Decommissioning in Oil and Gas: A Global Perspective on Scale, Cost and Timing

Decommissioning in Oil and Gas:

A Global Perspective on Scale, Cost and Timing

As producing basins mature across every continent, operators are confronting the same set of questions: how much needs to be removed, when, at what cost, and who pays?

Decommissioning isn’t a story confined to the UK North Sea. As producing basins mature across every continent, operators are confronting the same set of questions: how much needs to be removed, when, at what cost, and who pays? This briefing sets out the scale of that challenge region by region — what’s already been done, what’s still to come, and where the data is (and isn’t) reliable enough to plan against.

The Global Scale of the Challenge

A Market in Acceleration

The IOGP projects global offshore decommissioning expenditure of around $103 billion between 2025 and 2034, a marked step up from earlier estimates such as Wood Mackenzie’s $32 billion for 2018–2022 and a separate Rystad Energy figure, from a 2020 release, of $42 billion in projected decommissioning project value for 2020–2024. The figures aren’t directly comparable, but the direction is consistent: decommissioning spend is accelerating as more fields, across more regions, reach the end of their producing lives.

Global offshore decommissioning spend estimates — Flare Solutions

Global offshore decommissioning spend estimates

Historical and forecast, by source — plus a UK annual-spend zoom-in

By source and time window

Note: the Rystad and IOGP figures are not independent data points — IOGP’s estimate republishes Rystad data, rather than corroborating it separately. Time windows and bases also differ, so treat this as directional, not a single consistent trend line.

UK annual spend: actual vs forecast

Actual Forecast

Source: NSTA, UKCS Decommissioning Cost and Performance Update 2026 (2025 prices; total decommissioning, all WBS categories).

The North Sea: The UK

In its 2026 update, the North Sea Transition Authority (NSTA) estimates the UK’s total remaining decommissioning spend at approximately £43.4 billion – reducing only marginally from last year’s estimate despite a record 2025 spend of £2.6 billion. Progress has been offset by inflationary pressures, market uncertainty, and growing global competition for specialist resources. Well decommissioning remains the single largest component of expenditure, accounting for half of all costs to 2032, with over 1,500 wells to be decommissioned over the next five years. Decommissioning expenditure is forecast to overtake CAPEX from 2029, with nearly a quarter of all spend on the UKCS being decom-related. Overall, decommissioning in the UK is getting more expensive, not less.

The North Sea: Norway

Very limited information on decommissioning cost in Norway is available publicly, so figures here describe physical scope rather than spend. 20–30 currently producing fields are expected to cease production and move into decommissioning over the next decade. Offshore Norge’s most detailed operator survey (presented at the 2024 NPF Decommissioning Conference, covering 11 operators) has operators expecting to plug 250 platform wells and 50 subsea wells between 2023 and 2032, up from 234 and 29 just a year earlier.

North America: The US Gulf of Mexico

The US Gulf of Mexico is less a story of headline cost than of financial assurance and enforcement. A June 2023 US Government Accountability Office (GAO) report found more than 2,700 wells and over 500 platforms overdue for decommissioning, against an estimated $40–70 billion in total exposure covered by only around $3.5 billion in bonds held by the Bureau of Ocean Energy Management (BOEM). BOEM’s 2024 rule tightening financial-assurance requirements received strong industry pushback; a 2026 proposal to amend (not replace) that rule drew further opposition before its comment period closed on 15 May 2026. Independent operators, who produce roughly half of total US oil output, argued the bonding demands were unaffordable, and three Gulf states sued to block the original rule. For scale, more than 55,000 wells and 7,000 platforms have been installed in the Gulf since the 1940s; Rystad’s five-year outlook for US decommissioning spend (also from the May 2020 release cited above), by contrast, is a comparatively modest $5.7 billion, a sign of how much liability is still being deferred rather than actioned.

