Author Archives: Donna Rogers

21 Apr 2015

Changes to derivative contract rules enacted -important time limits

Readers will recall our newsbrief last August on the topic of proposed changes to the Derivative contracts rules, requiring companies to make an election to benefit from the Disregard rules in 2015 and subsequent years.

Those rules have now been enacted as The Loan Relationships and Derivative Contracts (Disregard and Bringing into Account of Profits and Losses)(Amendment) Regulations 2014.

For companies adopting fair value accounting in relation to derivative contracts for the first time (“new adopters” in the terms of the Regulations) the period in which this occurs is called the “first relevant period”.

In this case the election to opt in must be made by the date which is six months after the start of the first relevant period for qualifying companies (i.e. those which are within the Senior Accounting Officer rules) or 12 months after the end of the first relevant period for others.

Thus for new adopters with a December 31 year end the first relevant period will be the year ended December 31 2015 and the election will be required to be made by June 30 2015 if large or by December 31 2016 if not.

There is however another category of election that is required to be made by companies that already prepare accounts which would require fair valuing derivative contracts, but who have not actually entered into any such contracts to date i.e. companies which are not new adopters .

In this case these companies are not covered by the grandfathering provisions but need to separately make an election for the Disregard rules to apply. In the absence of such an election they will be taxed on the fair value gains and losses arising on derivative contracts.

For these companies the election needs to be made in advance of the derivative contract being entered into. Thus it is important to identify this time limit, as if such an election is not made before any such contract is entered into, the Disregard rules cannot apply to the fair value gains and losses on that contract (or any other entered into before the election is made).

Consequently such companies may wish to make an election now to ensure that when they do enter into a derivative contract they will be able to benefit from the Disregard rules and not be required to be taxed on the fair value movements on such contracts.

CW Energy LLP

April 2015

31 Mar 2015

Finance Act 2015

Finance Act 2015 received Royal Assent on 26th March.

Accounts being drawn up to 31 March 2015, including quarterly accounts, will need to reflect the provisions of the Act, in particular the reduced rate of SCT of 20%, the extended period for ring fence expenditure supplement, the changes to the Field Allowance rules and the introduction of the new Investment and Cluster Allowances.

The reduced rate of PRT to 35% also became law but will not apply until CP I 2016.

For deferred tax purposes companies will need not only to take into account the effect of the new rates on balances brought forward but also, in the case of PRT  to assess the extent to which timing differences are expected to reverse at the existing rates or the new rates when preparing these accounts.

If you have any questions on the Finance Act 2015 changes please call your usual CW Energy contact.

18 Mar 2015

UK Budget 2015 implications for oil and gas companies

In his pre-election budget the Chancellor has responded to calls to reduce the tax burden on the oil and gas companies, but is it a case of too little too late?

As already announced the government have confirmed a package of measures which is intended to “substantially reduce oil and gas taxes to improve competitiveness in the North Sea” in today’s Budget. The government states that this package of measures is expected to lead to over £4 billion of additional investment and at least 120 million barrels of oil equivalent of additional production in the next 5 years, boosting oil production in 2019 by 15%.

The Finance Bill is to be published on 24 March 2015. As Parliament will be dissolved on March 30 there will be a very limited time for discussion so it is hoped there will be enough support for these provisions such that they will be included in the Finance Act.

Tax rate reductions

As widely rumoured the rate of supplementary charge is to be reduced by a further 10% in addition to the 2% reduction announced last year, such that the rate will be restored to the pre-2011 rate of 20%.

This reduction will be backdated to apply from January 1 2015.

In addition the government announced that the rate of PRT is also to be reduced to 35% with effect for chargeable periods ended after 31 December 2015.

A table of the old and new rates is set out below.


The reduction in the SCT rate will be welcomed by those companies which are currently tax paying.

