Consultation outcome

Oil and Gas Price Mechanism Consultation: Summary of Responses

Updated 26 November 2025

1. Introduction

The government announced at Autumn Budget 2024 its intention to develop a permanent successor to the Energy Profits Levy (EPL), the Oil and Gas Price Mechanism (OGPM), recognising the need for greater long-term certainty for the oil and gas sector and a more stable fiscal approach in times of high prices. Proposals for the OGPM were published for consultation on 5 March 2025. This new regime will be designed to respond to future price shocks and provide a predictable environment for investment once the EPL ends. The consultation closed on 28 May 2025. The government received just under 100 responses from industry stakeholders and other interested parties, such as tax advisors, environmental groups and individuals.

The consultation sought views on how a future regime could best meet the government’s core objectives. These are to ensure that the mechanism delivers a fair return on the UK’s resources during periods of unusually high prices; to deliver predictability and certainty for industry; to minimise distortions on investment decisions; to minimise administrative burdens for both taxpayers and HMRC; and to recognise the distinct characteristics of the oil and gas markets, ensuring that any approach remains responsive to their differences and specific challenges.

Respondents were also asked to provide feedback on two potential models for the new regime and consider how each model could best deliver fairness, predictability, and simplicity, while supporting investment and recognising the distinct dynamics of the oil and gas markets. They were also asked for views on the factors that should be considered when setting a threshold for unusually high prices.

The government values the constructive engagement received throughout the consultation process from all stakeholder groups and remains committed to ongoing dialogue with the sector and wider stakeholders. As the North Sea continues to play a role in the UK’s energy mix, the government is determined to manage its transition in a fair, orderly and prosperous way, ensuring the oil and gas industry can contribute to the move towards clean energy. This summary of responses sets out the main themes and viewpoints raised in consultation responses, highlighting areas of consensus and divergence to inform policy development, and sets out the government’s response.

2. Government decisions and consultation response

The government is grateful to everyone who took the time to respond to this consultation and who met with government officials during the consultation period, including at workshops, roundtables and bilateral meetings.

The government remains committed to introducing a permanent Oil and Gas Price Mechanism (OGPM) that delivers fairness, predictability, and simplicity while targeting windfall gains during periods of unusually high prices. After careful consideration of consultation feedback, the government has decided to adopt a revenue-based model (RBM) as the core design for the OGPM. This approach best meets the mechanism’s objectives by directly linking tax liability to exceptional market conditions and ensuring that operators benefiting from windfall revenues contribute a fair return on the UK’s resources. While the ambition is to implement a transaction-based OGPM to effectively target windfalls, the government acknowledges practical challenges in tracking hedging outcomes and will work with industry to identify a level of transaction data that balances administrative feasibility with policy integrity. The government recognises that high prices often coincide with increased operating costs; however, it considers that indexing thresholds to inflation over time provides sufficient protection against these pressures, and therefore additional deductions for exceptional costs will not be introduced.

In setting thresholds, the government will adopt two price points, one for oil (in dollars per barrel) and one for gas (in pence per them), with Natural Gas Liquids treated as oil for simplicity. The government will take a holistic approach in determining the level of the thresholds and consider several factors in the round. These are historical prices, long-term price assumptions and the costs associated with investment in oil and gas production in the UK and UK Continental Shelf. Most stakeholders considered this a balanced approach and an improvement on the methodology used to set the EPL price floor (“Energy Security Investment Mechanism”) thresholds. The OGPM thresholds will be adjusted annually in line with CPI inflation to maintain their real value and ensure predictability over the long term. This approach reflects strong stakeholder support for transparent, pre-determined adjustment rules and aligns with the government’s objective of future-proofing the mechanism.

Administration of the OGPM will leverage existing Corporation Tax provisions wherever possible to minimise compliance burdens, while continuing engagement with stakeholders to ensure deliverability and proportionality. - 2.5  In summary, the government’s decision reflects a balance between targeting genuine windfall gains, maintaining competitiveness in a mature basin, and providing a stable and predictable fiscal regime. The OGPM will be legislated for in the next available Finance Bill, ensuring a smooth transition to a permanent mechanism that supports investment while safeguarding public revenues.

Overview of OGPM

The OGPM will be a revenue-based tax and will apply to upstream oil and gas companies operating in the UK/UKCS (broadly companies subject to the Ring Fence Corporation Tax regime). A company will be in scope of the OGPM where:

A. It (the company) disposes of oil or gas and,

B. The consideration received (i.e. the realised price a company receives) for the disposal of oil or gas exceeds the relevant threshold.

