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GLOBAL OUTLOOK 2026 · REGION BY REGION

Decommissioning & abandonment GEN Intel Special Report Aberdeen · Stavanger · Perth · Kuala Lumpur

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2026 Edition

Offshore focus • all sectors covered* All information correct at time of issue

Delivering certainty through late-life operations to decommissioning execution Worley is the world’s largest provider of engineering, project and asset management solutions in the energy, chemicals and resources sectors.

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inside this edition

Contents Page

Foreword, in association with CODA

The argument in brief

The market in numbers

Where the work is concentrated

The economics of a decommissioning contract

Technology and the cost curve

Capacity: the crunch is 2027

The execution timeline

United Kingdom Continental Shelf

Norwegian Continental Shelf

Gulf of Mexico

Australia

Southeast Asia

Brazil and Latin America

West Africa

Middle East and other regions

Adjacent markets: nuclear, refineries, power

The recycling chain

The CCS and repurposing bridge

The contractor landscape

Supply chain capability

The GEN View, and what to do next

Data appendix A: global forward pipeline

Data appendix B: decommissioning and repurposing pipeline

Statuses current as at 13th September 2026. Programmes are tracked live and continuously updated in the GEN Project Atlas.

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GEN INTEL • 2026 Foreword

In association with

Foreword Two perspectives on the state of decommissioning today. From the desk that built this report, and from Australia.

Kenny Dooley Managing Director Global Energy Network Decommissioning has spent too long being described as a future opportunity. It is not. The work is here, the liabilities are real and the pace is accelerating. In the UK, annual decommissioning spend has already passed £2 billion and is expected to approach £3 billion a year through the decade. The challenge now is delivery: more wells, more infrastructure and increasing pressure on vessels, equipment and skilled people. Australia is at a different point in the cycle, but the direction is the same. With an estimated AU$43.6 billion of offshore decommissioning liability to 2070, and major campaigns now moving into execution, the country is building the regulatory framework, capability and domestic supply chain required to deliver it.

Dr Francis Norman Chief Executive, Centre of Decommissioning Australia

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Those two shelves are not the whole picture, and that is why we built this report the way we did. We set one rule at the start. Read each basin by what has been delivered, not by what has been estimated. Liability totals are easy to publish and tell you very little about where the work is. Executed tonnage, plugged wells and awarded frameworks tell you a great deal. Apply that rule across eight basins and the centre of gravity is already outside Europe.

companies that took them in 2026 will hold those positions into the mid 2030s. One pattern runs through every emerging region. What releases the work is not engineering readiness, it is funding provision. The signal to watch in any basin is not the size of the liability. It is the moment the money to pay for it is secured.

What it shows is a market limited by capacity rather than by demand. One heavy lift vessel is being pulled between the Central North Sea, the Norwegian shelf and Bass Strait inside the same window in 2027.

So this is an execution map rather than a market overview. Every figure in it was verified against a primary source, regulators first, and every programme named is tracked live in the GEN Project Atlas. Our teams in Aberdeen, Stavanger, Perth and Kuala Lumpur sit inside four of the basins covered here.

The UK semi submersible fleet has fallen to six units marketed against more than 1,300 wells due in the five years to 2030. And the largest awards of the past year were multi year campaign frameworks rather than single tenders, which means the

Decommissioning is no longer the final chapter nobody wants to discuss. It is becoming one of the defining industrial opportunities of the next two decades. The question is not whether the work is coming. It is who is ready to deliver it

Moving from a local and regional challenge to a global opportunity the international decommissioning market is opening up to solutions. North and South America, Europe, Africa and the broader Asia Pacific regions are all on their decommissioning journeys with what was once considered a North Sea and North America industry becoming truly global.

surfacing. Thailand has executed significant volumes of P&A this decade, Brazil is now removing more flexibles than any other region, the North sea continues to deal with massive structures and Australia is planning for one of the most complex multi-platform removal campaigns to date.

Many of the emerging decommissioning regions built their knowledge and approach on the experiences of the early movers, and will continue to rely on established suppliers of technologies, but as global activities pick up, regional solutions to regional problems are

This report shines a light on the future pathway for decommissioning as it becomes a mainstream activity that must be done right in every region, all at the same time, making it one of the most significant current opportunities for businesses in the oil and gas industry.

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Integrated Well Life-Cycle Specialists From design and engineering to full field decommissioning projects (and everything in between), Well-Safe Solutions are your single source well specialists whatever stage or scale. wellsafesolutions.com

GEN INTEL • 2026 OUTLOOK SECTION 01

The argument in brief

A decade of delivery, not prospect Global offshore decommissioning is entering a decade of sustained delivery. The market doubles by 2034. The story is not the size. It is who can actually execute it. Unless stated, every figure in the outlook sections refers to offshore oil and gas decommissioning. Nuclear, refineries and power are treated separately from page 25.

ortune Business Insights puts the global offshore decommissioning market at $9 billion in 2026, rising to $16.7 billion by 2034, a compound annual growth rate of nearly 8 percent. Mordor Intelligence models a similar trajectory, from $8.08 billion in 2026 to $11.52 billion by 2031. The methodologies differ. The direction does not. What is driving it is not the energy transition narrative that sells conference tickets. It is ageing steel, hardening regulation, and operators who can no longer defer the bill.

EVERY BASIN IS NOW IN DELIVERY, AT DIFFERENT SPEEDS The UK and Norwegian shelves carry the largest committed spend and the most developed regulatory template, which is why the UKCS remains the reference point for how this work is priced and governed. Delivery is a different picture. The Gulf of Mexico has been executing at volume for years and will continue to. Australia now has a decade of contracted pipeline in front of it. Thailand has delivered substantial removal volumes. Brazil is moving from planning into execution at scale, backed by the largest single committed decommissioning budget of any operator in the world. The UK, meanwhile, is behind its own well schedule and carrying a platform backlog, and Norway has published a large forward liability while doing comparatively little removal to date. Read the basins by what has been executed, not by what has been estimated, and the centre of gravity is already outside Europe.

THREE TENSIONS RUN THROUGH EVERY REGIO N First, capacity is the binding limit. Heavy lift vessels, purpose built P&A semis, jack up rigs and recycling yards are all short, and decommissioning competes for the same fleet that offshore wind, brownfield work and carbon capture need. The UK semi submersible market has contracted to six units marketed on the UKCS, down from a peak of eleven in 2023, and those rigs are wanted for production well intervention and carbon storage drilling as well as for plugging. The NSTA’s own position is that insufficient rigs and vessels may push costs up and worsen well deferral. Second, regulators have split two ways. The UK, Australia and Brazil are hardening enforcement while the United States has moved to roll back the bonding rule it introduced in 2024. No operator can move a fixed platform to a friendlier regime, so this does not drive relocation. What it changes is the cost of delay, which is rising sharply in some basins and falling in others, and that is what pulls work forward or pushes it back. Third, recycling has become contractual. Operators now write 95 percent reuse targets into removal contracts, and a contractor without a confirmed yard partner is bidding incomplete.

the market

$9.1bn Global market, 2026 (Fortune Business Insights)

$16.7bn 2034 forecast, around 8 percent CAGR

~50% Europe share of 2025 spend, UK and Norway leading

45 to 60% Share of spend that is well plugging and abandonment

the gen project atlas

5,600+ Projects tracked globally

172 Decommissioning and repurposing programmes, 136 of them offshore

71% UK local content on 2025 decom contract awards

This report is the execution map that follows from those three tensions. It sets out each basin in turn, names the buyers, tracks the forward pipeline, maps the capacity crunch quarter by quarter, and shows where the accessible supply chain sits against the work coming. A market overview is useful. An execution map is essential.

T H E G E N V IE W The winners of this decade will not be the firms with the best single tender. They will be the firms holding framework positions across three or four basins, with capacity the market cannot easily replace. Everything that follows is about finding those positions before the competition does.

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GEN INTEL • 2026 OUTLOOK SECTION 02

The Market in Numbers

Doubling by 2034

wo numbers frame the decade. The global market doubles by 2034, and on the UK shelf, the most mature basin in the world, decommissioning overtakes new investment before 2030. The UK crossover matters beyond the UK because it is the first basin to reach it. Every other mature basin is on the same path. The UK is simply further along the curve. Global Offshore Decommissioning market - US$Billion

16.7 15.5

15 12 9

9.1

12.3

11.4

10.6

9.8

13.3

14.4

6 3 0

2026

2027

2028

2029

2030

2031

2032

2033

2034

The market roughly doubles over eight years at a compound rate near 8 percent. Source: Fortune Business Insights. Mordor Intelligence models a similar path, $8.08bn in 2026 to $11.52bn by 2031.

UKCS Decommissioning as a share of total spend

Decommissioning

Capital expenditure

2021 to 2025

13%

actual

Operating costs

31%

Exploration and appraisal

53%

Decommissioning share nearly doubles, from 13 to 24 percent

2026 to 2031

24%

forecast

26% 25%

49% 50%

75%

100%

Share of total UKCS upstream expenditure, 2025 prices Decommissioning rises from 13 percent of UKCS upstream spend across 2021 to 2025 to 24 percent across 2026 to 2031, while capital expenditure falls from 31 to 26 percent. On the NSTA’s annual forecast, decommissioning overtakes capital expenditure from 2029. Source: NSTA UKCS Decommissioning Cost and Performance Update 2026, Figures 13 and 14.

The two charts capture the shape of the opportunity. Globally, decommissioning is not a step change, it is a steady climb, and that is what makes it a durable market rather than a spike. The firms that build capability now will find demand every year for the next decade, not a single wave that passes and leaves them idle. The UK chart is the more consequential one for the supply chain. When decommissioning overtakes capital expenditure, it stops being the work operators do at the end and becomes the core of what the basin spends

money on. The UK reaches that crossover in 2029. The two move in opposite directions. Decommissioning spend is climbing, but capital expenditure is also falling, so the crossover is partly arithmetic. A rising decommissioning share of a shrinking total is not the same thing as a spending surge, and the point to take from it is that late life work becomes the basin’s centre of gravity. The Gulf of Mexico passed it in practice years ago. Australia reaches it in the 2030s, Brazil later still. The date moves by basin. The direction does not.

T H E G E N V IE W A doubling market that climbs steadily rewards patient capability building over opportunistic bidding. The UK crossover is the clearest signal in the dataset: the money is moving from first oil to last oil, and the companies positioned for removal, P&A and recycling are positioned for where the spend is going, not where it has been.

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GEN INTEL • 2026 OUTLOOK SECTION 03

where the work is concentrated

Eight Basins, four maturities Read the market by maturity, not by size. The mature basins tell you what the work costs. The emerging ones tell you where to be next.

he global picture resolves into eight basins at four different stages, and the stages are set by what has been delivered, not by what has been estimated. Two carry mature regulation and the deepest cost data, the UK and Norwegian shelves, though both have more ahead of them than behind. Two carry the largest backlogs and are executing at volume against them, the Gulf of Mexico and Southeast Asia. Two are moving from planning into execution, Australia and Brazil. And two are early, West Africa and the Middle East, where the precondition for decommissioning at scale, the exit of the majors or the end of field life, is still playing out. The map and table below are the starting point. The pages that follow are the terrain.

NCS $3 to 5bn UKCS £44bn

Gulf of Mexico $40 to 70bn

Middle East

SE Asia $100bn

West Africa Brazil $13bn

 Mature

Australia AU$43.6bn

 Large Backlog  Moving into execution  Early

REGION

MARKET SCALE

MATURITY

LEAD OPERATORS

Australia

AU$43.6bn through 2070

Moving into execution, decade long pipeline

Woodside, Chevron, Santos, INPEX

Brazil

R$70bn (~$13bn) by 2030

Moving into execution

Petrobras (dominant)

Gulf of Mexico

$40 to 70bn liability

Large backlog, high volume, operator led

Chevron, ExxonMobil, Shell, bp, Talos, W&T, APA

Middle East and other

Small but no longer zero

Early, first awarded programmes landing

Saudi Aramco, QatarEnergy, Ras Al Khaimah Petroleum Authority, CNOOC, Eni

Norwegian Shelf

$3 to 5bn near term, larger 2030s

Mature, limited execution to date

Equinor, ConocoPhillips, Aker BP, Vår Energi

Southeast Asia

~US$100bn through 2030

Large backlog, Thailand leading on delivered volume

PETRONAS, Pertamina, PTTEP, Chevron Thailand, EnQuest

UK Continental Shelf

£43.4bn total, £28bn 2023 to 2032

Mature, large backlog

Apache, Shell, bp, TAQA, EnQuest, Harbour, Ithaca, Eni, NEO NEXT+ Energy, Serica

West Africa

Building from a low base

Early, fragmented, IOC exit

Renaissance, Seplat, Afentra, Tullow, Chevron

Exhibit: the global decommissioning map by market scale, maturity and lead operators. Source: NSTA, Marine Minerals Administration, ANP, PETRONAS, NOPSEMA, Xodus, CODA and GEN Project Atlas.

The growth is driven by four things at once. Ageing infrastructure is reaching the end of engineered life, and corrosion and integrity cost is now pushing assets past the economic limit faster than commodity price. Operators are rationalising portfolios, with the majors exiting mature basins to focus capital elsewhere. Regulation is tightening across most jurisdictions. And specialised vessel capacity, long the excuse for delay, is finally arriving, which removes the last reason to defer.

GEN Intel · Regional regulators and operator disclosures

The practical consequence for a supply chain company is that the same capability travels. A firm that can plug a well, cut a jacket or run a reception yard on the UKCS has a product the emerging basins want and cannot yet build for themselves. The question in each region is not whether the work exists. It is who holds the capacity when it lands.

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GEN INTEL • 2026 OUTLOOK SECTION 04

The numbers behind the contracts

What it costs, what it charges The market reports tell you the size of the prize. They do not tell you what a well costs to plug, or what a heavy lift charges by the day. A contractor bidding into a tender needs that number. Costs on this page are given in sterling. That is deliberate. OEUK’s annual benchmark and the NSTA cost reports are the most complete public decommissioning cost series in the world, and operators and regulators in every basin in this report use them as a reference. Sterling figures convert at approximately 1.35 US dollars to the pound at the time of writing. These rates assume the structure comes ashore. They are not comparable across jurisdictions. Under OSPAR Decision 98/3 a North Sea tonne must be lifted, transported, dismantled and recycled, while in the US Gulf a jacket may be toppled in place and never leave the water. The removal standard, not the tonnage, is the largest single determinant of what a programme costs. Well plugging and abandonment is the single largest cost line in decommissioning, running to almost half of UKCS spend and a similar share elsewhere. A simple shallow water platform well can be closed for £2 to £4 million. A complex deeper water well runs £8 to £15 million, and a deepwater subsea well £10 to £25 million once vessel mobilisation is counted. The UKCS average across mixed complexity sits near £7.8 million on OEUK’s 2025 benchmark. In the Gulf, bulk campaigns and an abundant shallow water supply chain bring the figure down to $2 to $5 million a well. Removal is dominated by vessel rate and lift complexity. Single lift topside removal via Pioneering Spirit or Sleipnir runs £8,000 to £15,000 a tonne, and is now the cost competitive route for any platform above about 8,000 tonnes. Reverse installation, piece by piece, costs more per tonne and takes longer offshore, and survives only for very old structures with integrity concerns.

Jacket removal runs £6,000 to £12,000 a tonne depending on water depth. FPSO disposal runs £20 to £80 million all in. At the back of the chain, yard reception and dismantling adds £300 to £700 a tonne, and rates here are firming sharply wherever reception capacity is short against local removal volumes, most acutely in Australia. One question comes before all of these. Establish whether a removal is single lift or piece by piece, because the two buy almost entirely different things. Piece by piece removal generates months of offshore cutting, scaffolding, rigging and marine support. A single lift compresses the offshore phase to days and moves the labour onshore to the receiving yard. On Brent, that is why the yard at Teesside carried the work and the offshore content was comparatively small.

where the decommissioning dollar goes, a typical offshore programme

48%

24%

 Well plugging and abandonment  Owner cost and project management

 Facilities and topsides removal  Site remediation and monitoring

13%

10%

 Subsea and pipelines

Exhibit: indicative cost split. Well P&A is close to half of a typical programme, which is why it is where technology and capacity pressure matter most.

