Without the hype
North Sea Oil and Gas Explorer
28 October 2026
Output: Energy Institute, 1965 onward. Tax: HMRC net receipts from 1968-69, in 2025-26 money (ONS GDP deflator).
Jackdaw and Rosebank
Compare projected field output, emissions and tax revenue. Oil and gas are shown separately against the amounts already produced from UK offshore fields. Select either field, both, or add other fields below. These comparisons show both products, regardless of the map's oil and gas filter.
Other fields
These earlier-stage developments use the explorer's existing volume and start-date scenarios. Their oil and gas split is assumed from the stated main product unless a separate assessment is available.
Projected output by year
Projected output as a percentage of past UK offshore production
Projected emissions from burning the fuel
Gas supply emissions compared with imported LNG
This compares supplying the same amount of gas from the selected fields or as imported liquefied natural gas (LNG). It covers production, processing and delivery, with combustion shown separately. Oil and condensate are excluded from the LNG comparison.
Projected tax revenue
How each project is modelled
Each project is modelled with a first year of production, usually two years at peak, and then a decline. The curve totals the volume chosen for that scenario, which may differ from a company's current resource estimate. Published peak rates are used where available; otherwise annual peak output is one eighth of the chosen volume. The model treats each project as oil or gas for pricing, even where the field contains both. Investment uses the Tax tab's cost per boe and is spread over two years before production. It is assumed to qualify for immediate tax relief against the owners' other profits, shown as negative receipts during construction. Jackdaw's past construction spending and tax relief are excluded. Start years marked "assumed" are the explorer's assumptions. Decommissioning is excluded. Demand comparisons use the selected baseline demand, without applying annual demand change. These project volumes are not added to other tabs' totals, where they may already be included.
Production, demand and tax since 1965
How much oil and gas the UK has produced, how much of its own demand that met, and how much tax it raised. The outlook continues from the source chosen on the Supply tab and the prices and tax rates set on the Tax tab.
Oil: UK production and demand
Gas: UK production and demand
Share of UK demand met by UK production
Tax raised from UK oil and gas
Net gain to the Exchequer: imported oil and gas pays no UK production tax, so the tax raised on UK production is a gain compared with importing the same oil and gas. VAT and fuel duty are paid either way and are left out. HMRC's receipts are net of repayments such as decommissioning relief. This leaves out the wider effects on wages, jobs and the balance of trade.
Discoveries and exploration prospects
This tab brings together three groups: named discoveries, areas advertised in the 33rd licensing round, and features recorded on relinquished licences. Some are confirmed discoveries; others are undrilled prospects or earlier geological ideas. Their markers add no volume to the totals elsewhere in the explorer.
The NSTA discovery download has 348 points, including 209 without discovery names. The explorer adds larger markers to identify selected discoveries from company reports and other sources. The report's separate inventory includes 360 marginal discoveries on unlicensed acreage; that count is not directly comparable with this map layer, which contains both licensed and unlicensed points.
1 · Discoveries named by companies and the press
These discoveries have been confirmed by drilling and are unnamed or missing in the NSTA map layer used here. Published estimates are shown where available. The Benriach entry instead gives a pre-drill estimate, clearly labelled as such. These volumes may already be counted in the NSTA's discovered resources, so adding them would risk counting the same oil and gas twice.
Where the NSTA identifies a discovery by well number, its marker uses that well's location. Other markers use the centre of the listed blocks as an approximate location. Estimates are those reported by the linked sources, which vary in date and may cover different development phases or ownership shares. A pre-drill estimate describes what might be found, rather than what drilling has established. No separate Tornado East location or resource estimate is included in this dataset.
2 · Prospects offered in the 33rd licensing round
3 · Prospects in relinquished licences
Relinquishment reports record the work a company carried out before giving up a licence. This layer includes undrilled prospects and leads, geological concepts, and some discoveries. Giving up a licence does not by itself establish that a prospect is uneconomic or that it was never drilled. Each feature links to its report, which may give a volume estimate. The markers add no volume to the totals because some may already contribute to the NSTA's estimates of mapped prospects or broader geological plays. The explorer has not matched each feature to the NSTA inventory, so the extent of that overlap is unknown.
Shale oil and gas
This tab shows three British Geological Survey study areas and their estimated oil and gas held in the rock. Only a proportion of this could be extracted, and commercial recovery rates have not been established for the UK. Choose an assumed recovery rate to compare the resulting volume with UK demand. Shale volumes are shown separately from the offshore totals.
