Yearly Archives: 2022

17 Nov 2022

Autumn Statement 2022

The Chancellor delivered the Autumn Statement 2022 today.

As expected the tax rate applicable to UK oil and gas profits is to be increased.  The headline rate of corporation tax for UK oil and gas upstream profits is now 75%.  

He also announced a new tax to be levied on some electricity generators at a rate of 45%.

Energy (Oil and Gas) Profits Levy (‘EPL’)

Increased rate of EPL

The rate of EPL is to be increased from 25% to 35%.  The revised increased rate of EPL is to come into force for profits arising from 1 January 2023.

Reduction of rate of EPL uplift

The investment expenditure uplift will be reduced from 80% to 29% from 1 January 2023. 

This results in effective tax relief for capital expenditures (and some operating and leasing expenditure) of 91.4%.  This compares to the effective relief of 91.25% in the current regime.

The reduction in the rate of uplift whilst justified with reference to the theoretical total rate of relief means that many companies with heavy investment programmes will now pay EPL. 

Decarbonisation expenditure – enhanced EPL uplift

In order to encourage oil and gas companies reduce carbon emissions, decarbonisation expenditure such as “modifying existing installations to use power from offshore windfarms, installing bespoke wind turbines to power the installation or running electricity cables to the installation from shore” will keep the current 80% uplift.  This could result in effective corporation tax relief for decarbonisation expenditure of 109.25%.

This appears to mean that building new infrastructure that is low carbon will not qualify for the enhanced uplift whereas retrofitting lower carbon infrastructure may qualify.  Difficulties will remain for some projects as expenditures will still need to be within the ring fence regime to qualify for this enhanced uplift.

Period of EPL

The legislated end date for which EPL will apply has been extended from 31 December 2025 to 31 March 2028. 

Previously government had also said that if oil and gas prices moved back to more normal levels then they would consider phasing out EPL.  However, the government have now announced that they will no longer consider phasing out the levy ahead of its legislated end date and stated that this will help certainty.

Government also announced that it will engage with industry over the coming months on the long-term tax treatment of oil and gas production in the North Sea. It said that “the review will focus on delivering predictability and certainty, to support continued investment as the UKCS matures”. However, it also noted that any outcomes of the review would only be implemented after the EPL has ended.

Legislation timeline

The government has announced it will introduce legislation in an Autumn Finance Bill 2022 which presumably will mean that these changes may be substantively enacted (or indeed enacted) by 31 December 2022.

The changes related to decarbonisation expenditure will presumably take more time to work through and therefore it was announced that these will be legislated for in Spring Finance Bill 2023.

Electricity generator levy

The levy will be applied to groups generating electricity from nuclear, renewable and biomass sources.  It will not apply to generators who use gas, coal, oil, hydroelectric or battery storage.

The levy only applies to generator groups that produce more than 100GWh on an annual basis.  There is also an annual allowance of £10 million.  Together this should remove most companies that produce electricity as an incidental source of income from the levy.

The levy is more like a royalty than a corporate income tax with revenues in excess of £75MWh being taxed at 45% without any deduction of operating or capital expenditure.  The levy is not deductible from corporation tax.

The levy will apply from 1 January 2023.  Government has announced it will consult with generator groups with the intention that the law will be included in the next Finance Bill.


It should be remembered that both finance costs and decommissioning expenditure cannot be deducted from EPL.  Therefore for many oil companies the effective tax rate for upstream activities will be substantially higher and for some will now be above 100%.

These rules apply disproportionately to companies that have predominantly oil production as crude prices, although have shown some increase over the last year, have not risen anything like at the same rate as gas prices. 

The actual burden of EPL will be sensitive to the phasing of income and expenditure within the EPL period for each company. Under existing rules, EPL losses can be carried back for only one year and will fall away after March 2028. With the extension of the application of EPL to just under six years it would have been appropriate for the loss carry back period to have been similarly extended. 

The removal of the promise to abolish EPL if prices reduce may allow some companies to better plan without fear of missing out on the investment incentives.  However, many others will consider the certainty of high tax rates even where prices have returned to normal as a high price to pay for that certainty and as the oil industry knows all too well tax law can be changed at any time.

Many potential investors overseas may look at two major increases to UK tax rates in under six months as a reason to believe that the UK basin is a place that has too much fiscal risk to consider incremental investment.

CW Energy LLP

November 2022

15 Nov 2022

Oil and Gas capital allowances relief- lessons from a recent case

The judgement in a recent case (Gunfleet Sands Ltd and others v HMRC [2022] UKFTT 35 (TC)), concerning the costs of evaluation and design of a potential windfarm development, provides some current judicial thinking on what costs may qualify for plant and machinery capital allowances (PMAs).  

For large capital intensive projects such as oil and gas projects, as well as alternative energy projects, the entitlement to tax relief for the costs of project scoping, planning, and evaluation has been an area of doubt for many years, and taxpayers have had to rely on interpretations that have not been tested in court. This windfarm case addresses such costs head on and concludes that relief under the plant and machinery code is wider than perhaps had been previously thought.