WELL TYPE

COST PER WELL

REMOVAL SCOPE

TYPICAL COST

Simple platform, shallow water

£2m to £4m

Single lift topside

£8,000 to £15,000 / t

UKCS average, all wells

£7.8m

Piece by piece removal

£12,000 to £25,000 / t

Complex platform, deeper water

£8m to £15m

Jacket, heavy lift

£6,000 to £12,000 / t

Subsea well, deepwater

£10m to £25m

FPSO full disposal

£20m to £80m total

Gulf shallow shelf

$2m to $5m

Yard reception and dismantling

£300 to £700 / t

vessel and rig dayrate ranges, 2025 to 2026

CATEGORY

DAYRATE (USD)

EXAMPLES

Ultra heavy lift, single lift class

$700k to $1.5m+ per day

Pioneering Spirit, Sleipnir

Heavy lift semi sub, large

$400k to $700k per day

Thialf, Saipem 7000

Purpose built P&A semi sub

$300k to $500k per day

Well-Safe Defender, Well-Safe Guardian

Jack up rig, P&A campaign

$120k to $250k per day

Valaris, Borr, Velesto, Well-Safe Protector

Well intervention vessel

$150k to $300k per day

Helix Q4000, Q5000, Q7000

Indicative levels only. Ultra heavy lift rates are not publicly tendered and are held within a small community, so the band shown reflects market commentary rather than any disclosed rate. Spread costs of crew, fuel and integration typically add 30 to 60 percent on charter.

T H E G E N V IE W Three takeaways. The dayrate environment is firming through 2027, so quote at the upper end of historical ranges for decom specific vessels and rigs. Single lift is now the cost competitive route above 8,000 tonnes. And yard recycling rates are firming hardest where reception capacity is short against demand, so companies with reception base and recycling capability in those regions should price the premium rather than compete it away.

GEN Intel · OEUK Decommissioning Insight 2025, NSTA Decommissioning Benchmarking Report 2026, sanctioned project financials

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GEN INTEL • 2026 OUTLOOK SECTION 05

TECHNOLOGY aND THE COST CURVE

Where the cost bends Every basin in this report faces the same question. Is decommissioning getting cheaper or more expensive? The answer decides who wins the work. Through the 2010s the industry took cost out. The regulator, then the Oil and Gas Authority and now the NSTA, set industry a target to cut decommissioning cost by at least 35 percent against a 2016 baseline of £59.7 billion, as a shared objective with industry and government, and campaign learning, standardisation and single lift removal delivered much of it. That figure deserves a caveat. A meaningful share of the reduction came from vessel and rig rates falling during the pandemic rather than from durable efficiency, and those rates have since returned. The structural gains from campaign learning and standardisation are real. The headline percentage flatters them. The UKCS average well plugging and abandonment cost now sits near £7.8 million. But the direction is turning. As capacity tightens and dayrates firm through 2027, the tailwind of a maturing market meets the headwind of a constrained supply chain. The firms that keep winning will be the ones bending the cost curve through technique, not the ones relying on scale. Well plugging and abandonment is where it matters most, because it is close to half of all spend. The largest lever is getting off the rig. Vessel based and rigless intervention, using light well intervention vessels such as the Helix Q series, removes the single most expensive line item from many P&A scopes. That is no longer a theoretical route. In December 2025 Helix Energy Solutions took a multi year award from an undisclosed major for riserless plug and abandonment on up to 34 subsea wells in the UK North Sea from 2026, covering pipeline flushing and disconnection as well as the wells. With six semi submersibles marketed on the shelf against more than 1,300 wells due in the five years to 2030, the arithmetic does not close on rigs alone, and the market is already routing round the constraint. Barrier technology is the next frontier: bismuth alloy and thermite based plugs, offered by specialists including BiSN and Interwell, set annular barriers without waiting on cement, cutting rig time. These are moving from trials into campaign use. Removal and cutting have their own cost curve. Single lift removal via Pioneering Spirit and Sleipnir took cost and offshore exposure out of topside removal a decade ago. The frontier now is subsea and jacket work, where abrasive water jet and diamond wire cutting, internal cutting tools and conductor recovery systems are where the marginal saving sits. The table below maps where the money is being taken out of a programme.

Removal technology now carries a regulatory consequence as well as a commercial one. OSPAR Contracting Parties agreed in 2020 to report annually on removal technology developments that would narrow the categories where installations may be left in place. A 2018 review had found no capability advance significant enough to support that narrowing, so this is direction of travel rather than settled fact. The intent is explicit: as removal capability improves, the leave in place route closes, and capability investment expands the addressable market rather than only lowering the cost of serving it. The constraints are physical before they are commercial. On a late life normally unmanned installation the drilling rig and legacy equipment were removed decades ago, process equipment installed since leaves very little usable deck space, and there is no accommodation at all, so every well is worked from a vessel or a temporary spread. Documented campaigns on that kind of asset show the schedule moves on two things: redesigning platform equipment to cut skidding time between wells, and faster casing cutting. Subsea removal has its own version of the problem. Structures that have sat on the seabed for years become buried, so recovery is an excavation problem before it is a lifting problem, which pulls in dredging spreads and mass flow excavation that a standard installation contractor may not carry. The quietest lever is not a tool, it is how the work is packaged. Operators are bundling scope to give the market a wide execution window and let contractors optimise. Shell’s subsea infrastructure bundling, TAQA’s satellite disconnection campaigns and Apache’s single contractor Forties model are all cost strategies as much as procurement ones. Digital twins, the NSTA Visibility Dashboard and the Net Zero Technology Centre’s wells decommissioning collaboration sit behind them, turning campaign data into repeatable efficiency. The same packaging logic is visible worldwide. Chevron’s Barrow Island programme in Australia, Petrobras’ Campos Basin framework awards and PETRONAS’ three package structure for its platform tender are all attempts to give contractors a wide enough window to optimise against. OEUK puts the gain at 15 to 25 percent against industry averages for operators with strong campaign management, with early supply chain engagement and planning tools the main drivers. That is the largest single efficiency in the book and it is procurement, not technology.

COST LINE

WHERE COST IS BEING TAKEN OUT

EFFECT

Well P&A

Rigless and vessel based intervention

Removes the rig, the biggest single cost

Well barriers

Bismuth alloy and thermite plugs

Sets barriers without cement wait time

Topside removal

Single lift, Pioneering Spirit and Sleipnir

Cuts offshore time above 8,000 tonnes

Cutting and recovery

Water jet, diamond wire, conductor tools

Marginal saving on subsea and jacket work

Delivery

Campaign bundling, digital twins

Wide execution windows, repeatable efficiency

Exhibit: the five places cost is being engineered out of a decommissioning programme.

THE FLEET PROBLEM GETS A COMMERCIAL ANSWER On 13 August 2026 the NSTA and sixteen operators signed a wellhead severance charter, seventeen signatories in all, and it is the most directly commercial thing the regulator has done all year. The principle is simple. Rigs are the right tool for plugging a well with cement, but not for the last step of cutting the wellhead off the seabed, and a vessel can do that for less. Industry estimates put the saving at around 30 percent of the remaining subsea wellhead removal bill, roughly £200 million, against an average of £700,000 per wellhead over the past five years and about 1,000 subsea wells still to come. That is roughly £700 million of scope moving out of the drilling market and into marine and subsea services. Signatories will share data, expertise and vessels, and a workgroup will define the delivery framework for AB3 severance work. Read it as two things at once. It releases scarce rig capacity back to earlier stage plugging, and it creates a vessel based scope of work that did not exist as a distinct market twelve months ago. The signatories are Adura, Apache, bp, CNOOC International, Dana Petroleum, Eni, EnQuest, Harbour Energy, INEOS Energy Europe, Ithaca Energy, NEO NEXT+, Perenco, Serica Energy, Shell, Spirit Energy and TAQA UK. Any contractor with a suitable vessel and a cutting capability should be talking to that list now, because the framework is being written this year.

T H E G E N V IE W Cost leadership now comes from technique and packaging, not headcount. Companies with rigless P&A, barrier technology, specialist cutting and campaign management capability are positioned to win as capacity binds and operators consolidate scope precisely to capture these efficiencies. This is the part of the market where a focused specialist can out compete scale.

GEN Intel · OEUK, NSTA, Net Zero Technology Centre, GEN Project Atlas

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GEN INTEL • 2026 OUTLOOK SECTION 06

vessel and yard capacity

The crunch is 2027 Decommissioning at scale is a vessel business. A small number of assets set the rate at which the global pipeline can actually be executed. In 2027 they run out. The heat map below estimates capacity tightness across the major basins through 2028, built from operator capital plans, public charter announcements and GEN Intel weekly tracking. Two lines dominate it. UKCS heavy lift and Australian heavy lift both go critical through 2027, for the same reason: Pioneering Spirit is one vessel being pulled between Brae Alpha preparation, Bass Strait mobilisation in the third quarter of 2027, and Norwegian commitments. The tighter constraint is not the vessels. It is the yards. Australian reception capacity is the single most binding limit in the entire global system through 2028, because Barry Beach, Henderson and Onslow combined cannot absorb Bass Strait, Barrow Island and Northern Endeavour Phase 2 at the same time. Gulf jack up availability tightens through the second half of 2027 as operators accelerate their own programmes. West Africa alone shows surplus, a reflection of an early stage market, and that surplus reverses from 2028 as the indigenous operator transition matures. The competing commitments are now on the record. In the UK, Allseas holds a multi year contract with TAQA covering more than 120,000 tonnes across four Northern North Sea platforms, Eider Alpha, Tern Alpha, North Cormorant and Cormorant Alpha. Eider Alpha was lifted in October 2025 and the Cormorant Alpha and Tern topsides are routed to Able Seaton Port from 2027, alongside the 33,000 tonne Brae Alpha topsides in the Central North Sea. In Norway, Equinor has contracted the removal of the Statfjord A topsides at close to 50,000 tonnes, among the

Region and vessel pool

heaviest single lifts ever attempted. In Australia, the Gippsland environment plan, lodged by Esso before the operatorship transfer, has the vessel on site for roughly four months from the third quarter of 2027, removing topsides from up to 13 platforms plus jacket upper sections and two monotowers, around 60,000 tonnes in total, routed to Barry Beach. Allseas is also upgrading the vessel beyond 60,000 tonnes of lift capacity, with final load testing scheduled for late 2026 to early 2027, which pushes the heaviest lifts to the back of that window. One vessel, three continents, one window. Capacity is arriving as well as tightening, and the clearest example is a vessel that did not exist two years ago. The Petrodec Obana entered service in September 2025, a purpose built heavy lift jack up converted from two redundant drilling rigs, working in up to 65 metres of water with a 2,000 tonne lift. That places it below the single lift class and above a conventional crane barge, which is exactly the gap the Southern North Sea sits in: many small jackets, none of them worth a Pioneering Spirit mobilisation. It has taken Perenco UK’s Galahad, three Amethyst jackets and, from April 2026, Pickerill A and B, and everything it lifts goes to Petrodec’s own yard at VlissingenOost. Vessel and yard under one owner, no consortium required. Read against the heat map above, the constraint is not a fixed number of assets. It is how quickly redundant drilling capacity can be converted into removal capacity.

26Q3

26Q4

27Q1

27Q2

27Q3

27Q4

28Q1

28Q2

Available

Tight

Critical

Tight

Critical

Tight

Brazil FPSO disposal

Available

Tight

Available

Gulf jack up rigs

Available

Tight

Critical

Tight

NCS recycling (Vats)

Tight

Critical

Tight

Available

SE Asia jack up rigs

Available

Tight

Available

UKCS heavy lift

Tight

Critical

Tight

Available

UKCS P&A semis

Critical

Tight

Available

West Africa decom vessels

Surplus

Available

Australia heavy lift Australia recycling yards

 Critical, fully booked

 Tight, limited slots

 Available spot capacity

 Surplus idle capacity

T H E G E N V IE W Capacity is pricing power. Any company with a semi sub, a P&A crew, reception base or recycling capability in the right basin at the right window has strong pricing power when the heavy lift schedule is fixed. Companies with Gulf capable jack ups should be in commercial discussions now for 2027 charter, and companies with Australian yard capability hold a structural advantage in any campaign there.

GEN Intel · Operator capital plans, public charter announcements, GEN Intel tracking

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GEN INTEL • 2026 OUTLOOK SECTION 07

THE EXECUTION TIMELINE

The wave, on one line Eleven landmark programmes, one timeline. This is why the fleet runs short in 2027, and why a framework position taken now pays out for a decade.

2026 UKCS · Apache Forties

2027

2028

2029

2030

2031

2032

2033

2034

2035

$1bn+ · largest ever £1bn · 33,000t topsides

UKCS · Brae Area UKCS · Brent

£1.5bn

NCS · Heimdal

Topside removal to 2028

NCS · Veslefrikk

$400m 50,000t topsides

NCS · Statfjord A Australia · Bass Strait

$1bn → 2040

Australia · N. Endeavour Ph2

9 well P&A, awarded

Brazil · Marlim

$2bn

Thailand · Gulf of Thailand

$1bn

Malaysia · PETRONAS 31

 Europe

RM2 to 3bn

 Asia Pacific

 Americas

 2027 to 2028 Crunch

Exhibit: landmark decommissioning programmes by execution window. Bar colour denotes region grouping, the pink band marks the 2027 to 2028 capacity crunch, and Bass Strait runs to 2040. The Gulf of Mexico is not shown as a single bar because it is many smaller operator programmes rather than one mega scope. Source: operator disclosures and GEN Project Atlas.

Read vertically, the timeline explains the heat map. Almost every major programme wants execution capacity in the same 2027 to 2028 window, and there are only so many heavy lift vessels and P&A semis to go round. The overlap is the crunch, and it is structural, not a scheduling accident.

Read horizontally, it explains the opportunity. Apache Forties and Bass Strait alone run into the 2030s, and the frameworks awarded in 2026 lock in the contractors that will hold those positions for the whole decade. The companies that move this year are not chasing a project. They are taking a seat that stays occupied until the mid 2030s.

T H E G E N V IE W The timeline is the single best argument for acting now rather than waiting for the market to mature. The capacity to execute this wave is being contracted in 2026, and once the frameworks close the window narrows sharply. Companies with heavy lift, P&A, subsea or recycling capability should be in commercial conversations against these specific programmes today, not when the tenders are already gone.