However, most oil and gas companies are not currently taxpaying due primarily to their heavy investment programme.  Although these companies will benefit from lower rates in the future (should they be maintained), and the expectation of these lower rates may encourage further investment, most of the benefit of the rate reductions in the short term will be enjoyed by companies with mature projects who are in harvest mode,  i.e. not looking to reinvest in the North Sea. 

Indeed, although the government state that the package of changes will provide certainty for investors and create the right conditions for the basin to flourish and deliver maximum economic benefits for the UK, one of the main weaknesses of the current system is that there is no certainty that the rates announced will remain in place.

As can be seen from the above table, although the headline reduction in the PRT rate is 15%, if the company is also paying CT and SCT, when the reduction in SCT has been factored in, the actual benefit translates to an overall reduction in effective PRT from 19% to 17.5%  i.e. only 1.5%

Those companies which expect to be PRT paying in CP I 2016 and future periods will welcome the change but given that PRT applies to only the larger mature oil fields, it is  questionable whether this is the best target for relief.  The expected cost of this measure is £335m in the years up to and including 2019/2020. This contrasts with an expected cost of £965m for the reduction in SCT and the investment allowance over the same period.

However the real cost for government is likely to be much less than this as for many fields the reduction of tax rate will simply represent a cash flow benefit since much of the PRT to be paid will be repaid on abandonment. 

The other oil and gas measures included within this Budget were announced as part of the Autumn Statement 2014, as part of the plan for reform of the oil and gas fiscal regime. They are set out below:

Investment allowance

At the Autumn Statement date the Government undertook to consult on a new industry wide cost based investment allowance and following this consultation the allowance is now being introduced.

Details of the allowance are not due to be published until the end of this week but it has been announced that it will apply to expenditure incurred after April 1 2015, and that the rate of allowance will be 62.5%.

Through the consultation phase there have been a number of issues raised by the industry and we will have to see which, if any, have been taken up by Government once the detailed provisions are announced.

The reduction in the rate of SCT to 20% that was also announced of course reduces the quantum of the benefit of this allowance.


The new allowance is of general application and also provides a level of certainty that was not present in the previous field allowance regime, and it is hoped that this measure will go some way to stimulating more investment in the North Sea. However, this new allowance provides no immediate benefit to the many companies that are not currently tax paying, and it will be interesting to see if Government have thought about this issue. One possible measure to allow for the lost benefit arising due to the delay in using them would be to provide an RFES style uplift for these allowances.

The investment allowance is very similar to the new cluster allowance that is being introduced, the main difference being that in the latter case income from any part of the cluster can trigger the allowance whereas it is expected that only income from the field in question will trigger investment allowance.

While it is understood that the transitional rules will provide adequate protection for owners of fields that have already qualified for an “old” field allowance or are close to development consent, there could be many instances where the new investment allowance is worth significantly less than the previous regime. This is particularly the case for small new pockets of reserves where the existing volume based small field allowance provided a welcome boost, and it is hoped that this will not mean that otherwise economic prospects will not now be developed, or that companies will be discouraged from even looking for such accumulations. 

Seismic surveys

The government has confirmed that they will provide £20 million of funding for a programme of seismic surveys to boost offshore exploration in under-explored areas of the UK Continental Shelf.


Whilst this measure is welcome concern remains that exploration activity is at a historical low and further incentives are needed to ensure that the government policy of maximum economic recovery from the North Sea can be achieved.


The new Oil and Gas Authority is to be given the powers it needs to scrutinise companies’ plans for decommissioning programmes to ensure they are cost effective.

Cluster Allowances

Again this measure was confirmed at the Autumn Statement 2014 with draft legislation published at that time. Details were set out in our earlier Newsbriefs. There are to be a number of amendments to the scheme. The legislation will allow changes to the definition of qualifying expenditure to be changed by secondary legislation.  In addition the law is to be clarified to ensure that expenditure on the acquisition of a licence interest will not qualify.


One of the main issues with the Brownfield allowance regime was that it only applied to capital expenditure. This change will at least provide the opportunity for the scope of the cluster allowance to be wider and to cover certain “revenue” expenditures which we believe should be supported under the MER principle such as expenditures aimed at generating incremental production or at preventing a reduction in the rate of production.