North America: Canada

Canada’s liability is concentrated overwhelmingly in one province. The Alberta Energy Regulator’s own 2024 Liability Management Performance Report (published November 2025) puts the province’s conventional oil and gas closure liability at C$36.6 billion — C$23.4 billion for inactive sites and C$13.2 billion for active ones. That figure is dwarfed by the separately tracked liability for oil sands, of around C$57.3 billion under the Mine Financial Security Program. Putting the two together gives an AER-wide total closer to C$94 billion. Despite this, annual well decommissioning fell from nearly 12,000 wells in 2021 to under 6,000 in 2024, even as roughly 34,000 wells had already sat inactive for a decade or more by year-end. Alberta’s Liability Management Framework, announced in July 2020, replaced a simple assets-to-liabilities test with a broader Licensee Capability Assessment backing annual closure-spend quotas and security deposits for weaker operators. New licensees post security at 12% of their inactive liability, but the rate required on licence transfers to less capable operators fell from 7% in 2022 to 2% in 2023 to just 1% in 2024, suggesting the framework’s teeth are still catching up with its ambition.

Alberta’s orphan-well backlog (where the well operator is insolvent or untraceable) sits with the industry-funded Orphan Well Association (OWA), and it has grown sharply in the two years since. An August 2025 report put the inventory at a then-record 3,921 well sites needing decommissioning plus 8,122 sites needing reclamation only. This includes the roughly 2,365 sites transferred in via the Sequoia Resources bankruptcy settlement, while the Long Run Exploration insolvency pushed the inventory to around 7,302 wells. At current funding levels, the OWA’s own target completion horizon has slipped from around 2036 to 2037–2040.

British Columbia’s liability is smaller, and its regulatory approach has changed markedly in recent years. The trigger was a provincial Auditor General audit, published in March 2019 on 2018 data, that found the BC Oil and Gas Commission had no general legal duty to compel timely decommissioning – it could only order closure case by case, for safety or environmental reasons, rather than to any set schedule. Of more than 10,000 inactive wells at the time, 7,474 were still awaiting dismantling, filling or capping, against an estimated C$3 billion cleanup cost the Auditor General described as rising. Orphan sites, meanwhile, had grown sevenfold in three years, from 45 in 2015 to 326 in 2018. The regulator has changed substantially since. Renamed the BC Energy Regulator in 2023, it now operates a Dormancy and Shutdown Regulation, setting Western Canada’s first mandatory decommissioning timelines, with a goal of restoring 10,000–11,000 dormant sites by 2036.

One Canadian development is squarely a case study in who pays. In 2019, the Supreme Court of Canada’s Redwater decision (Orphan Well Association v Grant Thornton Ltd, 2019 SCC 5) settled a fight over what happens when an operator goes bankrupt. The Court held that abandonment and reclamation orders sit outside the normal creditor-distribution scheme entirely rather than ranking behind secured creditors within it, meaning that proceeds from an insolvent company’s valuable assets must fund decommissioning before secured creditors get paid, closing off a strategy to shift cleanup risk onto the public purse.

Asia-Pacific: The Next Wave

In 2018, Wood Mackenzie estimated that decommissioning Asia-Pacific’s roughly 2,600 platforms and 35,000 wells could cost more than $100 billion, with well plugging and abandonment alone accounting for about half of that spend. Within that total, Southeast Asia (Malaysia, Thailand, Vietnam and Indonesia) has around 200 offshore fields, comprising more than 1,500 platforms and more than 7,000 wells, projected to cease production by 2030. The Gulf of Thailand alone has around 300 platforms and 6,000 wells due within the decade. Regulatory frameworks across much of Asia-Pacific are markedly less mature than the North Sea’s, making access to the information needed for cost estimation and planning extremely challenging.