GEN Intel · Operator disclosures, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 REGION 01 OF 08

THE BaSIN THaT SET THE PRICE

United Kingdom Continental Shelf No basin has priced this work more accurately or regulated it harder, and none has removed more large steel structures. What happens on the UK Continental Shelf sets the terms the rest of the world imports. In 2026 those terms changed.

he numbers are settled. The NSTA’s 2026 Cost and Performance Update, published in August, puts remaining UKCS decommissioning at £43.4 billion in 2025 prices, with £28 billion of it falling in the decade from 2023 to 2032. Around £7 billion of that decade has already been spent, so £21 billion remains inside it, close to half the entire forward bill. Around 3,000 wells still require full plugging and abandonment, more than 1,300 of them in the five years to 2030, and the backlog of inactive wells awaiting final abandonment sits at about 500. This is no longer a market in prospect. It is a market in delivery. Operators spent a record £2.6 billion in 2025, up from £2.4 billion in 2024, and annual spend is forecast to run near £3 billion from 2026 to 2032. The total has stopped climbing, easing from £43.6 billion, but that is not a cost reduction: efficiency gains were offset by inflation and by competition for the same vessels and people from carbon storage, renewables and nuclear.

by the numbers

£43.4bn Total remaining scope, 2025 prices

£21bn

Still to spend inside the 2023 to 2032 decade

3,000

Wells still to be fully plugged and abandoned

THE REGULATOR STOPS CONVENING AND STARTS FINING What changed in 2026 was the regulator’s posture. For a decade the NSTA acted as a convenor, publishing benchmarks and connecting licensees with the supply chain. On 9 April 2026 it stopped convening and started fining. EnQuest Heather was penalised £16.5 million for failing to decommission 33 wells across the Alma, Galia, Broom and Dons fields, £500,000 for each breach, after what the regulator called a conscious strategy of deferral. It was the first collective decommissioning fine of its kind. EnQuest is considering an appeal and argues the wells were young and low risk, but the signal to the basin is not ambiguous. The NSTA’s first published well decommissioning deficit table, on 1 December 2025, named twenty-two operators. Thirteen are behind on their obligations with 153 wells in arrears. The other nine hold all 780 of their wells within consent. The legal cover for delay is closing. An annual league table ranking well decommissioning performance was consulted on at the same time and has still not been published. The two instruments do different work. The deficit table records who missed a deadline. A league table would rank how efficiently operators execute, and an operator can be fully compliant and still inefficient. The clearest evidence that the regulator is escalating is that it has not finished. The legal backdrop is hardening further. The government’s North Sea Future Plan, published November 2025, sets out powers for the NSTA to impose enforceable well decommissioning milestones and to take financial security where they are not met, aimed particularly at older subsea wells drilled before 2009. It also raises the maximum penalty the NSTA can levy from £1 million to £5 million, with a route to £10 million, and gives it power to remove a licence from a holder no longer judged fit and proper. The measures require an Energy Bill to take effect, so this is legislated intent rather than law today. The £16.5 million EnQuest Heather fine was levied under the old regime. The ceiling for the next one is five times higher. A third cost lever arrives on 30 September, when new abandonment charges regulations replace the 2012 flat fee regime with quarterly cost recovery on actuals, at £130 to £256 an hour depending on the officer, with all section 29 notice holders jointly and severally liable. Regulatory cost stops being a fixed line and starts tracking how much work a programme gives the regulator. The removal standard itself is moving. OPRED consulted from September to November 2025 on a new derogation methodology under OSPAR Decision 98/3, restating the presumption of full removal and requiring operators to show that full removal is not reasonably achievable before applying to leave a structure in place. Its stated expectation is a substantial reduction in derogations. The same consultation proposes dropping the requirement that steel jackets be cut three metres below the seabed, which OPRED expects to reduce cost and remove a technical barrier to full removal. Both levers point one way: more structures coming ashore, each cheaper to sever. The government response was still outstanding at the time of writing.

Semi subs marketed on the UKCS, down from 11 in 2023

the forward book

Apache Forties and Beryl

Well-Safe · well P&A · Archer 7 platforms · 260+ wells

Brae Area

TAQA · Allseas · to 2033 £1bn

Brent Shell · Allseas, Able UK · to 2027 topsides ashore, gbs and wells remain

EnQuest portfolio Alma and Galia, Thistle, Heather, Greater Kittiwake four fields, platforms disembarked

Hewett Complex Eni · Scaldis EPRD 3 Of 6 platforms removed

GEN Intel · NSTA, OEUK, Well-Safe Solutions, Apache, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

THE BaSIN THaT SET THE PRICE

GEN INTEL • 2026 REGION 01 OF 08

A RECORD PIPELINE MEETS A SHRINKING FLEET The paradox is that this record pipeline is meeting a fleet that is getting smaller. The UK semi submersible market has contracted to six units marketed, down from a peak of eleven in 2023, and plugging is not the only claim on them: the same rigs are wanted for production well intervention and for carbon storage drilling. The regulator, not the supply chain, is the one saying that is not enough. The NSTA’s own assessment is that industry cannot fully execute the plugging and abandonment of inactive wells across 2026 to 2030 in line with current regulatory guidance and current supply chain capacity. Operators worked 257 wells in 2025 and brought 114 to final abandonment, up from 238 and 103 the year before. That is real improvement, and it still leaves the backlog of about 500 wells awaiting final abandonment broadly unchanged year on year. Against that backdrop came the defining award of the year. In April 2026 Apache handed Well-Safe a multi year contract to plug and abandon the platform and subsea wells of the Forties field, the cornerstone asset bp developed in the 1970s. The programme runs from 2026 into the mid 2030s. Apache has since extended the same model to Beryl. Taken together the two awards cover seven platforms and more than 260 wells, and the contracting chain below Well-Safe is now visible: Archer holds platform drilling, wireline and coiled tubing, and NMC Energy holds integration, commissioning and topside decommissioning. Platform well operations began on Beryl Bravo in summer 2026, subsea well decommissioning starts in 2027, and production across both fields is expected to cease by the end of 2029. Every one of those scopes was placed by Well-Safe, not by Apache. Apache has consolidated two entire fields into multi year campaigns under one lead contractor, transferring execution risk and locking up scarce capacity years ahead. That is the model the basin is moving to.

THE WAVE IS CONCENTRATED AND COMMITTED The forward book confirms it. TAQA is running a £1 billion Brae Area programme across Brae Alpha, Bravo and East Brae to 2033, alongside its Northern North Sea cluster of Cormorant Alpha, Eider, Tern and North Cormorant. Shell’s £1.5 billion Brent programme has cleared its topsides. All four platforms are ashore at Able Seaton Port, the last of them Brent Charlie at 31,000 tonnes, the largest single offshore topside ever lifted, transported and delivered to land. What remains is the gravity based structures, wells and pipelines, governed separately. Eni is closing out Hewett, where Scaldis holds the engineering, preparation, removal and disposal (EPRD) scope, has removed three of the six platforms and takes the remaining Central Complex this year. EnQuest, the operator just fined, holds one of the largest live portfolios on the shelf. The Energy Profits Levy and tax uncertainty have pulled cessation decisions forward, so more work is arriving sooner against less capacity. That is the defining tension of the UKCS to the end of the decade.

the gen view The UKCS reward is no longer won on a single tender. It is won on a framework. Consolidation is now measurable: one operator carries 17 percent of the decade’s decommissioning spend and the top ten carry more than 80 percent of it. Apache, TAQA, EnQuest, Shell, Eni, Harbour and NEO NEXT+ are the buyers to hold a position with, and they are buying multi year. Every UKCS programme named here is tracked live in the GEN Project Atlas.

GEN Intel · NSTA, OEUK, Well-Safe Solutions, Apache, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 REGION 02 OF 08

DISCIPLINED REGULaTION, LaTE LIFE Management

Norwegian Continental Shelf Norway decommissions less than the UK and earns more doing it. The strictest regime in the North Sea is also the highest margin.

by the numbers

orway runs the tightest decommissioning regime in the North Sea, and it has so far done comparatively little decommissioning. Both are true, and together they define the opportunity. Cessation is governed by the Petroleum Act with OSPAR Decision 98/3 as the international anchor. Full removal is the default and derogations are rare, granted only twice on this shelf, for the concrete substructures of the Ekofisk tank and Frigg TCP2. Across the whole OSPAR area only ten have ever been issued. The Frigg field, dismantled between 2005 and 2010, remains the largest disposal ever completed on the shelf, and sixteen years on nothing has displaced it. What has been removed since amounts to subsea and steel structures from the oldest fields and facilities from a handful of small shut down fields. This is a basin that wrote the rulebook and is still waiting to use it at scale.

500

THE SCALE IS SMALLER, THE STANDARD IS HIGHER

Fields cease 2026 to 2036

The shelf carries 96 operational platforms, 12 of them concrete, 64 fixed steel and 20 floating, plus around 500 subsea installations with heavy tieback dependency. The concrete facilities alone account for roughly 70 percent of the total installed weight on the shelf, which is the single hardest technical problem in the basin. The Norwegian Offshore Directorate expects 20 to 30 producing fields to cease over the next decade, and around 2,900 wellbores to be plugged in the years that follow. The regulator has named new technology explicitly as the lever to bring that cost down, which is an open invitation to rigless intervention and through tubing abandonment suppliers. The reason so little has moved yet is that Norway is still investing heavily in production. Ninety-seven fields were producing at the end of 2025, sector investment ran to around NOK 243 billion that year, and exploration has returned roughly four times the capital invested over the past 25 years. While those returns hold, cessation gets deferred. Norway recycles around 98 percent of decommissioned material, the highest rate in the world. For a contractor, the combination of full removal, concrete substructures and the strictest environmental standard is what makes the NCS a higher margin market than the UK. The volume is not here yet. The standard, and the price that follows from it, already is. The Directorate has now put a date on the deferral. Its Resource Report 2026, published in August, says production stays high to the end of this decade and then falls steeply without significant new discoveries, against roughly 7 billion standard cubic metres of oil equivalent remaining and about 9 billion already produced.

Operational platforms, 12 concrete

Subsea installations

20 to 30 ~98%

Steel material recovery, highest in the world

the forward book

Statfjord A Equinor · Allseas topsides ~50,000t

Equinor has already moved. It plans to permanently plug 80 subsea and 90 platform wells by 2030 against a stock of more than 1,400 operated production and injection wells, with a far larger campaign running from 2035 to 2045. How it buys that work has changed with it. Plugging now sits in frameworks rather than project awards, with a dedicated plugging rig contracted at around US$330 million over three years and separate framework positions for plugging services. The stated intent is to industrialise plugging so unit cost falls as volume rises. For a supplier the practical consequence is that scope is now set with the framework holder in the room, so the commercial conversation happens before the scope exists rather than after it.

Heimdal

Three features of the Norwegian regime explain the deferral better than the geology does. A decommissioning plan goes to the Ministry of Energy at most five years and at least two years before a licence expires or a facility is permanently shut down, so the pipeline is visible to the supply chain years ahead of the work, and the plan is not binding: the Ministry makes the disposal decision. Through tax deductions the State indirectly covers 78 percent of the cost of cessation and disposal, and more again on fields where it holds a direct interest, which is why the Directorate treats cost control as a public matter rather than a commercial one. And under section 10-8 of the Petroleum Act the licensees are jointly and severally liable to the State, with that liability surviving the sale of an interest and falling first on the most recent seller. Norway wrote trailing liability into statute. Operators are already trading around it. In August 2026 DNO transferred interests in the Kveikje and Heisenberg discoveries and the Romsås prospect to Equinor in exchange for a sharply reduced decommissioning deposit, freeing more than $35 million of near term liquidity against an obligation inherited with Sval Energi. Where the security is the binding constraint, the asset moves rather than the money.

$400m

Equinor · Heerema, Aker · to 2028 topside removal under way

Veslefrikk Equinor · Heerema, Aker · to 2028

Ekofisk ConocoPhillips · Heerema, AF Offshore Decom partial removal, tank derogated

STATFJORD A AND HEIMDAL ANCHOR THE AWARDED PIPELINE The awarded pipeline is anchored by two Equinor scopes. Statfjord A is the largest, with topsides of around 50,000 tonnes contracted to Allseas, among the heaviest single lifts ever attempted. Heimdal is the one already offshore. The main topside removal campaign began on 15 July 2026, with the heavy lift vessel Sleipnir mobilising to field and modules routed to Aker Solutions at Stord. The riser platform came off in 2025 and the work must complete by the end of 2028. Equinor’s Veslefrikk programme, at around $400 million, is awarded to the same Heerema and Aker Solutions partnership through to 2028. Ekofisk sits differently. ConocoPhillips has been running down the original cessation programme since 2007, no current total is published, and the Greater Ekofisk story now runs the other way: in February 2026 ConocoPhillips and its partners submitted a NOK 20 billion plan to restart production at three previously produced fields by the end of 2028. In the basin with the strictest removal standard in the North Sea, the largest recent Ekofisk commitment is to produce again.

VATS IS THE QUIET CAPACITY STORY The AF Environmental Base Vats yard is a strategic asset for the whole Northeast Atlantic. Its position at the head of the floating asset recycling cycle, taking the FPF-1 facility from the UK and building capacity ahead of demand, is a slow moving advantage that will matter through the 2030s. Companies with brownfield modification and tieback engineering capability should read the NCS as production extension and high specification removal work, not as a volume play. The Ekofisk model of partial removal and repurposing will be repeated. Equinor put numbers behind that in January 2026, awarding twelve five year maintenance and modification frameworks worth around NOK 100 billion in total across seven Norwegian suppliers, running from the first half of 2026. That advantage is now compounding. In August 2026 the AF Offshore Decom and Heerema consortium took its third UK Continental Shelf award from the same operator inside a year. Across the three contracts the consortium now holds the engineering, preparation, removal and disposal of more than 120,000 tonnes of platform structure, all of it routed to Vats, with the campaign running over the next decade.

GEN Intel · Norwegian Petroleum, Offshore Norge, OSPAR 98/3, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 REGION 03 OF 08

the backlog and the regulator

Gulf of Mexico The biggest backlog in the world, and a regulator that just changed its mind. The work is still coming, but not for the reason the market assumed.

he Gulf holds the largest installed base of offshore infrastructure in the world and the largest decommissioning backlog to match. As of June 2023 the GAO found more than 2,700 wells and 500 platforms overdue, with operators having missed the one year deadline on more than 40 percent of wells and half of platforms on leases that ended between 2010 and 2022. Total liability is estimated at $40 to $70 billion, against about $3.5 billion in bonds held. There are over 27,000 wells awaiting permanent isolation. The market runs at roughly $2 billion a year, and the work is shallow water, well understood and logistically intense.

THE FORCING FUNCTION SOFTENED The market’s working assumption was that the 2024 BOEM financial assurance rule, which would have compelled around $6.9 billion in supplemental bonding, was about to force a wave of retirements. That assumption is now out of date. The rule was challenged in court by Gulf states and industry, the litigation was stayed, and it was never fully implemented. In March 2026 the Interior Department proposed to roll it back, a change estimated to save industry about $484 million a year in compliance cost and framed openly as cutting red tape. The comment period closed in May 2026 and no final rule has issued. The forcing function has weakened, not hardened. What is driving the Gulf now is operator portfolio economics and idle iron enforcement, not the bonding rule. And the enforcement architecture itself is being consolidated. On 10 July 2026 the Interior Secretary signed the order establishing the Marine Minerals Administration, reunifying BOEM and BSEE and reversing the separation put in place after Deepwater Horizon. The transition is phased and the Department has stated that existing regulatory requirements stay in full effect through it. The regulator is being streamlined, not sharpened.

THE WORK MOVES ANYWAY And the work is moving regardless. ExxonMobil is progressing Hoover Diana at $120 million, where Aberdeen based EnerMech won the complete flowline decommissioning package on competitive tender, its first large scale decommissioning campaign in the Gulf. The route in was not a Gulf track record. It was seven years of ExxonMobil work in Guyana, running since 2018. APA is executing Eugene Island, and Chevron the West Delta wells inherited from Hess. A different kind of buyer is also appearing. Promethean Energy, which positions itself as a late life operator rather than a contractor, took an integrated award from a major in July 2026 covering five well abandonments, two structure removals, two pipeline abandonments and site clearance, with wells from summer 2026 and structures in 2027. Rigs to Reefs is the structural difference between this basin and the North Sea. More than 600 platforms on the US Outer Continental Shelf have been reefed, by tow and place, topple in place, or partial removal at a permitted navigational depth. Around 28 percent of structures slated for decommissioning take that route, at roughly a quarter of the cost of a full removal. For the supply chain this is why Gulf work is high volume and low margin per structure, and why the removal and recycling chain the North Sea supports at scale does not exist here in the same form. The point for the supply chain is that Gulf demand rests on operator decisions and idle iron liability, which do not reverse when a bonding rule does. W&T Offshore now spends more on abandonment than on capital projects, $34 million to $42 million a year against $20 million to $25 million of capital expenditure, and Talos has divested shelf assets specifically to shed the liability attached to them.