There were also a number of non-oil and gas measures which nevertheless could be of importance to the oil industry.

Diverted profits tax (DPT)

As expected, it has been confirmed that the DPT tax, which was announced in Autumn Statement, is to be included in the Finance Bill.

While the detail is not yet available it is understood that there will be some changes to the original proposals, following representations made, mainly around the economic substance tests, but the provisions are otherwise as originally announced (see our newsletter of January 15th this year).


While HMRC’s stated intent is that the provisions are only aimed at catching aggressive tax planning and to generate early disclosure on transfer pricing issues, and our understanding is that the measures were introduced primarily to ensure groups generating revenues in the UK pay their “fair share” of tax, they are potentially of relevance to the oil and gas sector, particularly the support sector, and could therefore have an indirect adverse effect on upstream companies that are already suffering under the current climate.

Some service company activities which are caught by the so-called bareboat charter rules introduced last year could also fall foul of these DPT rules. In such circumstances, if no effective relief for the costs subject to the bareboat cap is obtained, the capped costs will be left out of account in arriving at any DPT charge.

It is not thought that many activities of upstream groups will fall within these provisions but we will need to see the final draft clauses and detailed guidance that we understand is to be issued next week.

Loss refresh prevention

A new TAAR is to be introduced which will limit the availability of certain carried forward reliefs, including trading losses, where profits are introduced into the company under arrangements having the obtaining of a tax advantage as one of its main purposes. As with the proposed diverted profits rules there is an exclusion if the other economic benefits of the arrangement exceed the tax advantage.

The introductory wording in the HMRC Press Release refers to contrived arrangements to convert a brought forward relief into something more versatile, but later defines the tests that will apply in much more general terms.

The reliefs that are covered by the TAAR are trading profits, non-trading loan relationship deficits, management expenses, qualifying charitable donations treated as management expenses, and management expenses arising on the cessation of a property business.


It appears that simple intra group asset or trade transfers could fall within these rules which, if correct, could have a significant impact on oil and gas groups which quite often have losses locked into one company which they would plan to utilise by reorganising the group if other group companies had successful projects.

The new TAAR does not appear to apply to pre trading losses so the change to the pre trading change of ownership TAAR, which the industry successfully lobbied for last year by the Industry, should not be affected.  The new TAAR could however prevent groups that own companies which have trading losses ever being able to sell those companies to recoup some of the losses of unsuccessful ventures.


CW Energy LLP

March 18 2015

16 Mar 2015

Loss Streaming on group reorganisations

The application of the loss streaming rules within the transfer of trade provisions (previously s343 ICTA 1988, now in CTA 2010 s940A et seq) was recently considered by the FTT in the case of Leekes Ltd v HMRC.

Very broadly a company which carried the a retail business through a number of branded high street stores took over another company with a similar business and following the acquisition of the shares immediately transferred the whole of the business of the acquired company into the acquirer. The acquired shops were rebranded and run as part of an enlarged business. The decision noted as a statement of fact that following the reorganisation the acquired stores continued to sell the same type of goods to the same customers and such selling was undertaken by much the same staff as before.

The taxpayer contended that the acquirer had succeeded to the acquired company’s trade and HMRC accepted this as a question of fact.

As a result the transfer fell within s343(1) and the taxpayer argued that the loss streaming rules in s343(8) could have no application because as a matter of statutory construction these rules only applied where the transaction fell within the circumstances set out within s343(8).

HMRC disagreed and refused to allow losses transferred across from the acquired company to be offset against any profits of the original trade of the acquirer.

The FTT agreed with the taxpayer.

It is surprising that having accepted that the transfer of the acquired company’s business was a succession HMRC should attempt to argue that the loss streaming rules should apply, as the previous authority of Rodin V Falmer Jeans seems to have clearly established that s343(8) was intended to extend the scope of section s343 to transactions which didn’t constitute a succession, and that it was only that extended category of transactions to which the provisions of s343(8) applied.