The OGPM will be a permanent feature of the fiscal regime but will only apply during periods of high prices and the amount that will be chargeable to the OGPM will be the part of the consideration that exceeds the threshold.

The OGPM will come into effect once the EPL ends – either on 1 April 2030 or earlier if the Energy Security Investment Mechanism triggers.

The thresholds and rate

The OGPM tax rate will be 35%.

The government will set two thresholds: one for oil and one for gas, and they will apply per financial year.

The OGPM thresholds for the financial year 2026 to 2027 will be:

• Oil: $90 per a barrel
• Gas: 90p per a therm.

For subsequent years, thresholds will be adjusted using the Consumer Price Index of the preceding year. Projected thresholds for the following financial years are below. (The final detail on how thresholds will be adjusted will be set out in due course and the actual thresholds, using that methodology, will be published by HMRC prior to the relevant financial year).

Financial year	Oil	Gas
2027 to 2028	$91.88	92p
2028 to 2029	$93.70	94p
2029 to 2030	$95.66	96p
2030 to 2031	$97.59	98p

Note – all estimated thresholds are rounded up to the nearest cent for oil and the nearest penny for gas

Consideration received for the disposal of Natural Gas Liquids (NGLs) will be treated as consideration for oil for the purposes of this mechanism. NGLs will need to be converted to barrels of oil equivalent (BOE).

Next steps

The government will continue to work with the sector to deliver this mechanism as effectively and efficiently as possible.

The government will then introduce legislation in the next available Finance Bill to provide for the OGPM once the EPL ends.

3. Summary of Responses

Policy Options

The consultation asked respondents for their views on the two proposed policy options. The first, a revenue-based model (RBM) that would target the excess revenue a company receives for its oil and gas sold above threshold prices. The second, a profit-based model (PBM) that would target a proportion of profits deemed to arise from unusually high prices by reference to ‘average market prices’ and the thresholds.

Revenue-based model

Do you foresee any challenges with using the realised price (rather than market price) as the determinant? If so, please provide further comment on those challenges.

The majority of respondents supported the use of realised prices rather than market prices as the determinant, on the grounds that realised prices more accurately reflect the revenue received and therefore better align with the principle of taxing genuine economic gains. Many argued that market prices can differ materially from the prices companies achieve due to hedging, quality differentials, or the timing and structure of sales contracts, so a market‑price basis risks taxing windfalls that were not earned. Many asked that realised prices include hedging gains/losses and associated costs, but exclude unrealised fair‑value movements.

Some stakeholders raised a concern around the administrative complexity of implementing a realised-price approach on a transaction-by-transaction basis. Several respondents pointed out that hedging is normally conducted at the portfolio or corporate level and not linked to individual sales, making it difficult to match hedge outcomes to specific transactions, especially for high‑frequency gas sales. Others observed that compiling and verifying consistent realised-price information across industry participants could be burdensome. Some stakeholders suggested that any mechanism using realised prices should operate at the level of an accounting period, rather than for each individual transaction, to make compliance more practical. A few respondents also noted potential challenges in cases where sales take place within corporate groups, where transfer-pricing rules would already apply. Views differed on burden: some anticipated material effort if per transaction; whilst some also considered it fairly manageable with the right framework.

While support for realised prices was widespread, a small number of respondents favoured simpler approaches such as using average or benchmark market prices, arguing that this would reduce administrative effort. A minority also argued that high-price sales should be assessed individually to ensure that all instances of unusually high revenue are captured.

If you produce oil or gas, what is your strategic approach to mitigating the risk of price fluctuations? For example, how are different hedging practices and/or other financial instruments used? And what is the extent to which your organisation hedges vs selling at spot price? If you do not produce oil or gas, what are the strategic approaches to mitigate the risk of price fluctuations that you see in the sector? For example, how are different hedging practices and/or other financial instruments used?

When describing their approach to managing price risk, most producers said that hedging is a normal part of their operations, designed to stabilise cash flows and protect against commodity price volatility rather than to speculate on prices. Many said they hedge a proportion of forecast production on a rolling basis, commonly higher in the near term and tapering over 2–3 years, using financial derivatives (with the precise coverage driven by risk appetite, market conditions and lender covenants; ranges cited spanned roughly 25–80% in the current year).