THE OBLIGATION FOLLOWS THE ASSET BACKWARDS Platform Holly off California is the case the Gulf has not yet had. Venoco quitclaimed the South Ellwood leases in 2017 and went bankrupt, leaving a $22 million bond against a decommissioning bill orders of magnitude larger. The California State Lands Commission seized the asset under its police powers, and ExxonMobil, as prior lessee, carries most of the cost. All 30 wells were plugged in 2024 and the platform now sits inactive and remotely monitored. The proposed project is full removal to five feet below the mudline, together with the pipelines, power cables and two seep tents. Partial removal, cutting the structure at least 85 feet below the surface, remains under consideration under California’s 2010 Marine Resources Legacy Act, though no platform in state waters has ever been converted under it. It would be the first platform decommissioning in California state waters since the Chevron 4-H removals in 1996. In federal waters Chevron has been decommissioning the Point Arguello platforms since 2020, with all 46 wells abandoned. Holly is not the only one. When Signal Hill Services defaulted on two further California platforms in 2020, BSEE determined that former lessees were liable, including Occidental at 37.5 percent on an interest it had sold roughly thirty years earlier. That determination is still being contested. The reach back is not theoretical, and it is not bounded by how long ago the seller left. This is the same trailing liability mechanism Australia legislated after Northern Endeavour, reached in California through insolvency and case law rather than statute. The obligation does not disappear when the operator does. It travels back to whoever held the lease before.

by the numbers

2,700+ Wells overdue (GAO 2023)

500+ Platforms overdue

$40 to 70bn Total liability

~$2bn Annual market

us offshore programmes

Hidalgo, Harvest, Hermosa Chevron · awarded $180m

Platform Holly State Lands Commission asset, ExxonMobil prior lessee wells plugged eir scoping complete

Hoover Diana ExxonMobil · awarded $120m

Eugene Island APA Corporation $100m

A REPETITIVE MARKET WITH FIFTEEN YEARS IN IT The Gulf is the world’s most operationally repetitive decommissioning market. Companies with shallow water jack up rigs, cementing services, dive support and barge logistics can find sustained work for the next fifteen years. Part of the UK supply chain that the NSTA worries about migrating overseas is heading here. The opportunity is to position before the larger Gulf specialists consolidate further.

T H E G E N V IE W Do not price the Gulf off the bonding rule. Price it off operator economics and idle iron, which are durable. This is a volume market rewarding repeatable, low cost execution, and the window to position is before the incumbents consolidate. Every Gulf programme named here is tracked live in the GEN Project Atlas.

GEN Intel · GAO-24-106229, BSEE, BOEM 2024 rule and March 2026 proposed rollback

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 REGION 04 OF 08

SUSTaINED RaMP UP, INFRaSTRUCTURE CONSTRaINED

Australia The most important emerging market for the supply chain. The work is real, the regulator is serious, and the capability has to be imported.

he Australian market has just been re-measured by the government itself. The Australian Offshore Oil and Gas Decommissioning Liability Estimate 2025, produced by Xodus for the Department of Industry, Science and Resources and published in November 2025, puts industry spend at AU$43.6 billion to 2070 in real terms, rising to AU$66.8 billion once inflation is applied. The real terms figure is actually down on the AU$61.8 billion estimated in 2020, as forecasting and execution have matured, but the inflated number is the one that captures the true scale of the bill. Around 55 percent of the work falls before 2040. Western Australia carries 61 percent of the liability, Victoria 23 percent and the Northern Territory 16 percent, with the Northern Carnarvon Basin alone accounting for more than half of the national total. At least 2.7 million tonnes of infrastructure has to come out, most of it steel. The scope covers more than 700 wells, 7,600 km of pipelines and 520 subsea structures. This is a market front loading real work into the next fifteen years.

THREE PROGRAMMES ARE ALREADY EXECUTING

ass Strait is the nation’s largest effort, a roughly $1 billion programme running to 2040. Woodside assumed operatorship from ExxonMobil on 1 June 2026, with equity in the Gippsland Basin Joint Venture unchanged at 50:50 and decommissioning provisions carried across intact. The asset base is 421 wells, 19 platforms, six subsea facilities and more than 800 km of pipeline. More than 220 wells are sealed, 69 of them in 2025 alone, the Pioneering Spirit is scheduled to begin lifting in 2027, and removed structures go to Barry Beach with a 95 percent steel recycling target. The first removal campaign cleared its regulatory gate in July 2026, when NOPSEMA accepted the environment plan and upgrades to the Barry Beach reception centre began. Chevron’s Barrow Island programme, known as WA Oil, covers around 888 wells across 2025 to 2031, alongside roughly 1,500 km of pipelines and flowlines and the associated processing and storage infrastructure. It is one of the largest and most complex petroleum decommissioning projects attempted in Australia, complicated by the island’s Class A Nature Reserve status and the quarantine protocols that follow from it. And the government run Northern Endeavour has completed Phase 1. Petrofac was the outsourced operator for the decommissioning and disconnection of the FPSO, which was then dry towed by COSCO and recycled at MARS Europe in Frederikshavn, Denmark, under a contract placed directly by the Department of Industry, Science and Resources, with Kent advising on recycling strategy and tender evaluation. Phase 1 is now operationally complete, including the disconnection and tow of the 274 metre FPSO.

by the numbers

aU$43.6bn

Liability to 2070, real terms, Xodus for the Australian Government 2025

aU$66.8bn Same liability with inflation applied

700+

Wells to P&A

7,600km

Pipelines, plus 520 subsea structures

55%

Activity before 2040

the forward book

Bass Strait Woodside · ExxonMobil 50 percent · to 2040 $1bn

Barrow Island WA Oil Chevron · 888 wells · Class A reserve 2025 to 2031

Ningaloo Vision FPSO Santos · awarded

Phase 2, the plug and abandonment of nine wells, was awarded to Zenith Energy Australia on 18 August 2026 after a competitive international tender. It runs in two stages, planning, engineering and regulatory approvals first, with the plugging campaign itself dependent on the outcome of that stage. Phase 3 covers the removal of the remaining subsea infrastructure, a comparatively modest scope of roughly 12,000 to 15,000 tonnes.

$500m

Phase 3a, the first tranche, is now out to tender in two stages with submissions closing 23 October 2026 and offshore execution subject to a Commonwealth gate after the planning stage. The recovered material goes to a nominated Australian port, not yet named. Environmental approvals for both later phases are already placed, so Phase 3 is the part of the programme still to be bought.

Northern Endeavour Ph2 and Ph3

Griffin, Scindian, Chinook Woodside · awarded $350m

Australian Government · Zenith Energy PH2 AWARDED, PH3 TENDER CLOSES OCT 2026

Well plugging and abandonment is the single largest line in the national estimate at AU$17.9 billion, with pipeline decommissioning almost level at AU$17.85 billion. The regulatory clock is what turns that liability into contracted work. NOPSEMA expects structures to be decommissioned within five years of production ceasing, wells plugged within three years and removed within a further two, and new resource management regulations took effect on 31 March 2026. The compliance backdrop is still tightening, not settling.

GEN Intel · Xodus, CODA, NOPSEMA, Australian Government, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

SUSTaINED RaMP UP, INFRaSTRUCTURE CONSTRaINED

GEN INTEL • 2026 REGION 04 OF 08

TRAILING LIABILITY CHANGED THE BEHAVIOUR Northern Endeavour is more than a project. After the original owner went into liquidation the Commonwealth took on the decommissioning, and the cost is being recovered from the offshore industry through a dedicated levy rather than absorbed by the public. Australia then introduced trailing liability provisions that now sit behind every operator decision. A second jurisdiction is following. The Victorian Legislative Council’s Environment and Planning Committee reported in June 2026 with 38 findings and 24 recommendations, among them that the state mirror Commonwealth trailing liability legislation so that companies rather than the public carry the cost. Victoria holds 23 percent of the national liability and Bass Strait sits inside it. That is why the awarded pipeline has broadened. Woodside is executing Griffin, Scindian and Chinook at $350 million and Stybarrow and Eskdale at $200 million, and Santos is running the Ningaloo Vision FPSO at $500 million. Bayu-Undan in Timor-Leste ended production in May 2025 against a published decommissioning liability of about US$1.1 billion, which would be avoided if the field is repurposed for carbon storage instead. Santos has also completed Harriet Alpha, the largest offshore platform ever removed from Australian waters, under a McDermott engineering, procurement, removal and disposal contract with Liberty Industrial on demolition and recycling. It is the clearest proof yet that Australian scopes can be delivered by an international and local contractor mix. Woodside has since closed out Enfield, its first full lifecycle decommissioning, plugging all 18 wells and recycling or reusing 99.6 percent of the recovered Nganhurra riser turret mooring. Not everything has run to plan. Subsea equipment removal at both Stybarrow and Minerva has been delayed pending alternative engineering solutions, with part of the Minerva pipeline still to come ashore. That sequence is trailing liability in practice. NOPSEMA directed BHP in 2021 to clear Griffin, Stybarrow and Minerva by mid-2025 after years of limited action, and Woodside inherited the obligation with the petroleum business in 2022. In July 2025 the regulator revised those directions following a series of incidents it called preventable, including a 16,000 litre spill at Griffin and pipeline saddles washing ashore near Minerva. It gave Woodside more time and attached tighter conditions to the work. The clock moves. What hardens is what a titleholder has to prove while it runs. The regulator’s reach has limits of its own. In the Reindeer case the Federal Court found that NOPSEMA is not legally required to satisfy itself that a titleholder has the financial capacity to decommission, and accepted a plan to preserve infrastructure in place rather than remove it. That gap is being addressed. The Department of Industry, Science and Resources consulted to January 2026 on reforms to offshore decommissioning and financial assurance, intended to keep titleholders responsible for the risks and liabilities of offshore activities, and asked whether the same arrangements should extend to greenhouse gas storage. Australia has identified the hole in its own regime and is consulting towards closing it. Preservation can therefore run on. Pilot Energy and Triangle Energy both ceased trading in July 2026, leaving a stranded asset off Dongara against an estimated $200 million bill. Trailing liability works while there is somebody left to carry it.

YARDS ARE THE BINDING CONSTRAINT The gap is not appetite, it is infrastructure. Reception and recycling capacity across Barry Beach, Henderson and Onslow is the single most binding constraint in the global system through 2028, which means imported capability is welcome and well paid. UK and Norway based companies should be opening Perth offices now if they are not already there. One thing is worth saying plainly about the Australian clock. The gate is approval, not engineering, and it is three gates rather than one. In July 2026 the Department of Industry, Science and Resources, the Department of Climate Change, Energy, the Environment and Water and NOPSEMA published joint guidance clarifying how the removal and sea dumping frameworks intersect, what cannot be left in the sea, and what may be assessed for leaving in limited circumstances. It introduces no new policy. It tells a titleholder how the existing gates are actually applied. NOPSEMA has to accept an environment plan, the EPBC Act runs a separate federal approvals track where a programme triggers it, and the onshore reception point is a consent again. Northern Endeavour is where that workload has been priced: the environmental approvals for both remaining phases are contracted to Xodus, which also produced the national liability estimate this page is built on. Because the programme is Commonwealth funded through the Department of Industry, Science and Resources, it is tendered through government process rather than an operator’s approved vendor list, which makes it the most accessible entry point in the country for a firm without an incumbent relationship. A contractor that can carry an approvals workload is selling something this market is short of. The GEN Australia office in Perth, and the APAC team led by Emma Davidson, are positioned to support engagement through CODA and the WA Department of Energy.

the gen view Australia is where a Perth presence pays for itself. The Bass Strait Pioneering Spirit campaign in 2027 will be a landmark for the supply chain, and recycling capability is the most strategic missing piece in the entire Australian chain. CODA, NOPSEMA, the Commonwealth Offshore Decommissioning Directorate and the WA Department of Energy are the entry points.

GEN Intel · 2026 Edition

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GEN INTEL • 2026 REGION 05 OF 08

THaILaND DELIVERS, MaLaYSIa STRUCTURES THE MaRKET

Southeast Asia A hundred billion dollars of work through 2030, and a UK operator has just bought a seat at the table.

outheast Asia faces around 200 offshore fields ceasing production by 2030, with total projected decommissioning liability near US$100 billion, concentrated across Indonesia, Thailand, Malaysia and Brunei. The wider APAC offshore population runs to nearly 2,600 platforms and around 35,000 wells on the 2018 WoodMac count. Annual contractor spend is a fraction of that liability, running at US$1.5 billion in 2024 and forecast to reach US$3.5 billion by 2035. Thailand is furthest ahead on delivered volume, with substantial removal work already executed. Malaysia is where the procurement is most structured and most accessible to new entrants. Indonesia, Vietnam and Brunei all have frameworks. Vietnam requires contributions to a decommissioning trust fund managed by PVN. Brunei is already executing, with Brunei Shell Petroleum awarding Serikandi Hilong the EPRD contract for redundant offshore structures in February 2025 against a national programme of more than 50 platforms and more than 70 pipelines. What the region lacks is not law. It is funded volume.

by the numbers

PETRONAS IS THE DISCIPLINED BUYER

PETRONAS Carigali is running a tender for the removal of up to 31 platforms, structures of 100 to 15,000 tonnes, split into Sarawak with 20 structures, Sabah with 4 and Peninsular Malaysia with 7. Awards are expected worth around RM2 to 3 billion, roughly US$450 to 700 million, with Dayang Enterprise the analyst front runner having bid all three packages, alongside EPIC, Reservoir Link and T7 Global, which has already completed well abandonment at Zuhal East. Velesto holds a five year rig contract, and around 35 Malaysian platforms are over 40 years old. PETRONAS is building local capability through its Hydraulic Workover Unit Academy and positioning itself as a regional hub.

Platforms in the PETRONAS tender

~200 Fields ceasing by 2030

US$100bn Total projected liability

35 Malaysian platforms over 40 years old

THAILAND, WHERE THE WORK HAS ACTUALLY BEEN DONE The single largest awarded programme in the region is not Malaysian, and neither is the region’s execution record. Chevron has been the clear regional leader on delivered decommissioning over the past decade, removing substantially more offshore structure in the Gulf of Thailand than any other operator in Southeast Asia. Under the terms of its expired Erawan concession Chevron retained responsibility for decommissioning 49 platforms and removing 53 subsea pipelines, while 142 usable platforms transferred to PTTEP as incoming operator. That programme targets 2028. Chevron has also reused wellhead platform topsides in the Gulf of Thailand, a first for the region, which points at reuse as a live alternative to full removal. Thailand’s procurement is less structured than Malaysia’s, but the delivered tonnage is where the regional experience sits. The legal framework is moving too. The Department of Mineral Fuels is preparing amendments to the Petroleum Act covering decommissioning security, concession extension and carbon capture. The draft has been in development since 2023 and is expected to go to public hearing in the second half of 2026.

INDONESIA, THE FUNDING GAP IS THE MARKET Indonesia has 634 offshore platforms, of which more than half are already over 20 years old against design lives of 20 to 30 years, and only seven have ever been decommissioned. The reason is not engineering. The Abandonment and Site Restoration funding scheme was made mandatory only for platforms sanctioned after 2010, so the large fleet installed in the 1970s and 1980s has little or no funding set aside. The only removal completed to date, the Attaka platform taken to a rig to reef site off Kalimantan, took seven years from decision to execution, held up by an absent funding provision and an undecided end of life strategy. Indonesia is a market where funding readiness, not technical readiness, decides when work releases, and where reuse and rig to reef are likely to feature more than full removal.

the forward book Gulf of Thailand ARP Chevron · awarded · 2028 $1bn

PETRONAS 31 platforms Carigali · bids under evaluation RM2 to 3bn

EnQuest Malaysia entry 4 assets from Petronas Carigali up to $833m

A UK DECOM LEADER BUYS IN The most telling move of the year ties this region to the UKCS. EnQuest, the North Sea operator, announced on 10 June 2026 that it will acquire four Malaysian assets from Petronas Carigali. The transaction comprises upfront consideration of $554 million, with total potential consideration of up to $833 million. Completion is expected on 31 December 2026 and is structured as a reverse takeover, with EnQuest’s shares expected to be readmitted in early January 2027. Once completed, the deal will shift nearly 70 percent of the company’s production to Southeast Asia. The Malaysian production sharing contracts carry annual abandonment cess payments into decommissioning funds managed with Petronas. The acquisition brings a UK decommissioning leader, and its expertise, directly into the Malaysian market.