In our view the legal position has been clear for some time.  If the transaction results in the acquirer succeeding to the acquired company’s trade then there is no streaming.  However the difficult practical issue that one has always needed to address is determining whether a particular transfer does involve a succession. This is a question of fact based on the circumstances of the transferee and transferor both before and after the transfer.

In the upstream Oil and Gas industry we have examples of where HMRC have accepted that the transfer of the whole of an oil and gas company’s business into another company already carrying on such a business does constitute a succession (in which case HMRC accepted that streaming was not in point), but we have also seen examples of transactions where, based on facts which appeared to us to be on all fours to the succession cases, HMRC were not prepared to accept that the succession had occurred.

If groups are looking to  reorganise in circumstances where one or more of the companies involved have losses then the loss streaming rules do need to be carefully considered. In some cases, falling foul of these rules could result in no effective relief being available for the losses. There are of course a number of other provisions that will need to be factored in. This decision may be helpful in assisting companies in determining whether their potential transaction could give rise to a succession although Oil and Gas and retail businesses have their differents.

If you would like to discuss the issues raised in this note please contact Paul Rogerson or your normal CWE contact

12 Feb 2015

February 2015 Newsletter – Extractive Industries Reporting Requirements

February 2015 Newsletter Extractive Industries Reporting Requirements

1. Introduction

2015 is the first year of implementation of the first wave of initiatives covering the reporting of payments by extractive industries to governments or government agencies.

UK oil and gas companies will be affected by the following;

  • EITI (Extractive Industries Transparency Initiative)- a voluntary initiative promoted by the government and certain industry bodies that seeks to demonstrate the correlation between company payments and declared government receipts with first reports required in the first half of 2015, and
  • the EU Accounting Directive requirements for extractive industries, which adds further reporting requirements for companies in addition to the financial statements, with the first report to be filed for most companies by November 2016.

The details of payments reported under UK EITI are being aligned with the requirements of the EU Directive, but the EITI is being implemented first.

2. Content of reports; payments and other information    

The content of the EITI reports is to be based on the requirements for the EU Directive, except that that the EITI report is likely to seek additional information on beneficial ownership of companies, and is only concerned with payments to UK government bodies and agencies.

The EU Directive requires a report from each ‘large’ UK company unless it is a subsidiary of an EU or UK company which prepares a consolidated report incorporating the payments made by the company.

Reporting is required for ‘large’ companies and groups, and listed companies. For these purposes ‘large’ is where the group meets at least two of the following;

(a) its balance sheet total on its balance sheet date exceeds £18 million,

(b) its net turnover on its balance sheet date exceeds £36 million,

(c) average number of employees during the financial year exceeds 250.

The payments to be reported are those made to a government or government agency or similar body in relation to the extraction activities. These include licence fees, taxes (excluding VAT and salary taxes), and payments such as signature bonuses, production entitlements and similar payments. For some payments the relevant project will need to be identified. Fines, interest and penalties do not need to be reported.

Any payment whether made as a single payment or by instalments which exceeds £86,000 should be reported. This threshold is applied to licence payments on a licence by licence basis not in aggregate.

 3. EU Directive vs UK EITI  

 The aims of the initiatives differ;

  • EITI aims to demonstrate openness and accountable management of natural resources by the relevant country through an independent report reconciling government receipts and company payments,
  • the EU Directive aims to disclose EU company payments to any governmental authority worldwide.

 The difference between the objectives is reflected in the method of reporting; company reports made under the EU rules will be made electronically to Companies House, whereas EITI reports are simply requested by the independent administrator.

The first UK EITI report will cover payments made in 2014, whereas the first reporting required under the EU Directive is for payments in 2015.

 4. UK EITI reporting

UK EITI reporting is entirely voluntary. The independent administrator will invite companies to respond and HMRC will seek a waiver of confidentiality from companies to allow HMRC to share the details of payments.