Australia

Australia’s Department of Industry, Science and Resources (DISR) estimates Australia’s offshore decommissioning liability at A$43.6 billion in base-year terms, or A$66.8 billion adjusted for inflation, through 2070. The scope includes more than 1,000 wells, 11 floating and 57 fixed facilities, 535 subsea structures such as manifolds, and around 6,700km of pipeline plus 1,500km of umbilicals in total, of which roughly 5,000km of larger pipeline is a candidate for leaving in place (in-situ decommissioning). That same analysis pointed to a review of selected North Sea decommissioning projects, which found actual costs running some 76% above original estimates on average — a sobering benchmark for any region still building its cost-estimating track record. Australia’s own flagship case makes a similar point more directly: the Northern Endeavour FPSO, orphaned after its operator collapsed in 2019–2020, was originally estimated at around A$250 million to decommission. After a multi-country tow to a Danish recycling yard that completed in 2026, the final bill is approaching A$1 billion — roughly a fourfold overrun on Australia’s own most closely watched case.

Latin America and the Caribbean

Latin America is a genuine growth region for decommissioning activity: Global Market Insights projects regional growth at a bit over 5% a year to 2034, led by Brazil and Mexico. What makes the region distinctive is the size of the decommissioning liability. Welligence (via Offshore Engineer) groups Brazil among the world’s four largest single liabilities, alongside the US Gulf of Mexico, UK and Norway, which together account for almost $150 billion of a current global total the firm estimates at over $300 billion.

Caribbean and South America — decommissioning liabilities — Flare Solutions

Caribbean and South America — decommissioning liabilities

Same figures as Figure 2 (Table 1), zoomed to the regions this section discusses

Caribbean and South America (5 regions)

Estimated cost / liability

Scope

Who pays?

Timeframe & source

Bubble area is indicative only (approx. USD-equivalent scale) — figures use very different vintages, scopes and sources. Hover or tab to a marker for full detail on that region. See Table 1 for the complete global dataset.

In Brazil itself, Petrobras targeted 18 production platforms for decommissioning under its 2020–2024 strategic plan, principally Campos Basin assets. Under its more recent 2025–2029 plan, the company has cut planned decommissioning capital spend from over $11 billion to $9.9 billion and cut the number of floating platforms slated for decommissioning from 23 to 10. Petrobras attributes this to 'optimisations of decommissioning activities', and platform life extension, a somewhat different regional pattern from the UK or Gulf of Mexico, where removal, rather than revitalisation, is the default. Brazil also has an active fleet of 46 FPSO units, comfortably the world's largest national fleet. Of the first two FPSOs earmarked for domestic dry-dock decommissioning, P-32 completed dismantling in June 2026, after starting about a year late following a contractual dispute over removing residual oily water; the second, P-33, arrived at the Rio Grande yard in late July 2026. There are signs of the supply chain continuing to build capacity: Brazilian firm OceanPact signed a decommissioning-services contract with Trident Energy covering three Campos Basin platforms (P-07, P-12 and P-15) and associated subsea infrastructure, running up to three years from the first quarter of 2026.

Mexico has the most transparent financial disclosure of any country in the region, if not globally. Pemex's SEC filings disclose a dedicated balance-sheet reserve standing at Ps. 115.5 billion as of December 31, 2024, nearly double the Ps. 61.1 billion a year earlier, and about US$6.7 billion in today's money. The physical scope is concentrated at Cantarell in the Bay of Campeche, once the world's second most productive oil field (behind Ghawar in Saudi Arabia): widely cited figures put more than 200 wells and 24 platforms in the complex as approaching decommissioning age. Market-research estimates of Mexico's offshore decommissioning services market vary widely, but what sources do agree on is that removing ageing platforms, rather than well plugging alone, will dominate the work. Using a commonly cited (though unverified) rule-of-thumb of $15–20 million per shallow-water platform removal, Cantarell's platform count alone would put that slice of the work at roughly $350–500 million before touching wells, pipelines or subsea infrastructure.