T H E G E N V IE W Thailand is where the volume has been delivered. Malaysia is the entry point, and PETRONAS is the buyer with the most disciplined procurement. Companies targeting APAC should be MOGSC registered and engaged with the PETRONAS HWU Academy. The GEN Kuala Lumpur office, led by Nik Adoone Nik Ahmad, is positioned for exactly this market.

GEN Intel · PETRONAS Activity Outlook, MOGSC, Chevron Thailand, EnQuest, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 REGION 06 OF 08

PETROBRAS MOVES FROM PLANNING INTO EXECUTION

Brazil and Latin America The most underrated decommissioning market in the world is now moving from planning into execution, and the window to position is short.

razil’s ANP projects R$51.5 billion of offshore decommissioning investment between 2023 and 2027, rising to R$70.2 billion, about US$13 billion, by 2030, with around R$40 billion earmarked for the Campos Basin. Petrobras intends to remove 18 platforms between 2026 and 2030, seven fixed, seven floating and four semisubmersible, alongside abandonment interventions on 500 offshore wells and the recovery of 1,800 km of flexible lines. A further 50 platforms follow beyond 2031. This is a serious number attached to a single, methodical buyer. Petrobras has now put its own number against it. The 2026 to 2030 Business Plan commits US$9.7 billion to platform decommissioning and well abandonment over five years, trimmed from US$9.9 billion in the previous plan. The ANP figure is the sector projection. The Petrobras figure is the buyer’s committed capital, and it is the one to price against. The ANP’s director general has since put Brazilian decommissioning investment at R$17.8 billion in 2026, peaking at R$25.2 billion in 2031 and totalling R$158 billion across the ten years to 2036. The R$70.2 billion above runs to 2030. The longer window is the larger number.

by the numbers

r$70.2bn

Investment by 2030 (~US$13bn)

Platforms to remove, 2026 to 2030

Further platforms beyond 2031

MARLIM IS THE TEMPLATE, AND IT IS NOW AWARDED The Marlim field is the reference case, and it has moved from concept to contract. Petrobras is running a Marlim platforms decommissioning programme valued near $2 billion, awarded, targeting 2027, as eight platforms are removed and replaced by the new FPSOs Anna Nery and Anita Garibaldi under a revitalisation model. P-32 sustainable disposal is the reference and P-33 follows the same path. P-19 and P-26 went to online auction in February 2026. In November 2025, ANP rejected Petrobras’s revised development plan for Barracuda and Caratinga and limited the concession extension to 2035, which led to the P-43 decommissioning programme being approved by ANP in March 2026.

A DEEPENING FIELD LEVEL PIPELINE Below the flagship, a granular pipeline is forming. Petrobras is running a Campos Basin subsea equipment removal campaign at around $250 million, alongside field level plug and abandonment across Congro, Guaricema, Itaparica, the Corvina P-09 and the Albacora P-25. The first US$170 million P&A framework was awarded in 2025 under Resolution 817/20, and the next wave of framework awards is expected through the second half of 2026. The awards are now landing. OceanPact won a R$443.7 million contract in June 2026 for flexible line and riser recovery at P-18 on Marlim, taken on open competition. Four contractors are bidding the P-37 FPSO decommissioning. This is a competitive market, not a captive one.

BRAZIL HAS ITS OWN ENFORCEMENT MOMENT The UK is not the only basin where the regulator moved in 2026. On 7 July 2026, at the Office of the Attorney General in Brasília, Petrobras and the ANP signed a conciliation agreement covering 335 offshore wells left in temporary abandonment without monitoring. Petrobras pays R$300 million, about $58 million, retains responsibility for all 335 including the 76 whose management had transferred to other operators, and has until the end of 2030 to bring them into compliance against six monthly targets set by risk group. Compliance can be met three ways: permanent abandonment, temporary abandonment with monitoring, or return to production with monitoring. So this is not 335 plugging jobs, and 233 wells were already compliant at signature. What it is, is a second regulator putting a date and a price on a well backlog, and holding the original operator liable for wells it has already sold. That is the same principle the Gulf reached through insolvency on Platform Holly, reached in Brazil through settlement. The same regulator is easing in one place while it hardens in another. On 12 August 2026 the ANP held a public hearing on revising Resolution 854/2021 to move decommissioning financial guarantee submissions from annual to triennial, to cut the administrative load on operators and on the agency. Read the two together: a hard date on the well backlog, a lighter touch on the security behind it.

US$9.7bn

Petrobras committed decom spend, 2026 to 2030 plan

the forward book Marlim platforms

Petrobras · awarded · 2027 ~$2bn

Campos subsea removal Petrobras · awarded $250m

P-43 Barracuda

Petrobras · ANP approved tendering

Field P&A run

Congro, Guaricema, Corvina, Albacora multiple

THE WINDOW IS 24 MONTHS Petrobras procurement is methodical once it starts moving, and it consolidates around incumbent partners. The Campos Basin in particular is approaching mass retirement, with the older P series FPSOs lined up for disposal. Companies with FPSO disposal capability, South Atlantic marine logistics and Petrobras recognised local content partnerships should be moving now. The window for international firms to position is the next 24 months, before the frameworks close. The window is already being tested. Saipem signed a memorandum of understanding with Petrobras in May 2026 covering plug and abandonment and subsea decommissioning. It is a one year, non binding technical dialogue with no commercial commitment attached, and any work would need separate contracts. But it is a tier one contractor positioning in a market that has been largely Brazilian, and it was signed weeks before Brazil’s competition authority cleared the Saipem and Subsea7 combination. That is what the closing of a window looks like from the outside.

T H E G E N V IE W Brazil is underrated and moving. The prize sits with FPSO disposal, South Atlantic logistics and local content partnerships that Petrobras recognises. Companies should engage now, before frameworks consolidate. Every Brazilian programme named here is tracked live in the GEN Project Atlas.

GEN Intel · ANP Resolution 817/20, Petrobras programmes, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

CHALLENGE ACCEPTED

Global Decommissioning Excellence Proven in the North Sea

25+

Years of subsea innovation

100%

Success in diverless blind flange installation

£450m 95%+ UKCS projects delivered

Materials reused or recycled

deepoceangroup.com

GEN INTEL • 2026 REGION 07 OF 08

INDIGENOUS OPERATOR TRANSITION

West Africa The long horizon, not the near one. But the transition that makes decommissioning happen is already under way.

est Africa is the least developed decommissioning market among the major hydrocarbon basins, and it is also where the largest structural transition is taking place. The international majors are exiting mature onshore and shallow water assets, and indigenous operators are taking ownership and inheriting the decommissioning obligations attached. The pattern mirrors the IOC exit from the UKCS over the past two decades, compressed into a few years.

key facts

$2.4bn THE HANDOVER IS THE STORY Shell completed its $2.4 billion exit from the SPDC onshore joint venture in March 2024, transferring assets to the Renaissance Africa Energy consortium. ExxonMobil sold its onshore Nigerian assets to Seplat Energy. Tullow and its partners signed an agreement to establish a decommissioning trust fund for the Greater Jubilee field offshore Ghana in April 2024, and Afentra holds a 30 percent non operated interest in Block 3/05 offshore Angola. The first offshore decommissioning project in Angola, on the Safueiro field, is running in phases under Ministry of Mineral Resources, Oil and Gas oversight, with EQS leading the early phases. The jacket is to be toppled and left as an artificial reef. Topside equipment removal and structural cutting is the final phase and has not yet been executed. And Angola’s largest private operator, Etu Energias, has agreed to buy Chevron’s 31 percent operated interest in Block 14 and 15.5 percent in Block 14K for a base $260 million, after exercising pre-emption rights against an agreed sale to Energean. Etu takes 60 percent of Block 14 and intends to assume operatorship, subject to ANPG approval, with completion expected in early 2027. Chevron retains Block 0. The funding mechanism matters more than the handover. Angola has one. Presidential Decree 91/18 of 10 April 2018 sets the rules for well abandonment and facility decommissioning, and it goes further than a process: it covers the provisioning, methodology and cost estimation of abandonment funds, the terms of the escrow account, and the certificates that release liability on handover. A separate regulation governs investing part of those funds in Angolan sovereign debt, which tells you the money exists to be invested. Ghana’s Jubilee partners moved because they built a trust fund. Nigeria has just rewritten its own. NUPRC issued the Nigerian Upstream Petroleum Decommissioning and Abandonment Regulations 2026 under the Petroleum Industry Act, repealing the 2023 regulations and reforming the timing of decommissioning plan submissions, the establishment and management of the Decommissioning and Abandonment Fund, and the administration of operator compliance. A National Assembly committee is separately examining whether the plans and escrow arrangements behind those obligations are adequate.

Shell SPDC exit to Renaissance, March 2024

$4bn Chevron Angola Blocks 0 and 14, on hold

6 WELLS Saltpond Ghana, all sealed, platform removal in final phase

2030s When the market arrives at scale

Across the region the question to ask of any announced transfer is not who now holds the licence. It is whether the abandonment fund travelled with it.

THE FIRST REMOVAL IS ALMOST DONE Two projects define the region’s current activity, and one of them is nearly finished. In Ghana, GNPC has been decommissioning the Saltpond field since 2022, the first project of its kind in the country, with Ghanaian contractor Hans and Co working on the Mr Louie platform. The scope covers permanent sealing of all six wells, removal of pipework and dismantling of the platform to return the seabed to its pre licence condition. GNPC has reported all six wells sealed and the work around 60 percent complete. The final phase has run late, held up by contractual and cost verification processes including mandatory third party technical assessments, and GNPC was still consulting coastal communities on the resumption in early 2026. Chevron is at conceptual stage on a roughly $4 billion Angola programme across Blocks 0 and 14, currently on hold. Everything else in the region remains a well integrity or operations support scope rather than a removal.

POSITION IN THE SUPPLY CHAIN, NOT THE REMOVAL The smart positioning for the supply chain is to be in the operations support supply chain now, in vessels, well services, marine logistics and safety services, and let decommissioning emerge as a natural extension of existing relationships. Renaissance, Seplat, Afentra and Tullow are the operators to engage. This is a 2030s market in earnest, so the risk is investing too heavily ahead of demand.

T H E G E N V IE W West Africa is the long horizon. The IOC to indigenous operator transition is the precondition for decommissioning at scale, and it is still incomplete. Be in the operations support supply chain now and let decom follow. GEN's growing Africa coverage through Kwasi Senya is positioned to support regional engagement.

GEN Intel · NIPEX, operator disclosures, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 REGION 08 OF 08

LATE LIFE MANAGEMENT, FIRST PROGRAMMES LANDING

Middle East and other regions Small, late, but no longer zero. The first awarded programmes have landed, and the production extension work is here now.

he Middle East accounts for under 5 percent of global decommissioning expenditure and will stay marginal through 2030. Major fields have engineered lives that extend well beyond 2050, and operators are extending life rather than retiring assets. Saudi Aramco’s management of Safaniya, Manifa and Ghawar focuses on enhanced oil recovery and brownfield modification. ADNOC’s Zakum fields run under similar long life programmes, and QatarEnergy’s North Field is in expansion, not retirement.

THE FIRST AWARDS CONTRADICT THE “NOT YET” STORY But the absolute version of “not yet decommissioning” is no longer accurate. Three programmes have now moved into contract. Subsea7 holds an Aramco award at Abu Safah under a long term agreement, classified by Subsea7 as substantial, a band of $150 to $300 million. The scope covers decommissioning of existing subsea facilities alongside a new pipeline and subsea equipment, with offshore work from 2026. QatarEnergy awarded McDermott a decommissioning definition engineering contract in February 2026, the first of its kind in the country, covering the framework and techno-economic studies for the retirement of 27 ageing platforms and their subsea infrastructure across the Al-Karkara, Idd El-Shargi and Maydan Mahzam fields. And the Ras Al Khaimah Petroleum Authority has contracted Northern Offshore’s jackup Energy Emerger to plug and abandon nine wells across six platforms in the Saleh field. Limited activity also exists in the Egyptian Gulf of Suez, where shallow water platforms from the 1970s and 1980s are reaching the end of economic life.

first awarded programmes

27 PLaTFORMS QatarEnergy definition engineering, McDermott, Feb 2026

$150 TO 300M Abu Safah, Subsea7 under Aramco long term agreement, substantial band

9 WELLS, 6 PLaTFORMS Saleh field P&A, RAKPA and Northern Offshore

2035 THE OTHER REGIONS, BRIEFLY

When the region scales

China holds the largest national share of the APAC decommissioning market, with CNOOC managing a substantial late life portfolio in Bohai Bay and the South China Sea, handled almost entirely by domestic contractors such as COOEC, COSL and Shanghai Salvage. Eni leads the Italian Adriatic with around 130 platforms still producing. The Dutch sector is further ahead than its size suggests, and the way the work is bought there is the instructive part. Eni Energy Netherlands runs its well decommissioning as a rolling campaign under a single contract amendment, releasing ninety day increments against options rather than tendering field by field. One jack up has carried that campaign continuously since August 2023 across roughly twentyfive wells in both Dutch and UK waters and for three different operators. Nothing about that is visible as a tender. An operator watching procurement portals for Dutch decommissioning work would conclude the market was closed. Canada’s Terra Nova FPSO is the major near term candidate on the East Coast following its 2022 refurbishment, and Trinidad’s mature shallow water assets face decommissioning at small scale.

PRODUCTION EXTENSION IS THE NEAR TERM PLAY For the supply chain, these markets are not the decommissioning opportunity of the next decade. They are the production extension opportunity. Position on brownfield modification, late life production support, EOR and gas expansion. The decommissioning conversation in the Middle East will emerge from 2035, and by then the lessons from the North Sea and Australia will be fully exported.

T H E G E N V IE W Treat the Middle East as a production extension market with a decommissioning tail. Position on brownfield, late life support and EOR now, and track the first awarded programmes as proof the tail is starting. China remains a domestic market for now. The decom scale is a 2035 story.

GEN Intel · Saudi Aramco, QatarEnergy, Ras Al Khaimah Petroleum Authority, CNOOC, Eni, GEN Project Atlas

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 OUTLOOK SECTION 08

BEYOND OFFSHORE OIL aND GAS

Nuclear, refineries and power Decommissioning is bigger than offshore oil and gas. The Atlas proves it, and the same supply chain can work all of it.

ffshore oil and gas is the core of this report, but it is not the whole decommissioning market, and companies that read it as such leave a larger opportunity on the table. The GEN Project Atlas tracks the adjacent sectors alongside offshore, and they are substantial. The core competencies are the same across both: heavy equipment and engineering, waste and hazardous waste management, health and safety, and project and risk control.

THE aDJACENT SCaLE

$70bn Fukushima Daiichi decommissioning, inside a US$188bn total

$135bn+

he UK’s nuclear decommissioning legacy alone exceeds $135 billion, dwarfing the offshore market.

UK NDA legacy over the next century

NUCLEAR IS THE LARGEST SINGLE SCOPE OF ALL Globally the numbers dwarf the offshore market. The Atlas tracks Fukushima Daiichi at around US$70 billion for decommissioning, the figure to use rather than the US$188 billion total that includes compensation and decontamination. San Onofre at $4.7 billion, Three Mile Island, Indian Point, the full German phase out fleet run by RWE, EnBW and PreussenElektra, and the Japanese, Taiwanese and Korean programmes. In the UK the Nuclear Decommissioning Authority legacy exceeds $135 billion over the next century, led by Sellafield. This is a multi decade market that runs alongside the offshore wave, not after it. And it is contracting now, not eventually. In October 2025 Sellafield placed up to £2.9 billion of non nuclear site infrastructure under a single Infrastructure Delivery Partnership, split three ways across electrical distribution, utilities and civils, for nine years with an option to 2040, and alongside it up to £4.6 billion of decommissioning and waste retrieval under a second framework on the same term. None of the infrastructure work is reactor work. It is power, water, roads, rail, bridges and foundations, bought to nuclear standards on a nuclear licensed site, and it is the clearest illustration of the point: most of the money in decommissioning is spent on capability that is not sector specific at all.

