we expand the initiative across the field."
PT Pertamina has signed a memorandum of understanding (MOU) with global drilling giant Halliburton to accelerate the deployment of advanced well construction and stimulation technologies in Indonesia.
Under the MOU, the two companies will evaluate opportunities for various advanced well services, Halliburton reported in a media statement.
This will include: multi-stage hydraulic fracturing, acid stimulation, advanced cementing services, as well as the potential application of closed-loop automation and artificial intelligence capabilities to improve drilling and fracturing performance in selected onshore fields.
According to Simon A. Mantiri, president director of PT Pertamina, the collaboration forms an integral part of the Indonesian state energy firm’s sustainable transformation of upstream production, increasing national lifting and ensuring reliable energy supply.
“With the support of advanced technology and global expertise, we are confident that mature fields can be revitalised and optimised to unlock their full potential, enabling the fields to, once again, be productive and contribute to national energy production,” he said.
Martin White, senior vice president, Asia Pacific, Halliburton, said his team brings global experience to local field operations to improve stimulation effectiveness and optimise production.
“Halliburton integrates proven unconventional methodologies with localised reservoir insights to improve performance, strengthen local capabilities, and deliver technology-based solutions that maximise asset value for our customers,” he noted.
“The MoU also expands Halliburton’s unconventional completions footprint in Indonesia and emphasises how the company’s collaborative approach maximises asset value.”
Saipem has strengthened its position in the Middle East after securing a new offshore contract in Saudi Arabia valued at approximately US$500mn.
The award comes in the form of a Contract Release Purchase Order under the company’s existing Long Term Agreement with Saudi Aramco.
The project centres on the Safaniya oil field, recognised as one of the largest offshore oil fields in the world. Under the agreement, Saipem will carry out the Engineering, Procurement, Construction and Installation of a 48 inch trunkline stretching around 65 kilometres offshore and a further 12 kilometres onshore. The development will also include associated subsea facilities designed to support ongoing production and long term field performance.
Offshore activities will be handled by Saipem’s construction vessels that are already operating in the region, ensuring continuity and operational efficiency. Meanwhile, fabrication work will take place at Saipem Taqa Al Rushaid Fabricators Co. Ltd. in Dammam. This local yard continues to play a key role in strengthening the company’s industrial presence within the Kingdom and supporting domestic capability.
The Safaniya field remains central to Saudi Arabia’s energy infrastructure, and this latest contract reflects the Kingdom’s ongoing investment in maintaining and enhancing offshore production capacity. By combining local expertise with established engineering knowledge, Saipem aims to deliver a project that meets strict safety, quality and environmental standards.
This award not only expands Saipem’s project portfolio in Saudi Arabia but also deepens its longstanding relationship with Aramco. Over the years, the company has built a strong track record in delivering complex offshore developments across the region.
With construction set to move forward using both regional assets and technical experience, Saipem continues to demonstrate its ability to execute large scale offshore projects efficiently while supporting the broader development of strategic energy infrastructure in Saudi Arabia.
A Victorian parliamentary inquiry has heard warnings that ageing subsea pipelines in Bass Strait could leach hazardous contaminants into the marine environment, while also presenting a major opportunity for domestic steel recycling.
Witnesses appearing before the Legislative Council Environment and Planning Committee’s inquiry into decommissioning oil and gas infrastructure highlighted serious concerns over the legacy pollution from offshore facilities in Victoria’s Gippsland region.
Fern Cadman, Fossil Fuel Industry Campaigner at the Wilderness Society, told the committee that around 800 km of subsea pipelines in the Gippsland offshore area contain naturally occurring radioactive materials, mercury, hydrocarbons, and heavy metals.
These substances pose risks to human health and the environment.
“Even if buried, eventually they will degrade, and all that is going to end up in the environment,” Cadman said.
Stan Woodhouse from Friends of the Earth echoed these fears, noting that contaminants can bioaccumulate and transfer through the food chain.
“If we leave it on the seabed, it will end up on our dinner plates,” he said.
The groups urged full removal of the pipelines before corrosion advances, rejecting industry claims that removal is too difficult.
Cadman countered, “Industry says it’s too hard to remove them, but engineers say almost anything can be done, you just have to be prepared to pay for it and use the right tools.”
The committee is examining the scale, legal ownership, and structure of Victoria’s oil and gas infrastructure, including offshore wells, pipelines, high-pressure transmission systems, low-pressure distribution networks, and projects in Commonwealth waters.
In contrast, Jerusha Beresford, Sustainability Adviser at the Australian Steel Institute (ASI), presented decommissioning as a strategic resource for Australia’s circular economy.