Any evaluation of the tax relief for capital intensive projects in the energy sector is likely to be affected by the lessons from this case. Although the decision may be beneficial in some cases, it may also adversely affect the relief available in the oil and gas industry, particularly as an application of the current decision may result in companies no longer being able to claim mineral extraction allowances on certain costs.

Unfortunately, a number of the difficult questions which arise where upfront planning costs are concerned did not need to be addressed in this decision as costs were incurred when the company was not yet trading, and allowances were only considered once the taxpayer had commenced a trade and at that stage most of the assets to which the planning and design costs related had been installed.


The case has had a long gestation period, with the claims to capital allowances dating back to 2009. The result goes against HMRC’s current interpretation of the law on a number of points. This is, however, a First Tier Tribunal (FTT) case and as such has no precedent value and indeed an appeal has been scheduled for hearing in June next year. . There were nevertheless some useful analyses which may be helpful in deciding whether similar costs on other long-term projects are claimable.

The expenditure

Plant and machinery capital allowances were claimed in respect of various different types of expenditure incurred in establishing an offshore wind farm array, consisting of the generating units (turbines mounted on the seabed) and the electrical cables (“array cables”) etc. from those units to a substation. The units and the array cables comprised “the generation assets”.

The dispute concerned, inter alia, the availability of plant and machinery allowances (PMAs) on “design” expenditure.

This design expenditure included environmental impact studies, studies of the sea conditions (metocean studies), geophysical studies of the seabed, and project management costs.

The claims to the disputed qualifying expenditure were made on the commencement of trade, meaning that expenditure incurred years before was only claimed at the time that much of the physical equipment was in place. This in turn meant that there was no need to address the application of the abortive expenditure rules in the plant and machinery code and, in particular, the issue of whether a claim for study costs could be made in a case where no plant was ever acquired or installed. 

The arguments in brief

HMRC argued that the generating units and electrical equipment were separate plant and machinery assets. In their view the expenditure on the studies was too remote to be counted as ‘on the provision’ of any of these separate items of plant and machinery as finally installed, as much of it was carried out to meet regulatory requirements on the impact of siting plant and machinery in specific locations.

In contrast, the companies argued that the whole windfarm array “the generation asset” was a single asset of plant (or machinery), and that the studies were incurred on providing that plant; choosing its configuration and installing it in accordance with all the regulatory requirements for environmental/shipping /wildlife impact assessments were all necessary to the provision.

The judgment – key elements

One asset, or many?

As in all capital allowance claims for plant and machinery, the asset must be identified. The identification of the plant can have an important effect. In this case, for example, the array might be seen to have a different function to a single installed turbine generator.

The judgment rejected HMRC’s contention that the individual elements constituted the relevant plant and machinery assets and held that the “generation asset”– the array – was the asset.

This determination will always be a question of fact which will need to be looked at on a case by case basis but the judgement offers some useful guidance on what will be relevant in any such decision.  Here, each generation asset was designed, manufactured and installed to operate as a single electricity generating unit and collectively were directed to a single purpose of generating electricity.

Studies and design – “On the provision of plant and machinery” or too remote?

HMRC argued that case law showed that “on the provision of” is tightly drawn and only extends beyond the price actually paid for the plant, to costs such as transportation, installation, and construction of the plant in question.

Additionally, HMRC argued that expenditure can be too remote if it has been incurred at a time when the identity of the plant to which it relates is not known.

HMRC further argued that the costs incurred on the surveys put the appellants in the position to know what plant and machinery to purchase, but those costs were not incurred on the provision of that plant.

The judgement sets out that the test to apply is whether the costs are needed to effect the actual provision or supply of the plant, together with the costs that must be incurred to make it usable at its basic level. Expenditure on the provision does not however include expenditure which is necessary or desirable to optimise the use of the plant.  The FTT cited the Barclay Curle dry dock case as precedent for determining this as the correct test.  That case also found that all expenditure which must be incurred before plant can be put in place to enable it to properly function should be regarded as expenditure on the provision of plant. The FTT correlated the term “must” with the word “necessary”.

In testing whether expenditure is necessary the FTT stated that this needs to be tested against the function or purpose for which the plant is designed.

In the case of the windfarms: they were designed to generate electricity. That generation function is carried out by the generation assets. These include the individual wind turbines which convert the kinetic wind energy into electrical energy. That electricity is then conducted to the substation by the array cables.

So, expenditure on design without which the windfarms or wind turbines could not carry out those functions, and without which the windfarms or wind turbines would be operationally useless, falls into the “must” or “necessary” category of design. It cannot be too remote.

Such “necessary” design qualifies as expenditure on the provision of plant whereas unnecessary design, would not. Furthermore, studies to choose the location of the entire array were excluded from qualifying as these did not determine the design, construction or installation of the array as installed.

It was held that much of the expenditure on studies was on the provision of the plant and machinery as finally acquired, despite having been incurred prior to the decision being made on which physical equipment would be acquired.  This earlier expenditure was still “on the provision of” the plant acquired, as it was essentially part of the necessary design work including the ‘design’ of the installation work.