REFINERIES AND POWER ARE OPENING NOW As European hydrocarbon use declines, refineries are closing. Grangemouth in Scotland is the flagship European case, and its closure is opening significant demolition and decommissioning scopes. It is a smaller market than offshore, served by fewer contractors, but a growing one. In power generation, legacy coal plant continues to come offline across Europe, with the UK ahead and activity migrating to Southern and Eastern Europe, while the earliest onshore and offshore wind farms are now passing through repowering into the removal phase and will draw on the same supply chain as oil and gas.

T H E G E N V IE W The supply chain that works offshore is largely an extension of the one that operates in nuclear, power and heavy demolition. Companies concentrated in a single sector face cyclicality. Companies positioned across offshore, nuclear and refinery decom capture a broader, steadier pipeline. Every one of these markets is mapped in the Atlas, so companies can see where the supply chain already has capability and where the gaps sit.

GEN Intel · GEN Project Atlas, Nuclear Decommissioning Authority, Sellafield Ltd

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 OUTLOOK SECTION 09

WHERE THE STEEL aCTUaLLY GOES

The recycling chain The removal contractor without a yard is now bidding incomplete. Operators are writing recycling into the contract, and the yard owner takes the high margin position. Operators now sign decommissioning contracts with end of chain recycling commitments embedded. TAQA targets 95 percent material reuse on Brae Alpha, ExxonMobil 95 percent steel recycling on Bass Strait, and Norway recycles 98 percent of decommissioned material. The implication is straightforward. A removal contractor without a confirmed reception base and recycling chain partner cannot fulfil the contract, and is increasingly uncompetitive against one that can. The model is already visible in the awards. AF Offshore Decom, which owns the Vats reception base, is winning UK Continental Shelf removal work in consortium with Heerema, which owns the vessels. Yard plus heavy lift, bidding as one. That is what a complete bid looks like.

Yard plus heavy lift, bidding as one. That is what a complete bid looks like. The capacity picture varies sharply by region. Australian reception capacity is the single biggest binding constraint in the global system through 2028, because Barry Beach, Henderson and Onslow combined cannot absorb Bass Strait, Barrow Island and Northern Endeavour Phase 2 at once. European capacity is tighter than it was but more elastic, with Vats and Stord built ahead of demand and Danish yards taking cross border traffic. UK yard capacity has been the anomaly, underused while UK structures were routed to Norway and the Netherlands. Hewett went to Vlissingen and the Ithaca floaters to Vats. That is now shifting. Allseas has placed the Cormorant Alpha and Tern topsides, 47,500 tonnes combined, with Able UK at Seaton Port from 2027, targeting up to 97 percent reuse and recycling, while Eider Alpha went to Vats. Where the tonnage lands is a commercial question for the basin rather than a capacity one. The Gulf has the most extensive yard capacity relative to demand. Brazil and Southeast Asia are the least developed, and operators there are increasingly shipping to Europe or Australia, adding 10 to 25 percent to total project cost. Marlim Leste is that pattern in practice. The Cidade de Niterói has left the field and is at a Danish recycling yard, with the subsea and well scope still to run. The UK case is now proven at scale. Harbour Energy completed a 38 platform Southern North Sea removal programme in 2025, begun in 2019, with around 80,000 tonnes dismantled in the UK at Veolia’s yard in Great Yarmouth and Able’s facility at Hartlepool, and recycling rates consistently above 97 percent. The final five platforms came off across two campaigns in August and November 2025, the second deliberately scheduled around a kittiwake nesting season. Thirty eight structures, one basin, UK yards throughout. Reception capability is also widening beyond lifting and cutting, with recent Norwegian subsea scopes covering dredging as well as recovery, because structures long buried on the seabed have to be excavated before they can be lifted.

REGION

KEY YARDS

NOTABLE CAPABILITY

Americas

MARS Louisiana, Gulf Copper, Brownsville

Most extensive yard capacity relative to demand

Asia Pacific

Lumut and Labuan (Malaysia), Batam (Indonesia)

Growing PETRONAS supply chain reception, FPSO disposal routes

Australia

Barry Beach (Vic), Henderson and Onslow (WA)

Bass Strait hub, WA hub building; the tightest link in the global chain

Brazil

Porto do Açu (São João da Barra), Rio Grande

Berthing and pre decommissioning hub, three berths expandable to ten

Denmark

MARS Europe, Frederikshavn

Northern Endeavour FPSO recycled here, cross border capacity building

Norway

AF Vats, Aker Stord

FPF-1 and Yme received at Vats, more than 120,000 tonnes of UKCS platform structure contracted to Vats across three consortium awards, heavy structure handling and module dismantling at Stord

United Kingdom

Able UK Hartlepool and Seaton Port, Veolia Great Yarmouth, Veolia Aberdeen, Dales Marine, John Lawrie

All four Brent topsides received, over 97 percent recovery, 47,500 tonnes of TAQA Cormorant Alpha and Tern topsides arriving from 2027

Exhibit: reception and recycling capability by region. Source: AF Gruppen, Able UK, MARS Europe, operator recycling disclosures.

T H E G E N V IE W If a company has reception base, dismantling or recycling chain capability, particularly in Australia, this is the moment to position. The yard owner takes a high margin seat in any supply chain, and operators are writing recycling commitments the removal contractor cannot meet alone. Companies without a confirmed yard partner should secure one this quarter, especially for Australian, Brazilian and Southeast Asian bids.

GEN Intel · AF Gruppen, Able UK, MARS Europe, operator disclosures

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 OUTLOOK SECTION 10

SECOND LIVES FOR LEGaCY INFRaSTRUCTURE

The CCS and repurposing bridge Not every depleted asset gets removed. Some get a second life as carbon storage, and a different supply chain with different timing.

he infrastructure already in place, platforms, pipelines, wells and subsurface knowledge, can become the foundation of the next business rather than a liability to remove. Where a depleted field sits near a viable storage site, the economics of conversion can be dramatic, as the comparison below sets out. This matters to the supply chain in two ways. Repurposing is a different procurement event from decommissioning, with a different supply chain and different timing. And the decommissioning schedule on adjacent assets shifts, so a platform that might have been removed in 2028 becomes a CO2 receiving hub in 2030. The NSTA ran its second carbon storage licensing round with 14 areas on offer. It closed on 24 March 2026 with five firms applying for more than 2 million acres, and awards are expected early 2027. The response was thinner than the first round, which drew 19 applicants and produced 21 licences across 2.94 million acres. The acreage held up. The number of bidders did not. The UK Continental Shelf holds roughly 78 billion tonnes of CO2 storage potential, about a third of all European capacity.

Three procurement opportunities emerge that are distinct from pure decommissioning. Subsurface conversion engineering, re-evaluating depleted reservoirs for injection and modelling plume migration. Well integrity and re-rating, since CO2 bearing wells need assurance more stringent than late life production wells. And pipeline re-rating and conversion, where legacy gas lines carry CO2 after pressure integrity work. All three are open to companies without full removal capability. The second of those is already contracted. Aquaterra Energy holds scope on the Northern Endurance Partnership covering safe re-abandonment of two legacy wells by vertical well re-entry tieback, and has begun fabricating the first Recoverable Abandonment Frame system. Wells drilled for production are being re-entered and re-abandoned to a CO2 standard, a scope that did not exist as a market five years ago. Hewett shows the two markets meeting on one asset. Eni is removing all six platforms through Scaldis while holding a carbon storage licence over the same depleted reservoirs, with around 300 million tonnes of storage capacity and the first appraisal well drilled in 2025. The field goes from removal straight into carbon storage without an idle period between them. Where that pattern repeats, the decommissioning contractor and the storage developer are working the same asset on overlapping timetables.

beatrice field: decommission versus repurpose

£260m

around 10x lower

£26m Decommission

The Beatrice comparison is the clearest single number in the repurposing case. Decommissioning the platform outright was costed at £260 million. Converting it to receive captured CO2 over thirty years was costed at £26 million, around a tenth of the price, while creating a revenue generating asset rather than a liability to be retired. The Acorn project applies the same logic at scale, saving an estimated £648 million by reusing legacy pipelines and platforms rather than building new infrastructure.

Repurpose for CO2

Source: University of Edinburgh study, Beatrice field.

PROJECT

LEAD

LEGACY ASSET REPURPOSED

Acorn (Scottish Cluster)

Storegga, Shell, Harbour

Goldeneye depleted field, 102 km pipeline

HyNet North West

Eni

Hamilton and Lennox depleted fields, Liverpool Bay

Morecambe Net Zero

Spirit Energy

Morecambe depleted fields, East Irish Sea

Northern Endurance

bp, Equinor, TotalEnergies

Endurance saline aquifer, Southern North Sea

Viking CCS

Harbour Energy

Viking depleted field, repurposed pipeline route

Exhibit: UK CCS projects reusing oil and gas infrastructure. Norway's Northern Lights and Denmark's Greensand follow the same model at scale.

T H E G E N V IE W Repurposing reshapes supply chain demand, it does not reduce it. The contractor mix shifts towards subsurface engineering, well integrity and pipeline re-rating. Companies positioned at the boundary between decommissioning and CCS conversion are sitting on the most valuable corner of the market through 2027 to 2032. Treating CCS as someone else's industry leaves margin on the table that competitors are already capturing. The second licensing round is a caution on pace, not on direction. Fewer bidders means fewer and larger developers, which concentrates the supply chain opportunity rather than removing it.

GEN Intel · University of Edinburgh, NSTA carbon storage round, operator statements

The Next GEN of Media globalenergynetwork.net

GEN INTEL • 2026 OUTLOOK SECTION 11

who executes the work

The contractor landscape A small, capital intensive top tier sets the ceiling on what can be executed. Below it, the specialists are consolidating, and operators are transferring execution risk to them. The top tier of global decommissioning contractors is small and capital intensive. These are the firms that own the heavy lift vessels and increasingly take on end to end campaign delivery for operators looking to transfer risk. Allseas holds the Pioneering Spirit and Solitaire. Heerema operates the Sleipnir and Thialf semi submersible crane vessels. Saipem and Subsea7 are progressing a merger that will form Saipem7 with a combined backlog near €43 billion. The timetable now sits with the regulators rather than the parties. Brazil’s antitrust authority cleared the combination in June 2026 and the United States antitrust waiting period has now expired. Clearance is not universal. The European Commission opened a full Phase 2 investigation on 22 July 2026, and the Australian competition regulator has moved the deal to an in depth review on the same grounds, competition in subsea umbilicals, risers and flowlines. The Commission stopped the clock in late August pending further information from the parties, so the decision date is now open and completion could slip into 2027. Until it closes they remain separate contracting entities. TechnipFMC and McDermott remain central to subsea and pipelay scopes. Below that tier the structure is consistent and it is not a single chain. A marine contractor holds offshore removal and a yard holds onshore reception, dismantling and recycling, and they are contracted separately, frequently in different countries. Brent went to Allseas offshore and Able UK at Teesside onshore. Heimdal and Veslefrikk went to Heerema offshore and Aker Solutions

at Stord onshore. Ithaca split its floating units between Subsea7 off station and AF Offshore Decom at Vats. Offshore buys marine support, survey, cutting, sea fastening and preparation. Onshore buys cutting, waste handling, materials recovery, logistics and labour. A supplier has to decide which end of the chain it serves, because approaching the operator reaches neither. A second model is worth watching. On the Miller and Don subsea scopes, completed in 2025, bp transferred title of the infrastructure to DeepOcean under a sale and purchase agreement, the first of its type in the North Sea. The contractor owns the removal methodology and the recycling revenue, and the operator carries oversight rather than delivery. More than 95 percent of recovered material was recycled, and the model has been carried straight into the Foinaven riser and umbilical removals starting later in 2026. Where an operator will sell you the steel rather than pay you to cut it, the commercial shape of the work changes completely. One contractor has gone further than framework. Well-Safe Solutions has taken its first full well operatorship contract, mobilising the Well-Safe Defender from June 2026. Under well operatorship the licence holder steps back entirely and subsurface analysis, well design, rig selection, vessel provision and every subcontract sit with the contractor. On a campaign contracted that way, a supplier approaching the operator reaches nobody at all.

The year’s biggest structural shift came a tier down, in well plugging and abandonment. Well-Safe Solutions won the Apache Forties award, the largest North Sea decommissioning contract to date, then added Beryl. Archer sits inside that framework on platform drilling and well services. That is the model operators want, and it consolidates scope with the specialists that can deliver it.

landmark contract awards, 2025 to 2026

DATE

CONTRACTOR

OPERATOR

SCOPE

EnerMech

ExxonMobil

Hoover Diana flowline decommissioning, first major Gulf campaign, Aberdeen based

Sep 2025

Allseas

TAQA UK

Brae Alpha EPRD, 95 percent recycle target, exec 2028 to 2032

Sep 2025

THREE60 Energy / AF Offshore Decom

bp North Sea

Andrew integrated decommissioning services, around $400m, first of its kind on the UKCS, to 2031 to 2032

Oct 2025

Heerema

bp North Sea

Andrew EPR, topside and jacket removal, following drilling equipment set removal in 2024

Dec 2025

Helix Energy Solutions

Undisclosed major, UK North Sea

Riserless P&A on up to 34 subsea wells, from 2026

Dec 2025

Well-Safe Solutions

EnQuest

UKCS well decommissioning frame, in excess of $45m, 100 days 2026 and 130 days 2027

Jan 2026

AF Offshore Decom

Ithaca Energy

FPF-1 recycling, NOK 225 to 275m

Feb 2026

AF Offshore Decom

Ithaca Energy

Alba floating storage unit dismantling, around 24,000 tonnes to Vats, second Ithaca award in five weeks

Q1 2026

T7 Global / Tanjung

PETRONAS Carigali

Zuhal East well abandonment, Malaysia

Apr 2026

Well-Safe Solutions

Apache North Sea

Forties well P&A, $1bn+, largest UKCS award to date

Apr 2026

NSTA enforcement

EnQuest Heather

£16.5m fine, 33 wells, first collective decom fine

Jun 2026

OceanPact

Petrobras

P-18 Marlim flexible line and riser recovery, R$443.7m

Jul 2026

AF Offshore Decom / Heerema

Undisclosed, UKCS

Topsides removal, 38,500 tonnes, to Vats, second consortium award of 2026

Jul 2026

CB&I Asset Solutions

EnQuest

Kittiwake duty holder extended through CoP and decommissioning

Jun 2025

2026

Island Drilling, Archer Oiltools, Baker Hughes Norge

Equinor NCS

Plugging frameworks, rig scope around US$330m over three years

2026

Well-Safe Solutions / Archer

Apache North Sea

Beryl P&A, 7 platforms and 260+ wells across both fields

2026

Petrobras framework

Petrobras

Marlim platforms decom, ~$2bn, target 2027

2026

Chevron Thailand

Chevron

Gulf of Thailand Asset Retirement, ~$1bn

Undisclosed, UKCS

Third award from the same operator, more than 120,000 tonnes across three contracts, all to Vats

Aug 2026

AF Offshore Decom / Heerema

Aug 2026

Noble Corporation

ConocoPhillips Skandinavia

Noble Interceptor jackup, 670 day Greater Ekofisk well P&A from Q3 2027, first Noble award on the NCS

Aug 2026

Valaris

Undisclosed, UK North Sea

41 well P&A, VALARIS 248, 1,080 days from mid 2027, around $140m

Aug 2026

Zenith Energy Australia

Australian Government

Northern Endeavour Phase 2, nine well P&A, Laminaria-Corallina

Exhibit: the awards that set the direction of the market over the past year. Source: operator and contractor statements, NSTA.