Some stakeholders stated that they rely less on financial hedging and instead manage price risk through diversified portfolios or long-term sales contracts. Others emphasised that strong balance sheets or integration across parts of the energy value chain reduce their exposure to price movements. The extent of hedging often depends on risk appetite, market conditions, or requirements imposed by lenders under debt facilities. There was general agreement that the combination of hedging practices, contractual structures and cost pressures means that headline market prices can have a significant impact on realised prices (and do not necessarily represent the profits actually achieved by companies).

Respondents asked for clarity and simplicity in how any new mechanism would treat realised prices and hedging outcomes, and for sufficient time to implement changes to reporting systems. Overall, respondents stressed the importance of designing a framework that targets genuine realised gains, recognises the widespread use of hedging in the sector, and avoids creating unnecessary administrative burdens or distortions.

Do you envisage any challenges to applying a RBM on a transaction basis? If so, please explain (including an assessment of the additional administrative burden). Linked to this, please provide comments on whether using the first point of sale following extraction as the tax point achieves the right outcome. If you produce oil or gas, please provide information on how your organisation sells their oil and gas, as well as your record keeping practices.

Many industry respondents noted challenges to applying a RBM on an individual transaction basis. Primarily, this was related to concerns over the potential administrative burden, as the initial approach would require tracking, analysing and reporting every individual oil and gas sale against the relevant hedging gain or loss. Respondents noted this would be more burdensome for gas than oil, as sales of gas are made on a daily basis. Under a transaction-based approach, each transaction would need to be individually assessed for threshold breaches, with hedging allocations and adjustments for non-arm’s length sales.

However, a large number of stakeholders confirmed that detailed records of sales transactions are already kept for statutory and audit purposes. Many respondents proposed that if a RBM is pursued, a pragmatic approach could be to apply an average realised price over a specific defined period (either over an accounting year, quarterly or biannual).Several respondents said that a transactional RBM would tax short lived price spikes (notably in gas due to seasonality/volatility), potentially creating distortions and investor uncertainty; therefore averaging is seen as mitigating this. A minority raised concerns that using average prices over a longer period rather than per transaction could be gamed: producers might advance or defer sales to lower their exposure and smooth revenues.

On the use of first point of sale following extraction as the tax point, there was broad support across respondents, as this generally aligns with existing tax and accounting practices and represents the point at which the producer realises value from the commodity. This approach is seen as logical and administratively workable, provided existing rules for non-arm’s length sales are retained and adapted as needed.

The government would welcome representations on the exceptional costs (above inflationary changes) that companies may experience during unusually high prices. Please provide supporting evidence.

Many respondents said that exceptional costs, often above general inflation, are experienced during periods of unusually high oil and gas prices. These costs include, but are not limited to: rig rates, vessel and equipment hire, labour and contractor rates, logistics and transportation, fuel and energy for operations, and compliance costs (such as carbon allowances).

Stakeholders noted that supply chain tightness and increased demand during high price periods drive up costs rapidly, and these elevated costs often persist even after commodity prices fall, creating a lag effect. Industry benchmarking and cost indices (e.g., NSTA and S&P Global) are cited as evidence of these trends. Several respondents highlighted that costs per barrel tend to increase as production declines in mature assets.

A minority of respondents argued against allowing additional cost deductions, suggesting this could undermine the policy objective and create opportunities for tax avoidance or administrative complexity. However, the prevailing industry view is that any mechanism should carefully consider the impact of exceptional costs to maintain fairness and support ongoing investment.

Profit-based model

The government would welcome your views on the overall design of the PBM.

Many respondents were attracted to a PBM as it would allow deductions for certain in-year costs when calculating tax liability and they considered profit-based taxation to be a more familiar approach which would be well understood by investors.

On the average market price, many responses proposed for HMRC to publish the average market price on an annual basis to support compliance activity and give taxpayers certainty. Some responses mentioned that not considering a company’s realised price could mean there is a risk tax is payable under the PBM even when a company’s realised price is below the thresholds. This could be due to the impact of hedging contracts entered into years in advance, for example, where future oil and gas production is sold at a predetermined market price. To control for this distortion, it was suggested a company’s realised price over an accounting period should be used to determine tax liability in the PBM rather than an average market price.