Ecuador's decommissioning story is driven by politics as much as economics, with a lot going on in recent years. Following an August 2023 referendum, Ecuador's Constitutional Court ordered Petroecuador to wind down oil operations in the Yasuní/ITT Block 43 – three fields and around 230 wells inside a national park and UNESCO biosphere reserve – within a year, setting a compliance deadline around August 2024. As of March 2026, the block was still producing: 2025 output averaged roughly 44,000 barrels a day, nearly 10% of Ecuador's total crude output. The government has since sought an extension to December 2029 for production cessation, and a rights group filed an enforcement case in November 2025 after Inter-American Court compliance deadlines in September 2025 and March 2026 were both missed. Cost estimates for the closure vary substantially. Petroecuador's own figures for abandoning the block's infrastructure have been reported anywhere from around $600–700 million to as much as $1.8 billion depending on source and date.

Nearly three years after the referendum, with production essentially unchanged and closure pushed toward the end of the decade against continuing legal challenges, Ecuador remains a stark illustration of the gap between a legal decommissioning obligation and the operational and fiscal planning needed to actually deliver it.

Guyana's Stabroek Block has become a flashpoint in the who-pays debate covered later in this briefing. Chevron only became a partner in July 2025, after an ICC arbitration tribunal in Paris rejected ExxonMobil's and CNOOC's attempt to block Chevron's acquisition of Hess under the joint operating agreement's pre-emption rights. The episode is a live illustration of a core criticism of the Institute for Energy Economics and Financial Analysis (IEEFA)'s review of Guyana's 2016 petroleum agreement: that decommissioning liability can transfer to a different balance sheet with no pre-funding requirement attached. A 30% Stabroek interest changing hands is precisely that scenario playing out. In 2022, IEEFA estimated total decommissioning costs for the block's Liza and Payara developments at around $3.2 billion, but the petroleum agreement allows partners to recover that cost from Guyana's oil revenues without any obligation to set the money aside in advance. IEEFA frames this as a structural gap that could leave Guyanese taxpayers exposed if operators sell their stakes before decommissioning is complete.

Venezuela's decommissioning challenge is dominated by Lake Maracaibo, an inland sea where production began onshore, from the Zumaque-1 well, in 1914, and progressed rapidly offshore, over a century of development coming to encompass an estimated 15,000 wells, many now inactive. Cost estimates here are thinly sourced: two OilPrice op-eds put minimal clean-up at '$2.5 billion required' and then 'more than $3 billion' respectively, while the same pieces put the cost of rebuilding Venezuela's wider oil infrastructure at $100 billion, or $100–200 billion over a decade. With sanctions easing and international operators being courted back into the country, commentators have raised concerns that environmental remediation may play second fiddle to the more immediate goal of restoring production.

Trinidad and Tobago offers a rare hard number outside the usual set of producing nations. State-owned Heritage Petroleum, formed from the 2018 restructuring of Petrotrin, carries a TT$4.75 billion (around US$700 million) decommissioning liability (albeit unfunded) on its audited books. Decommissioning costs are deductible against Petroleum Profits Tax, but only in the year the work is actually performed, which actively discourages pre-funding of decommissioning liabilities.

Elsewhere in the region, the picture is one of regulation without published figures. Colombia requires operators to fund a dedicated 'Fondo de Abandono' (Abandonment Fund): a trust or bank guarantee approved by the national hydrocarbons agency (ANH) and backed by a separate guarantees clause (Clause 15) – a contractual mechanism, on paper, at least as strong as several of the countries above, though we found no public aggregate cost estimate to show how large the ring-fenced total actually is. Argentina's Vaca Muerta shale play, Suriname's nascent offshore sector and Peru's smaller offshore fields are all, at this stage, decommissioning stories still to be written: recent, small, or dominated by onshore environmental liability rather than the classic well-and-platform decommissioning covered elsewhere in this briefing.