The test was to be applied by reference to the effect of the expenditure (on design and installation), and not its purpose. The FTT judge further commented that any duality of purpose (such as the ‘purpose’ of meeting regulatory requirements) should not affect the decision.

The FTT considered each of the various studies separately, with some being held to qualify and others not. The fish and shellfish study costs were allowed to the extent the studies dictated the necessary installation techniques (minimising disruption to the fish). The detailed metocean studies were allowed as they affected the actual design for functioning and installation of the windfarm, but were not allowed to the extent they were used for modelling projected electricity output. These differences in treatment demonstrate the level of analysis required before a conclusion on deductibility can be drawn.

Project management costs

Separately, the project management costs were allowable, following the long-standing acceptance of ‘incidental’ costs of acquisition and installation being allowed, such as professional fees, to the extent they can be attributed to the provision of equipment subsequently installed.


The case is important as it is clearly the most detailed and relevant case on whether preliminary studies can be regarded as qualifying expenditure for PMAs.

While it is an important decision for expenditure on windfarms, it will also be of potential relevance to other projects such as alternative energy projects, energy transition projects and for development expenditures incurred in the upstream oil and gas sector.

In relation to the costs judged as qualifying for PMAs, the judgment raises a number of issues:

  • Timing – how companies can determine if study costs prior to finalising the procurement of equipment and prior to settling upon the installation method are allowable? The case did not have to deal with this practicality as these were initially pre-trading expenses, all treated as incurred on the commencement of trade once the actual plant had been in place.
  • Abortive expenditure – if the work is in preparation for a project that does not proceed, or equipment that is not procured or installed, the question arises as to what relief might be available. In order for expenditure on the provision of plant to qualify generally, such plant has to be owned by the company as a result of incurring the expenditure. Although the abortive expenditure rules provide for deemed ownership, these may not always be in point, depending on the precise contractual arrangements. A difficultly therefore arises for companies with on-going trades in assessing whether this ownership test can be met. This may be a particular difficulty for companies which might otherwise have claimed these types of costs under the mineral extraction allowances (MEA) code in the past. MEAs are not available for expenditure on the provision of plant regardless of whether that expenditure is abortive and even where such expenditure does not qualify for PMAs. The effect of this decision could, paradoxically, mean that there is greater risk of certain planning costs failing to attract relief or, at the very least, not qualifying for first year allowances (FYAs).
  • Disposal values if work is transferred – if studies are undertaken by an affiliate, is there a disposal of an interest in plant and machinery, notwithstanding there is no identifiable asset? Alternatively, can the uncompleted work represent an intangible asset, subject to the intangible asset regime?
  • Reclaim of Ring Fence First Year Allowances – where plant and machinery is not used within the ring fence within 5 years of the expenditure being incurred (as a very broad outline of the rules) FYAs are withdrawn (if they were claimed). Companies considering relying on the judgment to claim PMAs for design expenditure may choose to opt to claim writing down allowances instead.


Companies engaged in pre-development work and studies should carefully consider the potential for capital allowances to be claimed using the lessons from this case, and also be aware of the consequences of such claims.

Whilst this case may extend the scope of expenditure which falls within the plant machinery regime, for many projects there may be significant study and design costs which would not be in scope. Oil and gas companies may be able to fall back on the mineral extraction allowance code but for companies that do not carry on a mineral extraction trade there may be categories of expenditure which could fall down a gap and be treated as tax nothings. This is an unsatisfactory state of affairs given the push to develop alternative sources of power and the move towards “net zero”. 

We recommend that any company about to commence a long-term project carefully considers how the initial design and planning costs are likely to be treated for tax purposes, and to the extent they may not qualify for relief examine whether alternative ways of structuring the commercial arrangements might produce a better answer.

CW Energy LLP

November 2022

23 Sep 2022

Mini Budget 23 September 2022: No change for oil and gas sector

Today’s announcements by the Chancellor Kwasi Kwarteng did not contain any changes to the current corporate taxation rules specifically aimed at the oil and gas sector.

In particular, there was no announcement of a change to the energy (oil and gas) profits levy enacted in July this year. CW Energy continues to monitor the implications of this levy, working with clients to understand its impact.

For industry generally, as widely predicted the non-ring fence corporation tax rate will not be increased to 25% in April 2023 but will remain at the current 19% rate.

As also previously suggested, recent reforms to IR35 are to be repealed such that workers providing their services via an intermediary company will effectively be responsible for determining their employment status and paying the appropriate amount of tax and NICs.     

15 Sep 2022

CWE under new ownership

After nearly five years of being part of the Ince group, Phil Greatrex and Paul Rogerson have reacquired the CWE business from Ince. There will be no changes to the running of the client-facing part of the business. All of the partners and staff of CWE will carry on in their original capacities and can be contacted using their existing details as set out on our website.

We are now looking forward to developing the business as an independent practice again.