Some stakeholders made suggestions in relation to the tax base of a PBM. There were calls for finance and decommissioning costs to be deductible and for exceptional gains such as balancing charges to be excluded. A minority of respondents suggested the existing Ring Fence Corporation Tax base could be reused for a PBM to ensure administrative simplicity. Some responses emphasised the requirement to calculate the average market price and deemed profit for oil and gas under a PBM should borrow from existing processes wherever possible to reduce any additional administrative burdens.

On the treatment of losses, whilst deductions for in-year costs was welcome by most stakeholders as noted above, some responses expressed concern that the risk reward profile for projects could be altered given it is not envisaged carry forward of losses or loss carry-back would be permitted under a PBM. Those responses set out that given oil and gas projects are capital intensive and involve long timescales, it would be important for full lifecycle costs to be taken into account when determining the tax base of PBM. A minority of stakeholders went further suggesting financing costs should be deductible.

Some responses included wider comments on a PBM. These sought clarity on the deductibility of tax paid under PBM in the permanent regime or advocated for progressive tax rates to increase the charge to tax depending on the extent to which the threshold price is exceeded.

The government would welcome your views on the tax base and definition for adjusted ring fence profits for the PBM.

Whilst responses generally supported aligning the tax base for a PBM with taxable profit used for EPL purposes to support simplicity and minimise additional administrative burdens, stakeholders raised several points in relation to the tax base.

On acquisitions and disposals, stakeholders advocated excluding chargeable gains or losses and balancing charges to avoid interfering with planning and incentives around asset-based transactions. It was also suggested forms of non-hydrocarbon related income such as Petroleum Revenue Tax (PRT) refunds and tariff income, with the exception of hedging gains and losses, should be excluded from the tax base on the basis these income streams are not generated because of, or affected by, unusually high prices.

A small number of respondents argued all costs incurred over a project lifecycle should qualify for relief. This includes capital expenditure, operating expenditure, decommissioning costs, and finance costs for those reliant on debt financing for their investments. Allowing deductions for full costs would be important to ensure PBM reflects the true profit from a company’s activities irrespective of when it was active.

Some respondents disagreed with aligning the tax base for a PBM with taxable profit used for EPL purposes and argued capital allowances should not be allowable to reduce average profit. Instead, tax liability should be based on gross revenue less operating costs.

Do you agree that the most appropriate way to account for the different oil and gas markets in a profit calculation is to use a proxy rather than attempt to apportion costs? Please provide additional detail to support your view. In addition, what proxy would be most appropriate to use?

Most respondents noted that using a proxy to account for the different oil and gas markets in a profit calculation is the more pragmatic, appropriate and administratively efficient approach to apportion profits between oil and gas. The majority of respondents noted a proxy would be much simpler than trying to consistently allocate costs between oil and gas assets, which would be administratively complex.

On the type of proxy, the majority of respondents did not have preference between a revenue-based proxy or a production-based proxy, suggesting either proxy could work. Respondents placed most emphasis on the outcome, that whatever the chosen proxy is, must be fair, auditable, and predictable, with safeguards to avoid arbitrary outcomes. A number of stakeholders did note that under a production-based proxy, whilst a benefit is costs are typically more closely linked to volume than revenue, specific consideration would be needed to avoid unusual outcomes, for example, volume-based proxies could disproportionately attribute profits to gas when prices are high, even though underlying costs vary significantly between oil and gas assets.

Administration of the Mechanism

A key objective of the mechanism is that it minimises, as far as possible, the administrative burden to both taxpayers and HMRC. The Government asked for respondents’ views on the best approach to administer the new mechanism.

Do you agree that, if possible, the mechanism should utilise the existing CT administrative provisions? The government would also welcome views on the best approach to administer this new mechanism (as well as an assessment of additional administrative costs), with a view to minimising the administrative burden.

The majority of stakeholders supported utilising existing Corporation Tax (CT) administrative provisions, recognising that this would generally help minimise administrative burden and complexity for both taxpayers and HMRC. Many respondents, however, highlighted a key caveat: the existing instalment payment regime is seen as inappropriate for the new mechanism, given the inherent unpredictability of unusually high prices. Several respondents therefore recommended that any tax liability under the new mechanism should be paid in a single sum after the end of the accounting period rather than in instalments.

A number of stakeholders suggested that group-level reporting and returns could further reduce compliance burdens, referencing precedents in other regimes. Some respondents advocated for separate administration of the mechanism to improve transparency and ease of tracking, while others proposed integrating it into existing CT filing processes.