West Africa

West Africa's decommissioning picture combines strikingly large regulator-held figures in some countries with an almost total information vacuum in others — the region overall has genuine headline numbers, even if Nigeria's onshore estate specifically does not.

Angola's oil regulator, ANPG, reports that 760 of 1,630 wells have been closed (690 of them offshore) and that operators hold around US$5.5 billion in decommissioning guarantee accounts plus a further US$800 million in securities, though none of the underlying assets has yet been formally, permanently abandoned.

Nigeria's own upstream regulator, NUPRC, approved 94 decommissioning and abandonment plans in the two years to September 2025, covering US$4.4 billion in liabilities under Field Development Plans, with over US$400 million already secured against them; against that, Nigeria's House of Representatives opened a probe in October 2025 into what it estimates as a US$15–20 billion compliance gap across the industry. Nigeria's Upstream Petroleum Decommissioning and Abandonment Regulations 2026 are now in force, bringing some improvements to the commercial workability of the 2023 framework, but leaving the high level approach essentially unchanged.

Nigerian onshore is a genuinely different case. Internal Shell estimates from 2014, disclosed as part of UK legal proceedings (the Bille and Ogale cases) and released in 2026, put the company's own Nigeria decommissioning liability at $10.9 billion. The liability is tied in large part to onshore wells with missing or unverifiable maintenance records and pipeline integrity issues, an uncomfortable case study of the importance of information management in decommissioning work.

The Middle East

Published Middle East estimates exist, but are sparse and poorly attributed rather than genuinely absent: a March 2026 trade-press report (TradeArabia) cites around 700 offshore facilities awaiting decommissioning in the Arabian Gulf, 1,000 structures by 2038, at an estimated cost of US$30–50 billion over two decades. However, the figures have no named source, study or methodology behind them, warranting some caution in their use.

The region's giant fields are generally further from end-of-life than comparable fields in the North Sea, Gulf of Mexico or Asia-Pacific on scale and cost-position grounds, meaning that decommissioning activity, and the data that comes with it, appears minimal for now, and the published estimates that do exist should be read as indicative at best.

Bringing It Together

The map below summarises every region, country and province covered in this briefing, from major regional aggregates down to single-company or single-province figures. The detail varies enormously by source, vintage and scope: some are total liabilities, others five- or ten-year spend forecasts, others a single operator's own internal estimate, so each should be read with its own timeframe and source in mind rather than added together into a single global total. The absence of a country from this table (for example, Russia & Central Asia) reflects a data gap rather than an absence of activity.

Decommissioning liabilities by region — Flare Solutions

Decommissioning liabilities by region

Headline figures from Table 1 — global total (all regions, 2025–2034): ~$103bn, IOGP citing Rystad Energy (not separately mapped)

Global (all regions)

Estimated cost / liability

Scope

Who pays?

Timeframe & source

Bubble area is indicative only (approx. USD-equivalent scale) — figures use very different vintages, scopes and sources. Hover or tab to a marker for full detail on that region.

Decommissioning cost estimates – how good are the numbers?

One way to dig into the reliability of the estimates above is to compare them to what we know about the state of the oil and gas industry in each country, or region for which we have data.

Simplistically, we might expect that the longer a region has been producing, or the more oil and gas a region has produced, the larger the decommissioning liability that accrues. If a region has been extracting oil and gas for over a century, a comparatively small decommissioning liability is worth questioning: is the physical liability genuinely small, or is it under-recognised, unfunded, or simply undisclosed? For the record, we’re not questioning intent in this work, but instead, looking at the level of work ahead, and how much our industry should prepare for: if we recognise the liability, we can plan and prepare for it.

The following figures dig into the reliability of decommissioning estimates in this way. First – liability versus years producing.