Please contact Phil Greatrex ( or Paul Rogerson ( if you would like to discuss this announcement.

CW Energy LLP
September 2022

31 Aug 2022

New Windfall Tax on the UK Oil & Gas sector

A new 25% tax on the UK upstream oil and gas industry is being introduced with effect from 26 May 2022, to be known as the Energy Profits Levy. The levy is intended to apply until 31 December 2025. It will be charged on the same profits that are already subject to ring fence corporation tax (RFCT) and supplementary charge, giving a combined rate of 65%. The RFCT profits are, however, adjusted by the disallowance of any loss relief, financing costs, and decommissioning costs. A new investment allowance at 80% of qualifying expenditure will be available to reduce profits subject to the levy.

The Chancellor announced on 26 May 2022 that a new “windfall tax” on the UK upstream oil & gas sector was being introduced. This is to be called the energy (oil and gas) profits levy or “the levy” but is referred to in this article as the Levy. A draft of the legislation was published on 22 June 2022 with a very short consultation period ending on 28 June 2022. The Bill was laid before Parliament for its first reading on 4 July 2022.

This note sets out the position as it is understood as of 4 July 2022 and should be read as being subject to any changes in the draft legislation that might arise as the Bill passes through Parliament.

Profits chargeable

 The Levy will be charged at a rate of 25% on profits falling within the ring fence regime (as set out in Part 8 CTA 2010) adjusted for certain specific matters and reduced by an additional expenditure amount broadly modelled on the existing supplementary charge (SC) investment allowances (Ch 6A to 9 of Part 8 CTA 2010).

This impost is in addition the ring fence corporation tax (RFCT) at 30% and SC at 10% levied on those same profits, giving an overall marginal rate of tax of 65%, although as the tax base for each of these taxes is somewhat different the overall effective rate of tax on profits will depend on the make-up of a company’s results for a particular period.

The Levy will apply to relevant profits accruing in the period from 26 May 2022 until 31 December 2025 or earlier if oil and gas prices revert back to a “historically more normal levels”. The draft legislation contains no provisions regarding this potentially earlier cut off, although when questioned in Parliament the Chancellor suggested average and normal Brent prices over the last 10 years were between $60-$70. This uncertainty over the period for which the Levy will apply makes planning very difficult, and industry has asked for further clarification on this aspect.

Where actual accounting periods straddle either 26 May 2022 or 31 December 2025 there are deemed to be accounting periods ending on 25 May or 31 December 2025, and profits or losses of the actual accounting period have to be apportioned between the two notional periods (clauses 15 to 17 to the Bill). Other than capital allowances which are deemed to arise in the notional period in which the expenditure is incurred (applying capital allowance principles as set out s5 CAA 2001), all other income and deductions have to be apportioned on a just and reasonable basis. This is in contrast to the position for the SC rate changes in 2011, where the default was time apportionment, with the possibility of a company electing to use an alternative just and reasonable basis if time apportionment worked unjustly or unreasonably in the company’s case. This will hopefully generate fewer problems than those which arose with the SC change HMRC and industry had a different view of how the law was to be applied and this ultimately led to the issue being pursued successfully by Total in the Court of Appeal (Total E&P North Sea UK Ltd and Another v HMRC [2020] EWCA Civ 1419). There are no provisions to deal with straddling periods if the Levy is withdrawn prior to 31 December 2025 (because oil and gas prices have returned to a “normal” level), but presumably they would be introduced, if and when, this eventuality arose.

The adjustments that have to be made to the RFCT profits or losses to arrive at the profits or losses for Levy purposes are that; any relief for RFCT losses carried forward, carried back, or claimed as group relief, any decommissioning costs, and any financing costs all have to be added back; but the profits are then reduced by an investment allowance, and by any petroleum revenue tax (PRT) repayments referable to any PRT losses attributable to decommissioning expenditure. The definitions of financing costs and decommissioning costs are broadly the same as is used for SC purposes (with some minor drafting differences) (see s330C and s331 CTA 2010).

Investment allowance

The Levy additional expenditure allowance is set at 80% of qualifying expenditure, such that 100 of spend will give rise to a total deduction against levy profits of 180 (Cl 2 of the Bill). Qualifying expenditure is capital expenditure and certain operating and lease expenditure which is incurred for oil related activities as defined in s274 CTA 2010, i.e. expenditure incurred for ring fence purposes and is not incurred for a “disqualifying purpose”. In all cases decommissioning and financing costs are excluded from the allowance.

Qualifying expenditure is broadly the type of expenditure on oil related activities that qualifies for investment allowances within the SC regime (see The Investment Allowance and Cluster Area Allowance (Investment Expenditure) Regulations 2017), but unlike the SC investment allowances, the expenditure does not have to relate to a defined oil field or Cluster Area. There is also no requirement for it to be “activated” with production income before it can be set against Levy profits.  

Qualifying operating expenditure will be that which is incurred in relation to a facility or oil well and which enhances production rates, reserves, life of field, working life of a facility, or tariff income which can be earned by upstream infrastructure, but is not something representing routine repair and maintenance expenditure. The uplift is confined to facilities used in offshore oil and gas production. These rules should by now be reasonably familiar to upstream industry taxpayers given the experience with applying them within the SC regime.