On administrative costs, most respondents considered that leveraging existing systems will limit additional burdens, but several noted that a revenue-based mechanism (RBM), especially if applied on a transaction-by-transaction basis, could increase complexity and workload for both companies and HMRC so consideration should be given to this.

Comparison against government objectives

To analyse the merits of each model, the government used the policy objectives (set out in the introduction) for this mechanism. The government asked for stakeholders’ views on the merits of each model.

Do you agree with the government’s overall assessment that, in comparison with a PBM, a RBM better targets additional gains as a result of unusually high prices? Please provide additional comments to support your view.

Many industry stakeholders argued that a PPB would, on balance, better target additional gains from unusually high prices. Respondents noted that a RBM would, in some circumstances, tax companies when they are loss-making or cash-flow negative in that particular accounting period (even if the overall revenue from the project is greater due to higher-than expected prices), as it does not account for rising costs during high price environments.

Some respondents supported the RBM on grounds of simplicity, transparency, and robustness against profit-shifting and aggressive tax planning. These respondents argued that the RBM is easier to administer and provides a clearer link to exceptional market conditions. Some stakeholders expressed indifference to an RBM until they receive further detail on the design before coming to a decision.

Defining unusually high prices for setting the threshold

The government invited views on the factors it should consider when defining high prices, as well as practical considerations when setting the threshold.

Do you agree that two thresholds (one for oil and one for gas) are sufficient to effectively administer the new mechanism? If not, please provide detail on the variance between different blends, types and categories of oil and gas, the material impact on project economics as well as how many and which additional thresholds the government should consider. In particular, how should the thresholds account for NGLs to ensure that the mechanism effectively targets gains arising from unusually high prices?

The majority of respondents considered two thresholds sufficient for the effective administration of the Oil and Gas Price Mechanism, noting that additional thresholds would introduce unnecessary complexity and administrative burden for limited benefit. Several highlighted that Natural Gas Liquids (NGLs) are a minor part of most portfolios and supported either excluding them from scope or treating them as oil for simplicity.

Some suggested that, if a separate threshold for NGLs is required, only one should be used for all NGLs. A minority expressed concern that two thresholds may not fully reflect the diversity of yields and advocated for further consideration of a more nuanced approach, such as introducing multiple thresholds or a fixed discount to Brent to better capture variations in commodity value and ensure fairness in taxation.

Do you agree with the government’s current approach that the threshold for oil should be set in dollars per barrel and that the threshold for gas should be set in pence per therm? In particular, the government would welcome views on what currency the oil threshold should be set.

The vast majority of respondents agreed with the government’s proposed approach to set the threshold for oil in dollars per barrel and the threshold for gas in pence per therm. Some stakeholders highlighted the risk of currency fluctuation and potential of a strengthening dollar which would trigger windfall revenue in dollars but no windfall conditions in GBP. Under a RBM in particular, stakeholders mentioned that further clarity on the currency conversion metric will be needed.

Factors to consider when setting the thresholds

In order to set appropriate thresholds, the government is considering several factors: backward looking, historical data and forward-looking forecast data (short and long-term price assumptions used by experts, investors, operators, and government organisations). The consultation welcomed views on the approach to setting thresholds.

Do you have any views on the proposed approach to convert from nominal to constant prices when looking at the data series used to set the thresholds?

The government set out how it intended to account for inflation when considering historic and forecast prices. It confirmed it would focus on 2024 constant prices, and that to arrive at these figures, nominal prices will be converted to constant prices using a US GDP deflator for oil and a UK GDP deflator for gas. Most respondents agreed with this approach.

Historical oil and gas prices

Historical prices are a form of outturn data. They provide an accurate reflection of oil and gas prices over a period of time. The government asked respondents for views on the most suitable look-back period when assessing these prices.

What are your views on an appropriate ‘look-back’ period (and to what date) to consider when analysing historical prices?

The majority of respondents considered that a 10 year ‘look-back’ period was most appropriate to consider when analysing historical prices, however, others argued for a 20-year ‘look-back’ period Respondents who favoured a 10 year ‘look-back’ period argued that this would better reflect more recent market and price trends which have the most impact on operating costs and investment decisions. Respondents also acknowledged the challenges of selecting one look-back period as the basis for defining high prices, noting the shift in oil and gas markets.