The EITI process is evolving, but we expect requests to be made in the first quarter of this year, with a 3 month window in which to reply. It is assumed that the process will repeat annually.

The first UK EITI report will cover payments made in 2014, but to assist in identifying 2015 payments of ring fence CT HMRC has asked oil and gas companies to differentiate these from tax paid on other activities, and in particular to arrange for separate payments to be made. We have details of this suggested procedure if you require.

5. EU Directive reporting  

The Reports on Payments to Governments Regulations 2014 have been enacted into UK law to comply with the EU Accounting Directive, and require disclosure of payments made to all governments in respect of extraction activities.

The Regulations apply to the first accounting period commencing on or after 1st January 2015 and cover the payments made within each period. The first report will be required to be filed within 11 months of the period end.

However for those companies which are members of a group for which consolidated accounts are prepared in another EU state there is delayed implementation; their first reporting is made in respect of the first accounting period commencing on or after 1st January 2016.


Oil and gas companies are well aware of the high profile of their activities. The increased transparency sought by authorities and civil society is now being taken forward in a number of separate initiatives and companies need to be prepared for the impact of these.

 For most UK oil and gas companies the first to have an impact will be UK EITI. The UK government has committed to the EITI to set an example and demonstrate its accountability. The UK EITI programme has the support of many industry players and organisations, and relies upon the companies to voluntarily provide certain information, waive taxpayer confidentiality, and potentially assist the independent administrator to reconcile amounts.

Nevertheless, companies should be aware that responding to requests for information, assisting HMRC in identifying ring fence CT and waiving confidentiality are all voluntary. As preparation for what is required under the new Regulations enforcing the EU Directive there may be some benefit to responding positively to the UK EITI, but when resources are stretched companies should not feel compelled to assist when there is no obligation on them to do so. The EU Directive reporting is however compulsory with most companies having to file their first report on or before 30 November 2016.

CW Energy LLP February 2015

15 Jan 2015

January 2015 Newsletter – Diverted Profits Tax


We did not mention in our Autumn Statement newsletter the proposed new diverted profits tax (or so-called Google tax) as, from the summary description, it did not seem likely that it would apply to upstream oil and gas companies.

Having reviewed the detailed provisions it is clear that the proposed legislation is widely drawn and  potentially relevant for many international oil and gas groups where there are arrangements under which profits can be seen as diverted from the UK tax net.

The new 25% diverted profits tax will apply in two different types of situation

  • first where arrangements are made such that a non UK resident company selling goods or services to UK customers with the assistance of persons in the UK does not have a taxable permanent establishment (PE) in the UK, the “avoided PE” rule;
  • second where a UK resident company, or a UK permanent establishment transacts with an affiliate in circumstances which generate a reduction in taxable income for the UK tax payer, where the arrangement involves entities or transactions which lack “economic substance”.

The avoided PE rule does not apply unless group sales to UK customers exceed £10m in the 12 month period.

In addition neither rule will apply if the group is a medium or small group (broadly less than 250 employees and turnover less than approximately £39m or the balance sheet is less than approximately £33m).

2. Avoided PE

For the “avoided PE” rule to apply there must be activities carried on in the UK in connection with sales of goods or services by a non-resident company to UK customers where it is reasonable to assume that the activity is designed to avoid the creation of a UK PE. The UK for these purposes would not include the UKCS, so if there is no one in the UK carrying on activities on behalf of the non-resident company then the avoided PE rule is not likely to be in point for most UKCS activities. Of course where activities are carried on in the UKCS the special rules which extend the scope of the UK and deem companies carrying on such activities to have a PE are likely to be relevant to bring the non UK resident within the charge to UK tax.

In the “avoided PE” case there are two situations where the rule can apply; where either the avoidance condition, or the mismatch condition is met.

2.1          The avoidance condition

This is where it is reasonable to assume that arrangements are in place in respect of which one of the main purposes is the avoidance of corporation tax.