Qualifying leasing expenditure also follows the definition used for the SC investment allowance. The past CT treatment of existing leases will impact the relief which is now available for Levy purposes and could give taxpayers with similar pre-tax profits very different Levy results.

Given the push by many upstream companies, both large and small, to invest in “alternative energy” projects, which is being actively encouraged, it is disappointing that investment allowance is not available in respect of such non-ring fence projects.

As noted above, certain expenditure is also specifically disqualified from the 80% uplift. Uplift is not available for expenditure on ‘second-hand’ assets (Cl 6 to the Bill). The rules here are very broadly drafted and deny the allowance on the acquisition of any asset where it would have been possible for an uplift to have been claimed by a previous owner of the asset, on the assumption that Levy was in place at the time that the owner incurred the relevant costs. The legislation includes as an example expenditure on the acquisition of a field interest, but would appear to apply to the acquisition of substantially all second-hand assets if previously held by a ring fence company, including exploration licences. As an example, expenditure on the acquisition of a vessel that had previously been used in connection with a UK field, even if many years previously, would not qualify for uplift whereas expenditure on the same type of vessel that had only previously been used in, say, the Norwegian sector would qualify.

There is also an anti-avoidance provision (Cl 5 to the Bill) which disqualifies any expenditure incurred for a “disqualifying purpose” from qualifying for the Levy additional allowance. A disqualifying purpose exists if the expenditure arises either directly or indirectly in connection with an arrangement, the main purpose, or one of the main purposes, of which is to obtain a levy advantage, i.e. a reduction, deferral or avoidance of the EPL.

Where qualifying Levy investment expenditure is incurred the marginal rate of relief can amount to 91.25p in the £ for a full taxpayer. This is made up with 30% RFCT relief; 10% SC relief; 6.25% SC investment allowance relief (albeit deferred until the relief is activated with income from the relevant field); 25% Levy relief; and 20% (25% x 80%) Levy investment relief.

Use of losses

While RFCT loss relief is denied, the rules include a bespoke Levy loss regime as set out in Schedule 1 to the Bill. Levy losses can be carried forward or carried back one year, or surrendered as “EPL” group relief against Levy profits of other group companies, as defined for normal group relief purposes. If the ring fence trade ceases, “EPL” terminal loss relief rules permit a three year extended carry back against profits within the Levy regime. These provisions are all subject to detailed rules including anti-avoidance provisions, but broadly follow similar rules for RFCT loss relief.

There are also matching provisions as for RFCT dealing with payments made for Levy group relief, and the so called MCINOCOT rules in Part 14 CTA 2010, and the transfer of trade rules in Part 22 CTA 2010 are applied to Levy losses.

The one year Levy loss carry back for ongoing trades seems overly restrictive given that Levy is expected to apply for only 3½ years and that new investment which the uplift is intended to encourage will inevitably take time to come to fruition. For example, full relief for investment from 2024 onwards (for December year end companies) may not be available where this generates losses.

In addition to the anti-avoidance rule for expenditure qualifying for the investment allowance referred to above, there is a further anti-avoidance rule for Levy losses in Sch 1 para of the Bill which is modelled on the 2017 loss TAAR, but is more widely drafted. The benefit of any Levy loss relief can be eliminated where the main or one of the main purposes of the arrangement which gave rise to the loss is to obtain a Levy advantage and it is reasonable to conclude, that the arrangements are intended to circumvent the intended limits of the relief or otherwise exploit shortcomings in the Act, but also where the arrangements include steps which are contrived, abnormal, or with no genuine commercial purpose.

Management and administration of the EPL

The rules provide that the Levy is to be charged as if it were an amount of corporation tax, with all enactments applying to corporation tax applying to the operation of the Levy, subject to any necessary modifications.

With respect to instalment payments they must be paid with reference to the deemed Levy accounting period in any straddling period as referred to above, as if it were a separate accounting period. When the Levy was announced on 26 May 2022 the explanatory notes set out that no instalments would be due until 14 January 2023. That has not however been provided for in the draft legislation and the normal instalment provisions will apply. It is understood that HMRC have realised that their systems could not cope with calculating interest payments on over or under repayments if the one-off 14 January 2023 date had been adopted.

The instalment payment regulations are being amended (Sch 2 para 3 of the Bill) is such a way that the provisions applicable to RFCT apply to the Levy instalments. As a consequence, December year end companies which are large or very large will have their first Levy instalment due on 9 December 2022 (six months and 13 days after the start of the deemed accounting period), and a final instalment in respect of the deemed period to 31 December 2022 on 14 January 2023 (14 days after the end of the accounting period). For June year end companies there will be a single instalment payment due for the whole of their liability for the 36-day deemed accounting period ending 30 June 2022 on 14 July 2022. It is however not yet clear whether the Bill will be enacted by that date or the consequences if it has not.