Oil and gas price forecasts

Future oil and gas prices are impacted by several factors including, but not limited to, global economic activity, global and local production, and storage capacity as well as geo-political conditions. Forecasts provide a snapshot of future price expectation at a given time. The government asked stakeholders to provide a range of forecasts as they can provide a snapshot of future price expectation at a given time.

If you produce oil or gas, what are your ‘medium’ price scenario forecasts (or ‘central’ price assumptions) for both the short and long term? What are the drivers of these assumptions? What are your ‘high’ price scenario forecasts (or ‘high’ price assumptions) with supporting narrative on the conditions that may trigger this, and the expected likelihood/risk factor used? If you do not produce oil or gas what are your views on ‘medium’ and ‘high’ price assumptions? What is the driver of these assumptions?

Most oil and gas producers indicated that they use a range of price scenarios—including low, medium and high forecasts—when evaluating investment viability, but that final investment decisions tend to be made using low and medium price assumptions. Specific data provided is commercially sensitive and therefore will not be replicated here.

Respondents emphasised that price assumptions are only one aspect of investment decision-making, with other considerations such as reservoir and infrastructure risk also playing a significant role. Several noted that medium- and long-term price assumptions are highly dependent on unpredictable supply and demand dynamics, and highlighted the difficulty of forecasting prices accurately, given the poor track record of anticipating historic price shocks.

Cost of operating and investing in the UK/UKCS

The UK/UKCS is a mature basin. The costs associated with operating and investing in the UK/UKCS are therefore different when compared to other basins. The consultation asked for producers’ cost data to help the government consider the different factors involved when setting thresholds.

If you produce oil or gas, what is your full cycle average cost per barrel of oil equivalent (BOE)/per therm (as appropriate) in constant (2024) prices for historic projects and future projects and the cost sensitivity of those projects? If you do not produce oil or gas, what are your views on the costs of projects as outlined above?

The majority of respondents noted that operating costs per barrel are driven by many different variables that can change during a project’s life cycle. Some respondents also noted that data sources on cost per barrel may vary: some data sources include certain costs in their calculation of cost per barrel while other data sources do not.

Some respondents commented that they did not agree with the statement in the consultation that projects become more economically viable when prices are higher, noting that there are several factors that can influence investment decisions including the overall profitability of the project and the general investment climate.

Do you agree that the government should consider the historical oil and gas prices, oil and gas price forecasts, as well as the cost associated with operating and investing in the UK/UKCS when setting the thresholds? Are there any other factors the government should consider? Should any factor hold greater weight?

The majority of respondents agreed that historical oil and gas prices should be the primary factor when setting thresholds, as these provide a factual and auditable basis for determining what constitutes “unusually high” prices. Many suggested using statistical analysis—such as standard deviation or percentile analysis—over a sufficiently long lookback period to identify genuine price shocks rather than normal market fluctuations or cyclical variations.

Most stakeholders considered oil and gas price forecasts to be less reliable due to their speculative nature and frequent revisions, with several explicitly cautioning against giving forecasts significant weight in threshold setting. Some noted that while forecasts and current operating cost expectations may provide useful context, they should not be central to the methodology.

There was broad agreement that the costs associated with operating and investing in the UK/UKCS should be considered, given the high and rising costs in the mature UK basin. Respondents highlighted issues such as increasing carbon compliance costs, transportation tariffs, and regulatory burdens, noting that these costs can vary significantly between fields and may disproportionately impact smaller producers. A few stakeholders argued that these costs are already reflected in the existing fiscal regime and thus should not be double counted in threshold setting.

Several respondents recommended that the government also consider international benchmarks, comparing the UK’s fiscal environment with other mature basins to ensure competitiveness and continued investment. Some also noted the importance of considering broader factors such as security of supply, employment, and support for energy transition projects.

On weighting, most respondents felt historical prices should hold the greatest weight, with costs as a secondary consideration followed by forecasts. A few highlighted the need for clear, transparent methodology and suggested that only true price shocks—rather than temporary or seasonal fluctuations—should trigger the mechanism.

How should these factors be used when setting the thresholds

The consultation set out that in order for the mechanism to meet its broader policy objectives of minimising the impact on investment and ensuring a fair return for the nation’s resources during times of unusually high prices, the government will set the thresholds above:

• Average long-term historical price
• Current central price assumptions
• Costs associated with operating and investing in the UK/UKCS

Do you agree that setting the thresholds using these factors is an appropriate starting point for determining unusually high prices, capturing a fair return of the UK’s resources and ensuring investment is not impacted? If not, what factors, with supporting evidence, would be more appropriate?