2.2          The mismatch condition

Even if it is not reasonable to assume that the arrangements had a main purpose of tax avoidance the avoided PE rule will nevertheless be in point if there is a “mismatch”.

The mismatch condition arises where there are arrangements between the foreign company and any of its affiliates (wherever resident) which have the effect of reducing the taxable profits of the foreign company which might have been attributable to the avoided PE had a PE existed, and where there is both a “an effective tax mismatch” and the lack of economic substance condition is met. A mismatch will not exist however if the only provision between the connected parties in question is a loan relationship.

An effective tax mismatch occurs where the tax payable (ignoring losses) by the affiliate on the increase in its profits is less than 80% of the reduction of the foreign company’s taxable profits multiplied by its tax rate.


Lack of economic substance condition.

There are broadly two circumstances where there will be insufficient economic substance.

First, where the non-tax financial benefits referable to the transaction or transactions, taken as a whole, between the two parties, are less than the tax benefits. It is hard to see how there can ever be any non-tax financial benefit to the two parties taken as a whole, and this will need further clarification.

Second, where the contribution of the staff of one of the parties to such a transaction is less than the benefit of the tax reduction. It is not however clear how the value of such contribution will be measured.

However, both of the above tests only apply if it is reasonable to assume that the transaction(s) or the staff’s involvement was designed to secure a tax deduction.


The involvement of entities or transactions lacking economic substance rules therefore  potentially apply to  a wide number of arrangements such as leasing, captive insurance and the provision of intellectual property. It is less likely that the rules would apply to service provision given that existing transfer pricing rules should mean that the lack of economic substance test would unlikely to be met. 

An example of the type of arrangement which could potentially be caught would be where the non-resident was supplying technical services to UK customers and in order to enable it to provide these services it was leasing equipment from an affiliate lessor in a low tax jurisdiction.

2.4 Calculation of diverted profits in the avoided PE case

2.4.1      In the avoidance case “taxable diverted profits” are essentially the amount equal to the profits which it is just and reasonable to assume would have been the UK taxable profits of the non UK entity had that entity had a PE in the UK through which it carried on a trade.

2.4.2      Where the avoided PE rules applies because of the mismatch rule, the diverted profit calculation for the non-resident requires the mismatch transaction to be replaced with an alternative transaction which it is reasonable to assume would have been entered into without the tax mismatch (and would not have generated a tax mismatch).

3. Involvement of entities or transactions lacking economic substance

In contrast to the avoided PE rule, which is concerned with non-resident companies trying to avoid a UK taxable presence, these rules are directly concerned with excess deductions being taken, or reduced income being recognised, for UK tax payers as a result of connected party transactions. In this sense this rule is looking to supplement the existing transfer pricing rules.

These rules apply where provision has been made or imposed between a company that is UK resident (or a UK PE) and another person by means of a transaction or series of transactions; the two entities are connected; and the provision results in both “an effective tax mismatch outcome” between the two entities, and the “insufficient economic substance condition” also being met in respect of the arrangement. These tests are essentially the same as apply in the avoided PE case.

3.1 How the diverted profits tax is calculated

In the “insufficient economic substance case”, the basic rule is that the taxable diverted profits are the amount would have been the chargeable profits of the UK taxpayer had it entered into a provision which had simply been based on arm’s length principles.

However, the calculation of the diverted profits is modified if it is reasonable to assume that the material provision would not have been entered into absent the tax mismatch. In this case one is required to identify an alternative provision which would not have had a tax mismatch outcome.


In the case of a captive insurance company, provided that the insurance is priced at arm’s length, and complies with transfer pricing rules, and provided the insurance would not otherwise have been obtained from a UK resident, the rules as drafted should not impose an additional charge. If however HMRC believe that a transfer pricing adjustment is in point, these rules can impose a charge to tax on that adjustment, and provide for the tax to be payable far earlier than would typically be the case in the normal course of a transfer pricing enquiry.