The Bill (Cl 12) includes a requirement to notify HMRC of the amount of any Levy being paid, on or before the date any such payments are made. This notification should be made by the company with the Levy liability or if a group payment arrangement is in place the group company responsible for paying the group’s tax liabilities.


There are a number of aspects of the rules that appear surprising.

Firstly, ring fence capital gains, i.e. capital gains on the disposal of licence interests which contain a determined field, and any assets sold in conjunction with such a disposal, are subject to the Levy. Capital gains by their nature capture all future profits from the field so for any field interest where the field is expected to continue producing beyond 31 December 2025, any profits (appropriately discounted) post 31 December 2025 will be effectively subject to the Levy where a chargeable gain arises. It is possible that reinvestment relief under s198A et seq TCGA 1992 might be available to exempt any gain from RFCT, and therefore the Levy, but if that or other planning options are not available this is likely to prove to be a block on any field licence interests changing hands

Although the Bill now contains a provision to exclude the levy of PRT repayments from losses attributable to decommissioning expenditure, which wasn’t included in the original draft Bill published for consultation, PRT repayments from other losses are still brought in to charge. This appears anomalous in the sense that no Levy relief was available for the PRT originally paid which is now being repaid, giving rise to an unwarranted windfall to the Government, when the repayment has nothing to do with the current high price situation. Taxpayers will probably also be looking closely on whether making PRT repayments subject to the Levy will give rise a claim under against the Government under decommissioning relief deeds (DRDs).

Further, RDEC credits on ring fence expenditure are within the scope of the Levy, which would appear contrary to the policy of incentivising R&D investment.

Mitigation and Planning opportunities

Companies will want to look carefully at the cut off rules to ensure that profits that do not need to be brought in can be excluded.

Factors such as the limited time frame for which the Levy is to apply and the material uplift which is available on certain expenditures will also mean that companies will want to review existing and potential project timings carefully. Companies which are expected to pay significant amounts of the Levy may also want to look at investment opportunities which may produce tax relief up to 91%, particularly if those opportunities might otherwise be pursued by companies with the expectation of little or no Levy liability. However, the fact that partners in a particular joint venture may be in materially different Levy positions could lead to misalignment and commercial tensions within that joint venture. Any planning ideas will of course have to be looked at carefully in light of the Levy losses anti-avoidance provision referred to above.


The introduction of this additional levy against UK upstream oil and gas profits adds an extra layer of complexity to an already extremely complex tax regime, and will have an adverse effect on industry confidence, thereby potentially having the opposite effect of the Levy investment allowance which is intended to boost investment in the sector. Although there may be an advancement of projects in the short term, it is unclear whether any of these will be incremental. It will also provide no encouragement to the sector to invest in alternative energy projects giving the Levy will reduce the profits available to invest and such expenditure cannot qualify for the Levy investment allowance. Any reduction in investment will also have an adverse impact on the support sector that haven’t had the same benefit of high commodity prices.

This article was originally published in The Tax Journal on 15 July 2022.

CW Energy

July 2022

14 Jul 2022

Energy Profits Levy – now enacted

The Energy Profits Levy (EPL) rules have now been finalised, and the rules are contained in the Energy (Oil & Gas) Profits Levy Act 2022. The Act passed through the House of Commons stages on 11 July 2022 and received Royal Assent on 14 July 2022.

Our newsletter of 22 June 2022 ( referred to the consultation on the draft legislation, but the Bill as finalised reflects only two material changes of note.

Petroleum Revenue Tax

This change is to exclude from the EPL profits chargeable the amount of any CT income charged as a result of a repayment of Petroleum Revenue Tax to the extent the repayment is attributable to decommissioning expenditure, creating a PRT loss that is carried back.

The change addresses an anomaly we referred to in our Newsletter and at least means that whilst decommissioning expenditure is excluded from giving EPL relief, the PRT repayment derived from such expenditure should not be charged to EPL.

Certainty on expenditure qualifying for uplift

The original Bill included potentially very wide-ranging anti-avoidance wording that could have led companies to be concerned that any expenditure brought forward or incentivised by the 80% uplift could be caught by the anti-avoidance rules with the result that no uplift would be available.

These anti-avoidance rules have now been better targeted and should ensure that transactions that are commercially driven should not be barred from accessing the uplift.


The two changes noted are welcome.  However, there are areas that may be clarified further, for example, that electrification costs can qualify for EPL uplift.  We are expecting HMRC Guidance to be forthcoming and hopefully, this will cover these areas.

Companies should note that when the proposals were announced it was stated that the first instalment of EPL should be made with the last instalment payment.  This has not been included in the legislation and therefore, the instalment rules apply in the way they do for RFCT (but with a shorter accounting period for the straddling period).  Therefore a December year-end company should pay any tax due for the EPL period to 31 December 2022 on 8 December 2022 and 14 January 2023.

CW Energy LLP

14 July 2022

22 Jun 2022

Energy Profits Levy – draft legislation published for consultation

The Energy Profits Levy (EPL) draft legislation has now been published for consultation. The consultation period closes on 28 June 2022.