Liability vs. years producing, by region — Flare Solutions

Liability vs. years producing, by region

Estimated decommissioning liability against years since first production in that basin (to 2026) — marker size shows liability per year of production

Marker size — liability per year of production

Caveat: these liability figures are NOT calculated on a like-for-like basis — they mix total remaining liabilities, decade forecasts, single-company capex plans and unattributed press estimates of very different vintages (see the global figures in the graphic above / References). ‡-flagged regions are ones already described above as unfunded, undisclosed, or based on a stale/incomplete estimate — for those, a small marker is more likely to reflect a disclosure gap than a genuinely small physical liability. Norway and Asia-Pacific are excluded: Norway has no confirmed total liability figure, and Asia-Pacific spans many countries with no single start date. Years and liability for US GOM are both genuinely Gulf of Mexico-specific (unlike the boe-production comparison below, this one has no national/regional scope mismatch to flag). This is an illustrative, exploratory view, not a statistically controlled analysis.

Trinidad and Tobago and Venezuela – the two longest-producing basins in this set, both over a century old – sit at the very bottom of the per-year ranking, and both are already flagged as currently unfunded. Guyana, by contrast, has the shortest history of any region here (production began in December 2019) yet already shows a recognised liability per year of production above most of the century-old producers: the opposite of what a simple 'liability builds up with production' relationship would predict.

Years of production is a blunt proxy, though, as some countries may have been producing in small quantities, or from a small number of very large fields, for a very long time; while for others, their industry may have expanded rapidly, and in a more complex, and plant-intensive manner. Our second approach looks at recognised decommissioning liability normalised by how much oil and gas each region has actually produced, using cumulative volumes from the Energy Institute's Statistical Review of World Energy (oil production summed 1965–2025; gas production summed 1970–2025, converted to barrels of oil equivalent using the Review's own conversion factor).

Re-running the comparison on that basis sharpens the picture.

Liability vs. cumulative production, by region — Flare Solutions

Liability vs. cumulative production, by region

Estimated decommissioning liability against cumulative oil + gas produced to date (Energy Institute, Statistical Review of World Energy) — marker size shows liability per bboe produced

Marker size — liability per bboe produced

Caveats: liability figures are NOT like-for-like (total remaining liabilities, decade forecasts, single-company capex plans and unattributed estimates of different vintages — see global summary above). Production is 1965–2025 for oil / 1970–2025 for gas. † marked regions (US GOM, Australia) use a NATIONAL production total as the denominator, because the Energy Institute doesn't publish a Gulf of Mexico-specific (or equivalent sub-national) figure — so those two markers are sized using a bigger denominator than the liability figure's own scope, which pulls their apparent per-barrel liability down artificially, and the true GOM-only ratio for the US is almost certainly higher than shown. Guyana's high ratio mostly reflects that it only began producing in Dec 2019, not that its liability is overstated: a young field's liability (covering its whole future life) will always look large next to the small volume it has produced so far. ‡-flagged regions are ones already described above as unfunded, undisclosed, or stale/incomplete — for those, a small marker is more likely a disclosure gap than a genuinely small physical liability. Norway, Alberta and British Columbia are excluded (no confirmed liability figure / no provincial production breakdown). This is an illustrative, exploratory view, not a statistically controlled analysis.

On a per-barrel basis, Venezuela and Trinidad and Tobago remain the two lowest-recognised liabilities of any region in this briefing, at a few cents of estimated liability per barrel of oil equivalent ever produced, versus 32 cents to over a dollar for regions with more actively managed or funded regimes such as Angola, the UK and Australia, a pattern is consistent with under-recognised liability rather than a genuinely small physical one.

The same cannot be said with confidence for the US Gulf of Mexico specifically: nationally, US production dilutes the comparison enough that its per-barrel figure lands in the middle of the pack, not the bottom: the US's well-documented problem, per the Who Pays? section below, is a bonding shortfall against a large headline number, not a small one.

Guyana is an outlier in this analysis as well, as it is only five years into a multi-decade journey as an oil and gas producing nation.