What might be recoverable
Recovery rates here are assumptions, rather than measured UK commercial rates. A 2019 study by Whitelaw and colleagues estimated a maximum of 140 ±55 trillion cubic feet of gas in the Bowland Shale, roughly a tenth of the BGS central estimate. The alternative option uses 85, 140 and 195 tcf as its low, central and high assumptions. These are estimates of gas held in the rock, not recoverable gas. The comparison with years of UK demand uses the assumptions on the Supply tab.
UK shale production and fracking policy
No UK shale well has produced commercially. England introduced a moratorium on shale-gas fracking in November 2019 after earthquakes at Preston New Road. It was briefly lifted in autumn 2022 before being reinstated. The Scottish and Welsh governments also oppose fracking. The UK government plans legislation to stop new licences for exploring new fields, while retaining the moratorium on existing licences. Lower-volume hydraulic fracturing falls outside the existing shale-gas consent definition, so the policy is not a ban on every use of hydraulic fracturing.
What this explorer is for
There is endless debate about new North Sea licences, with people and organisations often choosing figures that support their argument. I find this quite tedious, so I have put the different estimates together on one dashboard.
It maps 345 offshore production licences in the NSTA data downloaded in October 2026, showing their allocated share of recorded production and estimated remaining reserves and resources. It also compares national estimates from the regulator, the industry's trade body and a climate think-tank.
The map and calculators are interactive. The Supply tab compares each estimate with UK demand. The Tax tab applies the prices, costs and tax rates you choose to a production scenario, giving estimated receipts in pounds or dollars. These are comparisons based on assumptions, rather than forecasts of how much the UK will produce or collect in tax.
How to use it
Click a licence, field, discovery or unlicensed block to see its figures. The switch at the top changes the volumes shown to oil, gas or both and emphasises the corresponding field types. The layers box turns map layers on and off, including exploration prospects and shale basins.
Where the numbers come from
- Licences, fields, discoveries and unlicensed blocks: the North Sea Transition Authority's open data, as at October 2026.
- Production: monthly offshore field returns to the NSTA from 1975 to July 2026, added up for each field. Where a field spans several licences, each licence gets an equal share. The returns sum to about 3.2 bn boe less than the NSTA's cumulative total at the end of 2024. The explorer treats this gap as missing early gas production and adds it to the UK total, without assigning it to individual fields or basins. Some production records also cannot be matched to mapped fields, so the licence figures do not add up to the UK total. Here, boe means barrels of oil equivalent, which expresses oil and gas in a common unit.
- Remaining oil and gas: based on the NSTA's Reserves and Resources report for the end of 2024. The report publishes reserves by basin rather than field. The explorer sets aside separate field estimates for Rosebank and Jackdaw, which had no output in 2025, then shares the remaining basin oil and gas totals according to fields' 2025 output of each. Field allocations are divided equally between their licences. These are rough allocations on an end-2024 basis, with no deduction for later production. Production comes from measured field returns, but the shares assigned to licences are also estimates.
- Discoveries missing or unnamed in the open map: the NSTA download contains 348 discovery points, of which 209 have no discovery name. Tornado, Cambo, Bressay and Suilven are identified by well numbers. The explorer adds named markers from company reports and other published sources, with a link for each estimate. It also maps areas advertised in the 33rd licensing round and features recorded in relinquishment reports. These extra markers add no volume to the totals because they may overlap with the NSTA's existing resource estimates.
- Other estimates: the NSTA's February 2026 production projections and the ECIU's analysis of them, and OEUK's Westwood study and 2025 Business Outlook.
- Shale: the British Geological Survey's estimates of oil and gas held in the Bowland–Hodder (2013), Midland Valley of Scotland (2014) and Weald (2014) shales, with basin outlines from its mapped data. UK recovery rates have not been established commercially, so you choose the share assumed recoverable.
- Tax: the default scenario uses corporation tax at 30%, the supplementary charge at 10% and the Energy Profits Levy at 38%. The levy is scheduled to end by 31 March 2030, with an earlier end possible under its price-floor rules. The model also includes the announced Oil and Gas Revenue Levy, a proposed 35% charge on revenue above separate oil and gas price thresholds. The calculations simplify the tax rules, including their timing. Net UK oil and gas tax receipts were £4.3bn in 2025–26.