We understand that it is intended to have EPL enacted before the Summer recess but that the EPL legislation will not be substantively enacted for accounting purposes before 30 June 2022.

The comments below reflect the current draft, but we do not expect there to be much change given the compressed legislative timetable.

As expected the EPL applies to companies with ring fence trades and profits that would be chargeable to ring-fence tax. The EPL will therefore include relevant chargeable gains and PRT refunds.

The EPL will cover profits arising in accounting periods, or deemed accounting periods, starting from 26 May 2022 and ending on 31 December 2025.

The starting point for EPL is the company’s ring-fence profit or loss for a period, which will exclude any RFES, and is then adjusted to remove:

  • finance charges, determined using the SCT rules,
  • CT Losses brought forward, or back,
  • CT Group relief, and
  • Decommissioning expenditure.

An “additional deduction” is introduced as an uplift on so-called “investment expenditure” in the period. This is calculated as 80% of the relevant expenditure and counts as a deduction in computing the EPL profit/loss of the EPL period.

The rules include a bespoke EPL loss regime. EPL losses can be carried forward or carried back one year or surrendered as “EPL” group relief against EPL profits. If the ring-fence trade ceases, “EPL” terminal loss relief rules permit a three-year extended carry back against profits within the EPL regime.

The EPL profits and losses for accounting periods which straddle the 26 May 2022 and 31 December 2025 dates are to be apportioned on a just and reasonable basis except for investment expenditure which is to be apportioned with reference to when the expenditure was actually incurred (using the specific capital allowance rules on when expenditure is incurred). Overall we believe this approach will generate less difficulty than experienced when the Supplementary Charge rate was increased in 2011, where time apportionment was the default position adopted by the law.

The 80% uplift which generates the additional EPL deduction applies to investment expenditure as defined. This is broadly the type of expenditure on oil-related activities that qualify for investment allowance within the SCT regime, but unlike the SCT investment allowance, the expenditure does not have to relate to a defined oil field or Cluster Area. There is also no requirement for it to be “activated” with production income.

The definition covers not only capital expenditure but also some leasing costs and non-routine operating costs on facilities and wells that enhance production, reserves or tariff income. As with the rule for computing, EPL profits decommissioning and financing costs are specifically carved out from the uplift regime.

However, the 80% uplift is not available on ‘second-hand’ assets. The rules here are very broadly drafted and deny the allowance on any asset where it would have been possible for an uplift to have been claimed by a previous owner of the asset, on the assumption that EPL was in place at the time that the owner incurred the relevant costs. The legislation includes as an example expenditure on the acquisition of a field interest but would appear to apply to the acquisition of substantially all second-hand assets if previously held by a ring-fence company, including exploration licences.

There is no claw-back of any uplift on a transfer/sale of an asset but the new owner will not obtain the uplift on their acquisition cost, regardless of whether the seller actually obtained such uplift.

The rules also incorporate anti-avoidance specifically in regard to the 80% uplift and EPL losses for any avoidance arrangements with the main purpose of obtaining the uplift.

The rules provide for the normal CT machinery provisions to apply, including the instalment provisions, and a requirement to notify HMRC of the amount, on or before any EPL payments are made.


Overall the draft legislation is largely as expected based on the announcements last month.

The rules are generally tightly drawn. Companies will, in particular, need to look carefully at the transitional rules. There may also be some areas where companies can plan to mitigate their exposure. There does not seem to be anything in the draft which delays the instalment payments for December year-end companies until 14 January 2013 as previously announced.

The inclusion of ring-fence capital gains and PRT repayments appear particularly anomalous. Capital gains will be based on all future profits from the licence, capturing profits to be made after the sunset date of 31 December 2025. This is likely to deter any movement of field interests unless reinvestment or other reliefs can be found. For PRT repayments there is no relation to the excess profits through high prices that the levy is designed to catch. Indeed, the loss available to carry back will have already been reduced by the current high prices and is then being taxed again. Companies will no doubt be looking closely at whether this gives rise to a claim under the DRD.

CW Energy can assist companies in planning for and complying with the EPL.

CW Energy LLP
22 June 2022

26 May 2022

Chancellor announces a new oil and gas tax charged at 25%

This afternoon the Chancellor announced the recently anticipated, following significant political pressure, tax rise on the profits of companies that produce oil and gas from the UK and UK Continental Shelf. It does not apply to other energy sector players, such as the producers of green energy, as had been predicted in the Press.

Rather than increase the rates on existing taxes the Chancellor chose to introduce a new oil and gas tax called the Energy Profits Levy.  The Energy Profits Levy (the “Levy”) is effective from today and will be charged at a rate of 25%.

The Levy will be temporary and will be phased out if oil and gas prices return to “historically more normal levels” and in addition the legislation will include a sunset clause which will mean the tax is abolished from the end of 2025 at the latest.