The evidence, overall, however, is that the cost of decommissioning is likely to be substantially underestimated in the above, which brings an edge to the ultimate question: who pays for the work?

Who Pays?

Who actually pays for decommissioning varies sharply by jurisdiction, and the difference matters because it determines where the incentive sits to invest in good information management.

In the UK, the state shares much of the cost through Decommissioning Relief Deeds (DRDs), a contractual guarantee introduced in 2013 that lets operators reclaim tax previously paid against decommissioning spend. The NSTA's December 2024 estimate put the Exchequer's exposure at around £10.8 billion of what was then a £43 billion total remaining cost; the NSTA hasn't restated an Exchequer-specific split since, even as its 2026 update puts the whole remaining programme at £43.4 billion. Decommissioning costs remain specifically excluded from the Energy Profits Levy's investment relief. Norway arrives at a similarly state-heavy outcome by a different route: a 78% marginal tax rate means the state effectively covers most decommissioning cost through deductibility, and it also carries direct exposure as an equity partner via state-owned Petoro, which holds around a third of Norway's oil and gas reserves. Norway pays this out as an annual cash refund on the value of a negative special-tax position, arguably a more immediately generous mechanism than the UK's Decommissioning Relief Deeds, which work through the ordinary tax system over time.

In the US, the state's exposure is smaller and the risk of shortfall correspondingly larger. Operators recover only about 21 cents in the dollar of decommissioning spend through the federal corporate tax rate, with no refund mechanism, so BOEM instead relies on upfront financial-assurance bonds as a backstop against operator default. However, those bonds currently cover only a fraction of estimated exposure, which is exactly why BOEM's attempt to tighten bonding requirements met such strong industry pushback in 2024.

Australia moved to close a similar gap after the 2019–2020 collapse of Northern Endeavour's operator left the government holding the liability: its 2021 reforms introduced 'trailing liability' rules that can claw back costs from former titleholders, plus an industry-wide cost-recovery levy so the sector as a whole underwrites shortfalls rather than individual operators. The Northern Endeavour case itself, now approaching an A$1 billion final bill against an original A$250 million estimate, shows how expensive that backstop can get in practice.

Canada arrived at a similar principle by a different route: the Supreme Court's 2019 Redwater decision established that an insolvent operator's estate must fund decommissioning before secured creditors are paid, and Alberta's orphan-well backlog is funded mainly through an industry levy topped up with government loans the industry itself repays – both squarely operator- and industry-funded, with government exposure limited to a backstop of last resort (albeit one that has grown faster than it's been cleared).

Nigeria's onshore funding mechanism remains undisclosed at the operator level, and Asia-Pacific's varies by country with no reliable, comparable data found to be available for this report.

The Americas add a wider spread still. Brazil's Petrobras is state-controlled and Mexico's Pemex is wholly state-owned, so both countries' decommissioning exposure has a similar state-linked character to Trinidad and Tobago's. Colombia sits at the opposite end of the spectrum, requiring operators to fund an ANH-approved abandonment trust up front under their standard contracts: on paper, a materially stronger mechanism than the UK's or Norway's tax-based systems.

Who pays matters because it shows the incentive to invest in good information management doesn't always sit with the party best placed to act on it. Where the state underwrites much of the cost, as in the UK and Norway, government bodies have a direct financial stake in operators' record-keeping and planning quality. Where the state's exposure is limited to a bonding backstop, as in the US and (until recently) Australia, that incentive falls more on regulators policing compliance after the fact than encouraging shared, proactive information management. Decommissioning costs are subject to a whole range of factors, including inflation, supply chain capacity, and project complexity, so good IM, by itself, will never fully bend the decommissioning cost curve.

No matter where the money ultimately comes from, surfacing better information up front about what needs to be removed, when, and in what condition remains one of the most cost effective ways to reduce decommissioning cost uncertainty, and overall decommissioning expense: an approach that operators, regulators and taxpayers should all be able to get behind.