The first phase of Bass Strait platform retirements is expected to yield 60,000 tonnes of high-grade steel from 12 platforms, with much more anticipated over the coming decade.
Beresford called for prioritising local recycling into domestic steel manufacturing rather than export.
“We are strongly recommending that the scrap steel recovered from the decommissioning of the Bass Strait oil and gas infrastructure is recognised as a valuable national resource,” he told the committee.
Demand for steel in renewable infrastructure is projected at about 400,000 tonnes annually through to 2030, making retained scrap essential.
Recycling scrap dramatically cuts carbon intensity compared with primary production from iron ore and coal, supporting low-emission steelmaking via electric arc furnaces (up to 90% recycled content) or enhanced blast furnace processes.
Economic benefits are substantial: every 10,000 tonnes processed locally generates 37 jobs and AUD$4.8mn in value-add, versus just AUD$1.3mn if exported.
Without regulation, contractors may export scrap for short-term profit, as past patterns suggest.
Beresford described the moment as a “once-in-a-generation” chance to bolster manufacturing, create employment, and advance sustainability in an industry employing 100,000 people and generating AUD$30bn yearly.
The committee’s report is due by June 2026.
VAALCO Energy has announced encouraging operational advancements in its West African assets, highlighting successful drilling results in Gabon and confirmation of its operatorship in a key discovery offshore Côte d’Ivoire.
In Gabon, the company has successfully drilled, completed, and brought online the Etame 15H-ST development well within the Etame field’s 1V block.
The well encountered a 250 m lateral section of net pay in high-quality Gamba sands positioned near the reservoir top.
It has achieved a stabilised flow rate of approximately 2,000 gross barrels of oil per day (BOPD), with a 38% water cut, produced through a 42/64 choke and an electrical submersible pump (ESP) operating at 54 Hz.
This performance aligns closely with expectations derived from the earlier ET-15P pilot well.
VAALCO is actively managing the well to stabilise reservoir pressure and optimise long-term output.
The drilling rig has remained on the Etame platform, and in mid-February, it spudded a step-out exploration well targeting the West Etame (ET-14P) prospect.
This well, drilled from the S1 slot, carries a 57% chance of geological success and is anticipated to reach the target zone by mid-March.
Should it prove successful, the prospect could deliver significant additions to production and reserves by the end of 2026.
Turning to Côte d’Ivoire, VAALCO has been formally confirmed as operator of the Kossipo field on the offshore CI-40 block, holding a 60% working interest, with partner PetroCI retaining 40%.
The Kossipo field, originally discovered in 2002 by the Kossipo-1X well and appraised in 2019 by Kossipo-2A (which tested at over 7,000 BOPD), lies southwest of the producing Baobab field.
Recent ocean bottom node (OBN) seismic data has enhanced and de-risked VAALCO’s updated evaluation and development strategy.Independent estimates indicate gross 2C contingent resources of approximately 102 million barrels of oil equivalent (MMBOE), with around 293 MMBOE in place.
The company anticipates completing a field development plan during the second half of 2026.
Additionally, the Baobab Ivorien FPSO (formerly MV10), currently positioned off the east coast of Africa, is expected to return to Côte d’Ivoire waters by late March, supporting resumed operations and future drilling on the block.
These updates underscore VAALCO’s focus on organic growth through targeted drilling and field development in its core African portfolio.
The company expressed optimism about enhancing production profiles and reserves in both regions
Mubadala Energy has completed the acquisition of a 15% participating interest in the Nargis Offshore Area concession from Eni, strengthening its footprint in Egypt’s offshore gas sector.
The Nargis concession is an offshore exploration block located in the Mediterranean Sea and is considered a high-potential asset within the East Nile Delta Basin.
The transaction marks a further expansion of Mubadala Energy’s portfolio in Egypt and underlines its strategy of investing in core gas-producing regions.
Following the deal, Eni retains a 30% contractor interest in the concession through its subsidiary, IEOC.
The block is operated by Chevron, which holds a 45% contractor interest, while Tharwa Petroleum Company owns the remaining 10% stake.
The concession operates under a partnership structure with the Egyptian Natural Gas Holding Company (EGAS), with the contractor group and EGAS each holding a 50% interest.
Mansoor Mohammed Al Hamed, managing director and chief executive of Mubadala Energy, said the acquisition reinforces the company’s long-term commitment to Egypt and broadens its exposure to what he described as a high-impact growth opportunity in the strategically significant Eastern Mediterranean region.
“The acquisition of a 15% interest in the Nargis Concession further reinforces our long-term commitment to Egypt, expanding our portfolio with a high-impact growth opportunity alongside world-class partners in the strategically important East Med region,” he said.