Most respondents agreed that setting thresholds using historical prices, price assumptions, and UKCS operating costs is an appropriate starting point for determining unusually high prices and capturing a fair return on the UK’s resources. There was broad consensus that thresholds should be set above long-term historical highs and current high price scenarios, ensuring the mechanism only applies in genuinely exceptional price environments and does not undermine investment decisions.

Several respondents said the need for thresholds to be sufficiently high so that companies can offset periods of low prices with above-average returns, maintaining long-term viability and investment attractiveness. There was concern that thresholds set too low—such as those based simply on averages—could capture normal market volatility rather than genuine windfalls, risking negative impacts on investment and project economics.

A number of stakeholders highlighted the importance of a stable and predictable fiscal regime, noting that investor confidence has been damaged by recent interventions and that global investment is highly mobile. They stressed that the UK must remain competitive compared to other jurisdictions, especially given the mature and high-cost nature of its basin. Some respondents suggested additional factors, such as environmental considerations and the polluter pays principle, should be incorporated to ensure broader policy objectives are met.

Some said that historic price data alone may not always capture genuine windfalls, and that thresholds should be set with reference to exceptional price spikes rather than averages. Several respondents called for a clear, transparent methodology that is independent of the specific tax mechanism used.

In summary, the majority view is that using historical prices, price forecasts and UKCS cost profiles is a fair and evidence-based approach, provided thresholds are set high enough to avoid penalising normal market activity and investment. There was some support for additional factors such as environmental impact and international competitiveness, and strong calls for methodological clarity and fiscal stability.

How to ensure the thresholds are future proof

The government’s second key objective for the new mechanism is that it will be predictable and provide certainty. It is the government’s desire to design the mechanism in a way that it is future proof. Therefore, it will have pre-determined rules on how the thresholds will be adjusted over time to ensure that the thresholds meet the mechanism’s key objective over the long term. The government sought views from respondents on this principle and on using the GDP deflator.

Do you agree with the overarching principle of adjusting the threshold?

The majority of respondents agreed with the principle of adjusting the threshold. Most emphasised that annual adjustments are necessary to account for inflation and changing market conditions, ensuring the mechanism remains effective and only captures genuine windfall profits. Several stakeholders specifically supported using an index such as the UK GDP deflator for these adjustments, considering it a fair and broad measure.

Respondents highlighted that maintaining the threshold’s value in real terms is important for investment competitiveness and fiscal predictability. Many noted that rising operating costs in the UK Continental Shelf (UKCS) and the sector’s maturity mean thresholds must reflect the increasing cost per barrel, to avoid taxing companies that are not actually earning windfall profits.

A few respondents cautioned that the chosen inflation index must be appropriate, as an unsuitable index could undermine the mechanism’s effectiveness over time. There was broad consensus that adjustment should follow clear, pre-determined rules, ideally with annual publication aligned to existing fiscal processes. One stakeholder said that given the Brent price is set internationally in USD, and does not track an underlying GBP value, the USD oil price threshold should not be subject to retranslation each year.

Overall, there was strong support for regular, transparent threshold adjustments to ensure the policy remains targeted, proportionate, and supportive of long-term sector investment.

Do you agree that the most appropriate mechanism is a UK GDP deflator? If not, what would be more appropriate? What other challenges do you envisage of using a UK GDP deflator if the oil threshold was set in dollars per barrel?

Respondents agreed that the UK GDP deflator or CPI is appropriate to adjust oil and gas price thresholds for inflation, and this could be done annually. CPI has the benefit of being more broadly understood, and unlike the GDP deflator is not subject to ongoing revisions. Separately, respondents noted specific consideration should be given to oil and gas sector specific inflation in the mechanism design.

Equalities

If not covered by your answers to other questions, what are in your view the implications of these policy considerations for those who share a protected characteristic? If there are negative impacts, what potential mitigations could be considered?

A small number of respondents answered this question directly by advocating for hypothecation of revenues generated by the Oil and Gas Price Mechanism to support social groups most exposed to energy bills. Several other fiscal proposals outside the scope of this consultation were also raised as suggestions to support those who shared protected characteristics.