- Prices: the default scenario starts at $115 a barrel for oil and 240p a therm for gas, easing to $70 and 85p over three years. These are adjustable assumptions, rather than live market quotes. Use the sliders or presets to explore different prices.
What's left, basin by basin
This table compares production up to the end of 2024 with reserves and discovered resources estimated at the same date. Production comes from monthly field returns; the UK total also includes an adjustment for missing early gas. Basin reserves and contingent resources were read from the report's charts, so they are approximate. Prospect and play estimates come from its tables. The map panels show production through July 2026, so their production figures cover a longer period.
Not yet discovered
Licensed vs unlicensed
Unlicensed resources are in areas for which no company currently holds a licence. Production would need a licence or another permitted authorisation, investment and development consent. Government policy rules out new exploration licences but allows for limited developments connected to existing fields. Whether any of these resources can be developed therefore depends on the project and the rules that apply to it.
How much is left, and how long would it last?
Choose a source to compare its estimate with UK demand. Each card explains who produced it and what it measures. Some figures are inventories of recoverable resources; others are projections of production by 2050, so they answer different questions. For OEUK and ECIU scenarios, the explorer assumes 60% oil and 40% gas in boe. The NSTA inventory uses its category splits; its production scenarios use approximate splits derived from the reported oil and gas totals.
Production: history and projection
The explorer builds an illustrative annual production curve from the selected volume, modelling oil and gas separately from their 2025 output. Each curve preserves the volume chosen for the scenario. Estimates covering production to 2050 are exhausted by that date; inventories without an end date can continue later. Larger inventories may require a period of sustained output before a decline, representing new developments replacing lost output. These curves are generated by the explorer, rather than taken from the sources' annual forecasts. Actual production would vary as fields start, decline or close. The 2026 history bar covers January–July only. Historical gas bars omit production missing from field returns; the cumulative UK total includes an adjustment for it.
Every source side by side
UK demand assumptions
Default demand is inferred from the explorer's 2025 production figures and the shares reported by ECIU from DESNZ data: 55% for oil-based fuel use and 49% for gas demand. The sliders let you change demand and its annual growth or decline. Lower demand makes the same volume equivalent to more years of use. These are volume comparisons, rather than a forecast of self-sufficiency: production rates, exports, imports and the different uses of oil and gas also matter. Oil and gas are combined in boe only for the overall comparison.
Projected tax take
Choose an oil and gas estimate to use in the tax scenario, then adjust prices, costs and rates. Tax is modelled from January 2026 onward, using volumes available at the start of that year. Amounts are in constant prices, with no inflation adjustment.
For scale, net UK oil and gas tax receipts were £4.5bn in 2024–25 and £4.3bn in 2025–26, of which the Energy Profits Levy raised £2.9bn and £2.6bn (HMRC, October 2026).
Prices
The default inputs are $115 a barrel for oil and 240p a therm for gas, easing to $70 and 85p over three years. The calculation follows the selected price path month by month from January 2026. A flat-price scenario stays at its selected prices. These are adjustable assumptions, rather than live quotes or a reconstruction of actual monthly prices.
Tax rates
The default EPL end date is 31 March 2030. The calculation splits the year at that date, with the successor levy starting immediately afterwards. The early-expiry preset is a hypothetical scenario. If the price-floor option is selected, the model permanently ends EPL when both modelled six-month price averages meet the ESIM thresholds. It needs six modelled months before its first test and does not infer an actual trigger from unavailable historical prices. Published thresholds through 2026–27 are used; later thresholds stay at that level in constant 2026 money.
Costs
The calculation divides annual production and costs evenly between months. It deducts operating costs and investment from sales, with no profit tax on monthly losses and no losses carried forward. Corporation tax, the supplementary charge and applicable EPL are then calculated. The former additional 29% EPL investment allowance starts at zero; the slider lets you model restoring it. After EPL ends, the model applies the announced Oil and Gas Revenue Levy to monthly sales above the chosen thresholds. This proposed revenue charge can apply even when costs exceed sales. Prices and thresholds use constant 2026 money, rather than a forecast of future inflation. Decommissioning relief uses the combined corporation tax and supplementary charge rate and is spread across modelled years up to 2050. When oil or gas is shown separately, relief is divided by their remaining volumes. Gas uses about 60 therms per boe. Company tax positions, other allowances, petroleum revenue tax and payment timing are excluded.