The Nargis block lies approximately 50 km offshore in the prolific East Nile Delta Basin and includes the Nargis-1 discovery, which was made in early 2023.
The find has attracted industry attention as part of wider exploration success in the Mediterranean waters offshore Egypt.
The concession is adjacent to the Nour block, also operated by Eni, in which Mubadala Energy acquired a 20% stake in 2018.
In addition to its interests in Nargis and Nour, Mubadala Energy holds a 10% stake in the Shorouk concession, which is home to the producing Zohr gas field, also operated by Eni.
The latest acquisition further consolidates Mubadala Energy’s position in Egypt’s offshore gas landscape, aligning with its broader strategy to expand its international gas portfolio and support long-term energy supply from established basins in the Eastern Mediterranean.
Chevron and HELLENiQ ENERGY have signed a landmark agreement with the Hellenic Republic granting exploration rights to four major offshore blocks, opening one of the largest unexplored maritime areas in the European Union to potential natural gas development.
Under the agreement, Chevron will hold a 70% stake and act as operator, while HELLENiQ ENERGY will retain the remaining 30%. The blocks are located south of Crete and the Peloponnese and cover a combined area of approximately 47,000 sq km.
The move is seen as a significant step in Europe’s ongoing efforts to diversify energy supplies and reduce reliance on Russian gas, which still accounts for roughly one-fifth of the EU’s imports. By unlocking new exploration acreage in the Eastern Mediterranean, Greece is positioning itself as a potential contributor to future regional gas supply.
The joint venture partners confirmed that the exploration programme will proceed in phases, beginning with seismic surveys scheduled to commence later this year. The initial data acquisition will help assess the hydrocarbon potential of the largely untapped offshore area before any drilling decisions are made.
Speaking at the signing ceremony in Athens, Prime Minister Kyriakos Mitsotakis described the agreement as a strategic development for both Greece and the wider European energy market. He noted that the European Union’s decision to curb dependence on Russian gas had created new opportunities for member states to strengthen domestic and regional energy production.
Mitsotakis highlighted Greece’s ambition to enhance its role as a regional energy hub, citing existing and planned infrastructure projects that connect South-Eastern Europe with broader European gas networks. He emphasised that, despite the EU’s long-term climate goals and transition towards renewable energy, natural gas would remain an essential component of Europe’s energy mix for years to come.
Industry observers view the agreement as a potential catalyst for further exploration activity in Greek waters, which have historically been underexplored compared with other parts of the Mediterranean. The size of the concession area makes it one of the most significant offshore licensing arrangements within the EU in recent years.
For Chevron, the deal strengthens its presence in the Eastern Mediterranean, while HELLENiQ ENERGY consolidates its role in domestic upstream development. The success of the initial seismic phase will be critical in determining whether the region can deliver commercially viable gas resources capable of contributing to Europe’s long-term energy security.
Eni has announced a major oil discovery following the successful drilling of the Algaita-01 exploration well in Block 15/06 offshore Angola.
The well is located approximately 18 km from the Olombendo FPSO, with preliminary assessments indicating oil in place of around 500 million barrels.
Drilling operations began on 10 January 2026 using the Saipem 12000 drillship in water depths of 667 metres. The well intersected multiple oil-bearing sandstone intervals within Upper Miocene formations. These reservoirs have been described as having strong petrophysical characteristics, supporting their commercial potential. An extensive data gathering programme, including fluid sampling, confirmed both reservoir quality and favourable fluid properties.
The proximity of established production facilities, including the Olombendo floating production, storage and offloading unit, strengthens the economic case for development. Access to nearby infrastructure is expected to shorten development timelines and optimise capital expenditure, improving the overall viability of bringing the resource on stream.
Block 15/06 is operated by Azule Energy, which holds a 36.84% interest, in partnership with SSI (26.32%) and Sonangol E&P (36.84%). Azule Energy is jointly owned by Eni and bp, and the latest find further reinforces the consortium’s upstream position in Angola.
The discovery highlights the continued exploration potential of Angola’s offshore basins, particularly within mature producing blocks where near-field opportunities can deliver material additions to reserves. By leveraging existing infrastructure and technical expertise, operators are increasingly able to unlock value from adjacent prospects while maintaining cost discipline.
Looking ahead, appraisal activities will likely focus on refining reserve estimates, evaluating development concepts and assessing tie-back options to current facilities. If progressed efficiently, the Algaita-01 discovery could contribute meaningfully to Angola’s medium-term production outlook, supporting national revenue generation and strengthening the country’s role as a key hydrocarbon producer in sub-Saharan Africa.
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