GEN Intel · Allseas, Heerema, Saipem, Well-Safe, operator statements, GEN Project Atlas

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GEN INTEL • 2026 OUTLOOK SECTION 12

SUPPLY CHaIN CaPaBILITY

Where the supply chain is deep A market overview tells you where the work is. This tells you where the accessible supply chain is deepest, and where capacity is thin.

This maps the accessible decommissioning supply chain against the service categories the market requires across the eight regions. Individual companies are not named. The result answers a different question from whether the market is growing. It answers where the supply chain has credible execution capability today, and where the gaps are that new entrants should fill.

CAPABILITY CATEGORY

Capability is deepest where the market is deepest: engineering and project management, well plugging and abandonment, well services and subsea, each with dozens of companies holding credible capability. For an operator sourcing suppliers, that means multiple competitive options exist for most core work scopes. The gaps matter just as much, because they are where the growth is. FPSO disposal, recycling and yards, and hazardous waste are thin against markets that are scaling fast, while heavy lift vessels and drilling rigs are the scarcest categories of all, which is exactly why the capacity heat map runs red.

COMPANIES WITH STATED CAPABILITY

2+ REGIONS

COVERAGE

Engineering and project management

Strongest

Well plugging and abandonment

Strong

Well services and intervention

Subsea infrastructure removal

Surveys and integrity inspection

Diving services and ROV Marine logistics and supply Cutting, conductor recovery, tools

Hazardous waste and environmental

Gap, growth

Pipeline removal and disposal

Strong

Legal, advisory, regulatory

Strong

Recycling, reception base, yards

Gap

Heavy lift vessel charter and ops

Scarce, critical

Gap, high opportunity

Drilling rig charter, jack up and semi FPSO disposal capability

9 6

Exhibit: decommissioning supply chain capability by category. Teal denotes a strong, competitive category. Amber denotes a capability gap or a strategically scarce, high value category. Companies with stated capability, anonymised.

T H E G E N V IE W The three biggest gaps, FPSO disposal, recycling and yards, and hazardous waste, are all growth markets through 2030 as Bass Strait, Marlim and Northern Endeavour type programmes scale. Companies with capability there face less competition for the work coming. Heavy lift and drilling rig owners are the scarcest and most strategically important capabilities in the market, and command pricing power when the heavy lift schedule is fixed.

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GEN INTEL • 2026 OUTLOOK SECTION 13

WHaT THIS MEaNS aND WHaT WE DO aBOUT IT

The GEN View, and what to do next Position for the work coming, not the work that was. Five moves define the decade, and one window is open right now. One pattern runs through every emerging market in this report. What releases the work is not engineering readiness, it is funding provision. Indonesia’s platforms wait because the abandonment fund only covers post-2010 assets. Ghana’s Jubilee partners moved because they established a funded trust. The US Gulf backlog persists because bonds cover a fraction of the liability. Brazil’s wells are moving because a regulator attached a paid penalty and a hard date. For a supply chain company, the signal to watch in any basin is not the size of the liability. It is the moment the money to pay for it is secured.

Treat the next decade as a sustained execution market, not a project market. Companies that win frameworks with Apache, TAQA, EnQuest, Petrobras, PETRONAS and ExxonMobil in 2026 hold those positions into the early 2030s. Campaign frameworks are now the norm.

Build genuine recycling capability. The 95 percent target is now a procurement standard. Companies that can prove end of chain custody win on differentiation, not price.

Treat enforcement as urgency on the buy side. The UK, Australia and Brazil are hardening while the Gulf loosens. Companies that mobilise quickly and execute compliantly command premium dayrates in the tightening basins.

Follow the vessel. Pioneering Spirit, Sleipnir, Thialf and the leading well intervention semis are the binding constraint. Companies supplying vessel related services should position around where these vessels go, not chase individual tenders.

Position across multiple basins and sectors. The UK is mature, Australia ramping, Brazil opening, Malaysia the next wave, nuclear running alongside. A single basin is cyclicality. Three or four is compound exposure to a supercycle.

WHaT GEN PROVIDES

gen project atlas

ops map & intel cycle

events & access

More than 5,600 projects tracked, 172 decommissioning and repurposing programmes, 136 of them offshore.

A verified position database for 167 rigs, FPSOs, jack ups and pipelay vessels, plus the weekly 16 report Intel cycle. Pulse flags tenders, Wire tracks appointments, Yard tracks newbuilds, Ledger tracks dayrates.

WAES London, 1 to 2 December 2026, includes dedicated decom programming: a Pioneering Spirit operator panel, a CODA panel on Australia and a PETRONAS Activity Outlook briefing.

T H E SIN G L E B IG G E ST O P P O R T U N IT Y R IG H T N OW Companies with capability in well P&A, subsea, heavy lift, recycling or floating asset disposal should position for the three contract tranches arriving across 2026 to 2028: the Apache Forties and Brae Alpha programmes on the UKCS, the Bass Strait Pioneering Spirit campaign in 2027, and the PETRONAS 31 platform packages across Sarawak, Sabah and Peninsular Malaysia. MOGSC registration is the prerequisite for the last of these.

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GEN INTEL • 2026 DATA APPENDIX A

data appendix

Global forward pipeline Every project below is tracked live in the GEN Project Atlas. Award windows derive from operator capital plans, regulator pathfinders and GEN Intel weekly tracking.

Scope

Operator

Region

Est value

Status

Bass Strait

Woodside, ExxonMobil 50 percent

Australia

$1bn

Awarded, to 2040

Barrow Island, WA Oil

Chevron

Australia

888 wells

Executing, 2025 to 2031

Ningaloo Vision FPSO

Santos

Australia

$500m

Awarded

Griffin, Scindian, Chinook

Woodside

Australia

$350m

Awarded

Stybarrow and Eskdale

Woodside

Australia

$200m

Awarded

Northern Endeavour Ph2

Commonwealth of Australia

Australia

9 well P&A

Awarded Aug 2026, Zenith Energy

Marlim platforms

Petrobras

Brazil

$2bn

Awarded, target 2027

Campos subsea removal

Petrobras

Brazil

$250m

Awarded

Campos field P&A run

Petrobras

Brazil

Framework

Awarded, multiple

P-43 Barracuda

Petrobras

Brazil

ANP approved

Tendering

Hidalgo, Harvest, Hermosa

Chevron

USA, Pacific

$180m

Awarded

Hoover Diana

ExxonMobil

Gulf of Mexico

$120m

Executing

Eugene Island

APA Corporation

Gulf of Mexico

$100m

Executing

Platform Holly

State Lands Commission, ExxonMobil prior lessee

USA, Pacific

Not disclosed

EIR scoping complete, removal pending certification

PETRONAS 31 platforms

PETRONAS Carigali

Malaysia

RM2 to 3bn

Bids under evaluation, Activity Outlook 2026 to 2028

Abu Safah subsea

Saudi Aramco, Subsea7

Middle East

$150 to 300m

Awarded, to 2027

QatarEnergy platform retirement

QatarEnergy, McDermott

Middle East

27 platforms

Definition engineering Awarded

Saleh field P&A

RAK Petroleum Authority, Northern Offshore

Middle East

9 wells, 6 platforms

Saltpond field decommissioning

GNPC, Hans and Co

West Africa

Not disclosed

Wells sealed, platform removal in final phase

Ekofisk

ConocoPhillips

NCS

Not disclosed

Cessation programme active, partial removal

Statfjord A

Equinor, Allseas

NCS

~50,000t topsides

Awarded

Veslefrikk

Equinor

NCS

$400m

Awarded, to 2028

Heimdal

Equinor

NCS

Not disclosed

Executing, topside removal from July 2026, to 2028

Gulf of Thailand ARP

Chevron

Thailand

$1bn

Awarded, target 2028

Bayu-Undan

Santos

Timor-Leste

~$1.1bn liability

Production ended, decommissioning against CCS repurposing

Alma and Galia

EnQuest

UKCS

£800m

Awarded, to 2031

Andrew Area

UKCS

~$400m services scope

Awarded Sep to Oct 2025, to 2031 to 2032

Brae Area

TAQA UK

UKCS

£1bn

Awarded, to 2033

Brent continuation

Shell UK

UKCS

£1.5bn

Topsides complete, GBS and wells to 2027

Forties and Beryl, well P&A

Apache

UKCS

$1bn+ combined

Awarded, 2026 to mid 2030s

Hewett Complex

Eni UK

UKCS

Not disclosed

Executing, 3 of 6 platforms removed, completion 2026

Southern North Sea campaigns

Perenco, Spirit, NEO

UKCS

£200m+ combined

2026 to 2028

Tartan Area

NEO NEXT+ Energy

UKCS

£500m

Awarded, to 2034

01 Be cited in Edition Two

02 WAES 2026 copies

03 Analyst briefings

Won a decom contract in 2026 or deploying new technology? Deadline 30th September 2026.

Printed copies for WAES London, 1 to 2 December.

For the underlying data or an analyst briefing on any programme in this report.

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GEN INTEL • 2026 DATA APPENDIX B

data appendix B.

Appendix B, global decommissioning and repurposing pipeline The decommissioning and repurposing pipeline tracked in the GEN Project Atlas, cleaned to genuine decommissioning, abandonment, subsea and pipeline removal, FPSO disposal and repurposing scopes. Producing assets, new developments, new build, service and vessel rows, aggregate placeholders and duplicates are removed. Nuclear and other adjacent sectors are shown separately. THE COUNT •

Offshore oil and gas decommissioning and abandonment: 131

•

Repurposing and CCS: 5

•

Decommissioning and repurposing, offshore focus: 136

•

Adjacent sector decommissioning, nuclear 34 plus LNG facility and dam 2: 36

•

Total genuine decommissioning and repurposing, all sectors: 172

Offshore oil and gas decommissioning (131)

❚ United Kingdom Continental Shelf Programme

Operator

Status

Spirit Energy Production UK

Decommissioning

Ithaca Energy

AF Offshore Decom recycling at Vats, FPF-1 awarded January 2026, Alba floating storage unit around 24,000 tonnes February 2026

EnQuest

EPRD active, FPSO removed Sep 2020, subsea decom to 2027, well P&A Define phase from 2029

Perenco UK

Petrodec Obana removing jackets, complete 2026

Andrew Area Decommissioning

Contract awarded Sep 2025, THREE60 and AF Offshore Decom EPRD, Heerema EPR for topside and jacket, completion 2031 to 2032

Anglia Field Decommissioning

Ithaca Energy

Authority approved, EPRD active to 2027

Apache

Well-Safe Solutions lead contractor, seven platforms and more than 260 wells, 2026 to mid 2030s

Balmoral Area Decommissioning

Harbour Energy

Phase 1 complete, nine subsea wells P&A on Caledonia, Nicol and Brenda, wider programme continuing

Banff and Kyle Phase 2b

CNR International

Decommissioning, work from Q1 2023

Beatrice Alpha Well Abandonment

NEO NEXT+ Energy

Decommissioning, 43 wells, work from Q1 2025

Beatrice Facility and Jacket Removal

NEO NEXT+ Energy

Decommissioning, five structures plus two demonstrator turbines, work from Q1 2031

Brae Area Decommissioning

TAQA

Contract awarded, EPRD active to 2033

Brent Alpha Bravo Charlie Delta Platforms Decommissioning

Shell UK

All four topsides ashore at Able Seaton Port, GBS, wells and pipelines to 2027

Caister Murdoch System (CMS)

Harbour Energy

LOGGS and CMS Satellite structures complete, final jacket ashore at Able Seaton Port January 2026

Causeway and Fionn Field Decommissioning

Ithaca Energy

Decommissioning, work from Q1 2025

TAQA

Decommissioning

A Fields SNS Decommissioning (Ann, Alison, Annabel, Audrey, Ensign) Alba FSU and Greater Stella FPF-1 Decommissioning Alma and Galia Fields Decommissioning Amethyst Field Topsides Decommissioning

Apache Forties and Beryl Decommissioning, Well P&A

Cormorant Alpha Decommissioning

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GEN INTEL • 2026 DATA APPENDIX B

data appendix B.

Programme

Operator

Status

Subsea removal complete 2025, DeepOcean under sale and purchase agreement, over 95 percent recycled

Donan, Balloch and Lochranza Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q1 2027

Dunbar Well Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

Durango Decommissioning

Perenco

Decommissioning, work from Q3 2026

Eider Decommissioning

TAQA

Decommissioning

Exploration and Appraisal Well Decommissioning, Edradour

TotalEnergies Upstream UK

Decommissioning

Exploration and Appraisal Well Decommissioning, Laggan

TotalEnergies Upstream UK

Decommissioning

Exploration and Appraisal Well Decommissioning, Tormore

TotalEnergies Upstream UK

Decommissioning

Foinaven Field Decommissioning

Riser and umbilical removal from later 2026, DeepOcean under sale and purchase agreement

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

Garrow Decommissioning

Energean

Decommissioning, work from Q1 2025

Greater Kittiwake Area (GKA) Decommissioning

EnQuest

Kittiwake hub plus Mallard and Gadwall subsea tiebacks, CB&I duty holder through CoP and decommissioning, production into the late 2020s

Gryphon Well Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

Harding Removal and Disposal

TAQA

Decommissioning

Heather and Broom Hub Decommissioning

EnQuest

EPRD active, topsides removed Aug 2025, jacket next, subsea and well P&A through 2027

Harbour Energy, Waldorf Petroleum Resources licensee

Decommissioning, work from Q3 2026

Eni UK

Scaldis EPRD, 3 of 6 platforms removed, Central Complex 2026, completion 2026

Harbour Energy

Decommissioning, work from Feb 2020

Indefatigable 18AD and AP Topside and Jacket Removal

Perenco

Decommissioning, work from Q1 2027

Indefatigable 23AC and AQ Topsides and Jackets Removal

Perenco

Decommissioning, work from Q3 2027

Ithaca Energy

Decommissioning, work from Q3 2024

Leman 27J Jacket and Pipeline Removal

Perenco

Decommissioning, work from Q4 2026

Leman Southwest Decommissioning

Perenco

Decommissioning, work from Q3 2026

Liverpool Bay Asset Decommissioning, Phase 2

Eni UK

Decommissioning, work from Q4 2026

MacCulloch Field Decommissioning

Harbour Energy

EPRD active, all infrastructure committed to shore with anchors left in situ, complete 2027

Millom, Dalton and Calder

Harbour Energy

Decommissioning, work from Q3 2023

Platforms removed, Saipem removal scope, subsea removal complete 2025 with DeepOcean under sale and purchase agreement, infield pipelines remain and the export pipeline is retained pending carbon storage reuse

Minke Decommissioning

Ithaca Energy

Decommissioning, work from Q2 2024

Nelson Well Services P&A

Adura Energy

Decommissioning

TAQA

Decommissioning

Don Subsea Field Decommissioning

Forvie Well Decommissioning

Helvellyn Decommissioning Hewett Complex Decommissioning Huntington Decommissioning

Juliet Decommissioning

Miller Field Decommissioning

North Cormorant Decommissioning

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GEN INTEL • 2026 DATA APPENDIX B

data appendix B.