The new Levy will be applied to “UK oil and gas profits”, which means ring fence profits from UK and UK Continental Shelf production subject to a number of adjustments.  One of the stated adjustments being leaving finance costs out of account as for SCT.  However, the RFCT and SCT profits to which the new Levy is applied will not be reduced by brought forward tax losses, nor decommissioning costs. Any “Levy” losses can however be augmented by the Levy allowance and will be available for carry back under normal CT rules (without the extended ring fence carry back), carry forward, and group relief, against other Levy profits.

It is not clear if the Levy will apply to ring fence capital gains, although that would have little economic logic given the Levy is only due to apply for a short period of time, and the value generating a capital gain will be representative of all future profits. As such this could create a big disincentive to assets moving hands into companies wanting to invest while the Levy is in place, and it is hoped that the exclusion of capital gains will be one of the “number of adjustments”.

The Levy will be payable along with the three instalments for RFCT and SCT, although for December year end companies the first payment will not be until January 2023.

Also announced is a new investment allowance.  We believe this applies to expenditure incurred from today.  The additional investment allowance appears to operate solely to give relief against the new Levy, albeit at an 80% rate. It will be given on top of the capital allowances relief that will reduce the profits on which the Levy is charged. 

The new investment allowance was described by the Treasury as meaning tax relief of more than 91p for each pound invested when combined with existing reliefs. This is made up of RFCT relief of 30p, SCT relief of 10p, SCT investment allowance relief of 6.25p, Levy relief of 25p, and Levy allowance relief of 20p. However, this rate of relief only applies if a company is already paying CT and SCT, and therefore reduces to 45p where a company has brought forward tax losses. If companies were still investing in PRT fields which had paid tax in the past the relief would be more than 100% of the costs.

Overall, the Chancellor referred to the measures providing an extra £5bn in tax in the next year.


These changes will be very unwelcome news to both upstream companies and the wider supply chain. 

Companies which have invested in new projects that have just started to produce will be particularly hard hit as their past investment costs will not be deductible against the new Levy.

As soon as further details are announced, CW Energy will provide further analysis.

CW Energy LLP

26 May 2022

23 Mar 2022

Spring Statement 2022

The Chancellor delivered the Spring Statement 2022 today.

Despite the speculation and calls for a windfall tax there was no announcement on any changes to the oil tax rates.  Therefore, the rates will continue to be those currently enacted being 30% for ring fence corporation tax and 10% for the supplementary charge to corporation tax.

In addition, there was no announcement on any changes to the calculation of profits chargeable to ring fence taxation.  Neither was oil and gas taxation mentioned in the Spring Statement Tax Plan.


While there have been many public statements in the last few weeks that HM Government were not considering changes to oil taxation it is welcome that the Chancellor has once again allowed a stable regime to remain in place.  This again is evidence that HM Government understands the importance of fiscal stability and should underpin the plan for more investment in UK domestic oil and gas production in these uncertain times in energy markets.

14 Mar 2022

Scope of the ring-fence: Result of the appeal in the Royal Bank of Canada case

In August 2020 we published a newsletter on a First-tier Tribunal (‘FTT’) case that considered whether an oil and gas royalty interest held by a non-UK resident gave rise to ring-fence income and whether the relevant treaty allowed HMRC to tax the income.  That newsletter can be found here:

As we reported at the time the taxpayer lost on both counts at the FFT and appealed. The appeal was heard by the Upper Tribunal (‘UT’) in December and the decision was published on 17 February 2022.  The UT confirmed the decision of the FTT on both the domestic law and treaty matters and consequently found that the royalty income was taxable as ring-fence income in the UK.

In terms of the treaty position, the UTT agreed that the oil royalty constituted “rights to variable or fixed payments as consideration for the working of, or the right to work, mineral deposits…” and therefore fell within the definition of immovable property under the treaty.

The key domestic law finding in terms of the wider relevance of this decision is the UT’s decision on the meaning of the “benefit of” exploration or exploitation rights. There was very little analysis of the meaning of this term in the FTT decision, and unfortunately, there is not much more in the UT decision.

The UT found that the oil royalty constituted “rights to the benefit of the oil because, provided that the oil was sold at a sufficiently high price to generate a payment of the royalty, the Bank would thereby benefit from the oil produced..” and the reference to benefit “is capable of including a wide range of arrangements, whether proprietary or contractual or otherwise, giving rise to a benefit, including a commercial benefit.”

As a consequence, the UT dismissed the grounds for appeal and affirmed that the UK domestic tax rules would, based on the facts of this case, treat the income arising as subject to tax in the UK as ring-fence trading income.

One matter to note is that this is a UT decision and therefore does set legal precedent.

The implications for taxpayers are as we set out in our original newsletter when the FTT decision was published.  Taxpayers should review any similar arrangements already in place

Generally, we see royalties of the type considered in this case to be created as a result of the transfer of interests in oil fields. It may however to be possible to distinguish some forms of contingent deferred consideration from the royalty in this case.

In today’s oil and gas price environment mechanisms that share the benefit of price fluctuations have remained common in transactions.  Such mechanisms should be considered carefully.

CW Energy LLP
March 2022