Programme

Operator

Status

Nuggets 1 Well Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

Nuggets 2 Well Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

Nuggets 3 Well Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

Nuggets 4 Well Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

P454 and P611 Orca

Ithaca Energy

Decommissioning, work from Q2 2024

Pickerill A and B Decommissioning

Perenco UK

Jacket removal under way from April 2026

Perenco

Decommissioning, work from Q4 2026

Harbour Energy

Decommissioning, work from Q1 2019

SEAN Decommissioning

ONE-Dyas

Decommissioning, work from Q1 2025

SNS Decommissioning (Seven Seas)

Spirit Energy

Complete Aug 2026, three subsea wells P&A, more than 234 tonnes recovered, DeepOcean Edda Freya and Well-Safe Protector, all material to UK yards

Solan

Harbour Energy

Decommissioning, work from Q1 2025

Southwark Platform Decommissioning

CalEnergy Gas

Decommissioning, work from Q2 2027

Subsea Infrastructure Decom 2 (SID2)

Shell

Decommissioning, work from Q2 2026

Subsea Infrastructure Disconnections

TAQA

Decommissioning, work from Q1 2024

Subsea Infrastructure Removal

TAQA

Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q1 2031

Ravenspurn North GCD Removal Campaign Rita and Hunter Decommissioning

Subsea Removals Subsea Well P&A, all TAQA NNS and CNS Assets

TAQA

Decommissioning

Suspended Well to be P&A

Eni UK

Decommissioning, work from Q1 2023

T-Block Decommissioning

CNR International

Decommissioning, work from Q1 2027

Tartan Area Decommissioning

NEO NEXT+ Energy

Contract awarded, EPRD active to 2034

Tern Decommissioning

TAQA

Decommissioning

The Dons Decommissioning (Don SW, Conrie, West Don, Ythan)

EnQuest

Authority approved, 2029 completion target

Thistle Hub Decommissioning (Thistle and Deveron)

EnQuest

Contract awarded, EPRD active to 2027

Tullich Well Decommissioning

NEO NEXT+ Energy

Decommissioning, work from Q2 2026

Tyne Pipelines Decommissioning

Perenco

Decommissioning, work from Q1 2027

Wenlock Field Decommissioning

Energean

EPRD, tendering, decom complete 2027

Dana Petroleum

EPRD active, work began April 2026, completion 2028

NEO NEXT+ Energy

Decommissioning, work from Q1 2031

Western Isles Wells Decommissioning (Barra and Harris) Wind Turbine Removal

❚ Norwegian Continental Shelf Programme

Operator

Status

Atla Gas Field Decommissioning

TotalEnergies

Ocean Installer, part of Moreld, awarded. Dredging and recovery of around 1,000 tonnes across the three fields, offshore campaign 2027

Byggve Field Decommissioning

TotalEnergies

Ocean Installer, part of Moreld, awarded. Dredging and recovery of around 1,000 tonnes across the three fields, offshore campaign 2027

ConocoPhillips Norge

Cessation programme active since 2007, partial removal, tank derogated

Repsol Norge

Complete March 2025, 28,000 tonnes dismantled at Stord, 98.5 percent recycled

Heimdal Field Decommissioning

Equinor

Contract awarded, main topside removal from July 2026, completion by end 2028

Skirne Field Decommissioning

TotalEnergies

Ocean Installer, part of Moreld, awarded. Dredging and recovery of around 1,000 tonnes across the three fields, offshore campaign 2027

Statfjord A Decommissioning

Equinor

Contract awarded, Allseas, topsides around 50,000 tonnes

Veslefrikk Field Decommissioning

Equinor

Contract awarded, EPRD active to 2028

Ekofisk Oil Field Decommissioning Gyda Field Decommissioning

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GEN INTEL • 2026 DATA APPENDIX B

data appendix B.

❚ Africa

Programme

Country

Operator

Status

Chevron Angola Decommissioning Programme, Blocks 0 and 14

Angola

Chevron

Conceptual design, on hold, target 2028; Block 14 and 14K interests sold to Etu Energias, subject to ANPG approval

Saltpond Oil Field Decommissioning

Ghana

GNPC, Hans and Co contractor

Decommissioning under way since 2022, six wells and platform

❚ Middle East

Programme

Country

Operator

Status

Abu Safah Subsea Facilities Decommissioning

Saudi Arabia

Saudi Aramco, Subsea7 contractor

Award under Aramco long term agreement, Subsea7 substantial band $150 to $300 million, offshore work from 2026

QatarEnergy Platform Retirement, definition engineering

Qatar

QatarEnergy, McDermott

Definition engineering study, Feb 2026, 27 platforms, no disclosed value

Saleh Field P&A

UAE

Ras Al Khaimah Petroleum Authority, Northern Offshore contractor

9 wells across 6 platforms, jackup Energy Emerger

❚ Asia Pacific

Programme

Country

Operator

Status

Bass Strait Decommissioning Programme (Gippsland Basin JV)

Australia

Woodside Energy, operator from Jun 2026

Contract awarded, EPRD active to 2040

Bayu-Undan Decommissioning

Timor-Leste

Santos

Production ended May 2025, decommissioning against CCS repurposing undecided

Bayu-Undan to Darwin Gas Export Pipeline Decommissioning

Australia

Santos

Conceptual design, planning consent applied, target 2029

Barrow Island Well Decommissioning Programme

Australia

Chevron Australia

888 wells scheduled across 2025 to 2031, Class A Nature Reserve conditions apply

Brunei Decommissioning Campaign

Brunei

Brunei Shell Petroleum

EPRD awarded to Serikandi Hilong Feb 2025, activity from Nov 2025, more than 50 platforms and 70 pipelines

CNOOC Offshore Platforms Decommissioning

China

CNOOC

Contract awarded, target 2035

Enfield Field Decommissioning

Australia

Woodside Energy

Complete, 18 wells plugged, 99.6 percent of recovered material reused or recycled

Griffin, Scindian and Chinook Fields Decommissioning

Australia

Woodside Energy

Authority approved, EPRD active to 2027

Gulf of Thailand Asset Retirement Programme

Thailand

Chevron Thailand

Contract awarded, target 2028

Harriet Alpha Platform Decommissioning

Australia

Santos, McDermott EPRD

Complete, largest platform removed from Australian waters

Kangean TSB Decommissioning (Terang Sirasun Batur)

Indonesia

Kangean Energy Indonesia

Feasibility, contract awarded, target 2028

Minerva Subsea Field Decommissioning

Australia

Woodside Energy

Wells plugged, 45 percent of pipeline recovered, remaining removal pending engineering solutions

Northern Endeavour, Laminaria-Corallina Fields

Australia

Commonwealth of Australia, industry levy funded

Ph1 complete, Ph2 P&A awarded to Zenith Energy Aug 2026, Ph3a tender closes Oct 2026

Ningaloo Vision FPSO Decommissioning

Australia

Santos

Contract awarded, target 2027

PETRONAS Asset Retirement Programme, 31 platform tender

Malaysia

Petronas Carigali

Tender launched June 2025, bids under evaluation, awards pending

Ruby Abandonment Site Restoration

Indonesia

TIS Petroleum

FEED, tendering, target 2028

Sabah-Sarawak Gas Pipeline Decommissioning

Malaysia

Petronas

Conceptual design, planning, target 2027

Sebuku Decommissioning Project

Indonesia

TIS Petroleum

Feasibility, planning, target 2027

Song Doc Field Well P&A

Vietnam

Truong Son JOC

Contract awarded, target 2030

Stybarrow and Eskdale Fields Decommissioning

Australia

Woodside Energy

Ten well plugging campaign complete, subsea equipment removal delayed

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❚ North America and Gulf of Mexico Programme

Country

Operator

Status

Amoco South Pecan Lake Pipeline Decommissioning

USA

TC Energy

Feasibility, planning consent applied

Eugene Island Field Decommissioning

USA

APA Corporation

Contract awarded, target 2026

Hess West Delta Wells Decommissioning

USA

Chevron, Hess prior operator

Contract awarded, target 2027

Hidalgo, Harvest and Hermosa Platforms Decommissioning

USA

Chevron

Contract awarded, target 2026

High Island Wells Decommissioning

USA

Promethean Decommissioning

Bids under evaluation, target 2027

Hoover Diana Decommissioning

USA

ExxonMobil

Contract awarded, executing, target 2026

Platform Grace Decommissioning

USA

Chevron

Planning consent applied, target 2028

Platform Holly Decommissioning

USA, California

ExxonMobil, prior lessee, State Lands Commission asset

Wells plugged 2024, draft EIR in preparation from January 2026, removal follows certification

Promethean West Delta Wells Decommissioning

USA

Promethean Decommissioning

Bids under evaluation, target 2027

South Pass-East Breaks Decommissioning

USA

Promethean Decommissioning

Contract awarded, target 2026

❚ South America

Programme

Country

Operator

Status

Albacora Field (P-25) Subsea Equipment Decommissioning

Brazil

Petrobras

Tendering, target 2027

Campos Basin Subsea Equipment Removal Campaign

Brazil

Petrobras

Contract awarded, target 2028

Congro Field Decommissioning

Brazil

Petrobras

Bids under evaluation, target 2026

Corvina Field (P-09) Subsea Equipment Decommissioning

Brazil

Petrobras

Tendering, target 2027

Enchova-Pampo Cluster Decommissioning

Brazil

Trident Energy

Contract awarded, target 2028

Guaricema Field Decommissioning (Well P&A)

Brazil

Petrobras

Contract awarded, target 2026

Itaparica Field Decommissioning

Brazil

Petrobras

Tendering, target 2027

Libra EPS Decommissioning

Brazil

Petrobras

Planning, target 2027

Marlim Leste Field Decommissioning (Cidade de Niterói FPSO)

Brazil

Petrobras

Cidade de Niteroi FPSO departed and at a Danish recycling yard, residual subsea and well decommissioning scope remains

Marlim Platforms Decommissioning

Brazil

Petrobras

Contract awarded, target 2027

P-37 FPSO Decommissioning

Brazil

Petrobras

Tendering, four bidders

P-43 Barracuda Decommissioning

Brazil

Petrobras

ANP approved March 2026, tendering

P-65 Platform Decommissioning (Enchova)

Brazil

Trident Energy

Authority approved, target 2027

Yasuní-ITT Oil Fields Decommissioning

Ecuador

EP Petroecuador

Mandated by referendum and court order, substantially behind schedule

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❚ Repurposing and CCS

Programme

Country

Lead

Status

Acorn (Scottish Cluster)

Storegga, Shell, Harbour

Goldeneye depleted field, 102 km pipeline

HyNet North West, Liverpool Bay CCS Transport and Storage

Liverpool Bay CCS, Eni led

Repurposing, transport and storage

Northern Endurance Partnership CCS

bp, Equinor, TotalEnergies

Repurposing, active

Viking CCS

Harbour Energy

Viking depleted field, repurposed pipeline route

Morecambe Net Zero

Spirit Energy

Morecambe depleted fields, East Irish Sea

adjacent sector decommissioning (36) Kept for the all sectors view and shown separately, matching the nuclear, refineries and power page. Not part of the offshore count

❚ Nuclear

Programme

Country

Operator

Status

Biblis Nuclear Decommissioning

Germany

RWE

Execution, target 2032

Emsland Nuclear Decommissioning

Germany

RWE

Planning, target 2037

Grohnde Nuclear Decommissioning

Germany

PreussenElektra

Execution, target 2039

Gundremmingen B Nuclear Decommissioning

Germany

Kernkraftwerk Gundremmingen

Planning, target 2030

Isar 2 Nuclear Decommissioning

Germany

PreussenElektra

Execution, target 2040

Kozloduy Nuclear and National Waste Repository

Bulgaria

Bulgarian Energy Holding

EPRD active, target 2030

Krümmel Nuclear Decommissioning

Germany

Vattenfall

Planning, target 2035

Kursk Nuclear Decommissioning Units 1 and 2

Russia

Rosenergoatom

Planning, target 2035

Mühleberg Nuclear Decommissioning

Switzerland

BKW

EPRD active, target 2034

Neckarwestheim 1 Nuclear Decommissioning

Germany

EnBW

Execution, target 2035

Philippsburg 1 Nuclear Decommissioning

Germany

EnBW

Execution, target 2035

Chinshan Nuclear Decommissioning

Taiwan

Taiwan Power

Execution, dismantling to 2038, site restoration to 2044

Fukushima Daiichi Nuclear Decommissioning

Japan

TEPCO

Contract awarded, EPRD active to 2060

Fukushima Daini Nuclear Decommissioning

Japan

TEPCO

Planning, target 2064

Genkai Nuclear Decommissioning Units 1 and 2

Japan

Kyushu Electric

Execution, target 2054

Ikata Nuclear Decommissioning Units 1 and 2

Japan

Shikoku Electric

Execution, target 2059

Kashiwazaki-Kariwa Units 1 to 5

Japan

TEPCO

No programme announced, units 6 and 7 restarted

Kori 1 Nuclear Decommissioning

South Korea

KHNP

Execution, target 2037

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Programme

Country

Operator

Status

Mihama Nuclear Decommissioning Units 1 and 2

Japan

Kansai Electric

EPRD active, target 2045

Monju Fast Breeder Prototype Decommissioning

Japan

JAEA

Planning, target 2050

Ohi Nuclear Decommissioning

Japan

Kansai Electric

Planning, target 2048

Onagawa Nuclear Decommissioning Unit 1

Japan

Tohoku Electric

EPC active, target 2053

Shimane Nuclear Decommissioning Unit 1

Japan

Chugoku Electric

Execution, target 2049

Tokai Nuclear Decommissioning Unit 1

Japan

JAPC

EPRD active, target 2035

Tsuruga Nuclear Decommissioning Unit 1

Japan

JAPC

Execution, target 2047

Wolsong 1 Nuclear Decommissioning

South Korea

KHNP

Planning, target 2040

Crystal River CR3 Nuclear Decommissioning

USA

Accelerated Decommissioning Partners CR3, Duke Energy Florida owner

Reactor building demolition to complete 2026, target 2027

Fort Calhoun Nuclear Decommissioning

USA

Omaha Public Power District

Execution, target 2026

Indian Point Nuclear Decommissioning

USA

Holtec International

Execution, target 2041

Oyster Creek Nuclear Decommissioning

USA

Holtec International

Execution, target 2035

Pilgrim Nuclear Decommissioning

USA

Holtec International

Execution, target 2035

San Onofre (SONGS) Nuclear Decommissioning

USA

Southern California Edison

84 percent complete Aug 2025, dismantlement to year end 2028

Three Mile Island Unit 2 Nuclear Decommissioning

USA

EnergySolutions (TMI-2 Solutions)

Authority approved, EPRD active to 2052

Kazakhstan

METR

Execution, target 2030

Aktau Nuclear Facility Decommissioning

❚ Power, LNG facility and other Programme

2 Country

Operator

Status

Atlantic LNG Train 1 Decommissioning

Trinidad and Tobago

Atlantic LNG

Feasibility, planning, target 2026

Potter Valley Dam Decommissioning

USA

Pacific Gas and Electric

Feasibility, planning, target 2030

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The first summit built around the whole decommissioning market rather than one shelf of it. Two days covering the UK and Norwegian continental shelves, the Gulf of Mexico, Australia, Southeast Asia, Brazil, West Africa and the Middle East, with a yard tour taking place on the final day.

400+

20+

12+

Senior delegates from across the global decommissioning community

Basins covered, read by delivery rather than liability

Operator and duty holder delegations

Regulators and state bodies

Eight Basins, one supply chain.

globalenergynetwork.net

All figures, programme statuses and regulatory positions in this report were verified against primary sources on or before the 13th September 2026. Decommissioning programmes and regulatory positions move continuously, and material published after the editorial cut-off is not reflected here. The GEN Project Atlas is updated weekly and remains the current record for every programme referenced in this report. Sources: NSTA UKCS Decommissioning Cost and Performance Update 2026; NSTA Wellhead Severance Charter 2026; NSTA Decommissioning Benchmarking Report 2026; OEUK Decommissioning Insight 2025; Xodus; CODA; NOPSEMA; Norwegian Offshore Directorate; BSEE Idle Iron; BOEM 2024 rule and March 2026 proposed rollback; GAO-24-106229; ANP Resolution 817/20; Petrobras and PETRONAS programmes; Fortune Business Insights; Mordor Intelligence; Subsea7, McDermott, Ras Al Khaimah Petroleum Authority, Northern Offshore, ANP P-43 decision March 2026; operator and contractor statements; GEN Project Atlas (more than 5,600 projects). OPRED; Norwegian Petroleum; Norwegian Offshore Directorate; Parliament of Victoria Environment and Planning Committee; ANP; NUPRC.

GEN Decommissioning and Abandonment Report