4. Procedure

A company must notify HMRC if there is a possibility it might be within the rules, within the rules within 3 months of the end of the relevant accounting period. For the avoided PE case the fact that UK sales exceed the threshold and there is no actual PE triggers the requirement and in the lack of economic substance case if the tax reduction is significant relative to any other financial benefit of the arrangements. Where HMRC then determine that there is a liability a preliminary notice will be issued explaining HMRCs views. There is then a period of 30 days for the company to make representations. HMRC then issue a charging notice or confirmation that no charge arises. Tax is then due within 30 days of the notice regardless of whether the taxpayer appeals.


Oil companies which are selling crude and product to UK customers will need to review their arrangements to ensure that they cannot be caught by the avoided PE rule. There is an exemption if such companies are selling into the UK through an agent of independent status or where the level of UK sales by group companies is less than £10m per annum.  We are aware of a number of groups with oil and gas traders in the UK who are selling on behalf of non UK entities but who have reached agreement with HMRC that no profit need to be attributed to the PE (as the UK affiliate earns a sufficient level of profit) and it is thought that given the acceptance that a PE exists such activities should not fall within the avoided PE rules. Taxpayers may however want to review their arrangements and seek HMRC agreement on this.

Of perhaps more concern is the “transactions lacking commercial substance rules” under which companies taxable in the UK make payments to affiliates in lower tax jurisdictions. We believe that it is clear for these purposes that SCT is not to be factored into the tax mismatch test as this is not corporation tax. However given the rate of ring fence CT is 30% ring fence companies may be particularly vulnerable to a challenge under these rules.  For these purposes any payments deductible within the ring fence would potentially be caught if paid to an affiliate in jurisdiction where the rate is less than 24%. For payments deductible outside the ring fence, the cut off rate is 16%.

Any payment to affiliates in such low tax jurisdiction would seem to be potentially caught unless it can be said that the arrangement was not designed to secure a tax advantage. In this case one would have to assess the level, if any, of diverted profits, to see if a UK charge were to apply.

Examples of transactions that might be open to challenge are payments to captive insurance companies, affiliate leasing arrangements, and payments to traders or other service providers established in low tax jurisdictions. Note that transactions which “only” give rise to loan relationships are excluded from both heads of charge.

These provisions are complex and while designed to catch certain arrangements identified by Government as abusive, appear to have potentially wider and perhaps unintended application. If introduced as drafted the compliance burden is likely to be significant for many international groups. It is also unclear how these rules fit in with UK double taxation treaties and EU law. Given that we are faced with a very short period of time between Budget Day, March 18th, and the dissolution of Parliament there will need to be cross party support for these provisions to be included in the first 2015 Finance Act. Early indications are that this does exist but this does not mean that there is agreement that the measure should be pushed through in the next Finance Act. There must still be a chance that these provisions will be dropped, or substantially modified, particularly if genuine concerns are raised about their application. However companies should review their potential impact now as, if not introduced in the first Finance Act in 2015, they may reappear at a later date with possibly the same effective date of April 1 2015.

CW Energy LLP

January 2015

05 Dec 2014

Autumn Statement 2014 – Oil and Gas tax measures

Following the announcement of immediate changes to the regime in the Autumn statement, the Government announced today the results of the fiscal review discussions and their proposals to make changes to the regime designed “to support the government’s twin objectives of maximising the economic recovery of hydrocarbon resources whilst ensuring a fair return on those resources for the nation”.

There were nearly 60 respondents to the call for evidence and the Government have summarised those responses in their paper published today called “Driving investment: a plan to reform the oil and gas fiscal regime” in which they also set out a number of further proposals to take forward next year.

The aim of these proposals is summarised by Treasury as committing the Government to:

  • Introduce a basin-wide ‘Investment Allowance’ to reduce the effective tax rate further for those companies investing in the future of the UKCS. A consultation on this proposal will be published in early 2015.
  • Introduce financial support for seismic surveys in under-explored areas of the UKCS, working with industry on options for shared funding models. Stakeholders will be engaged to discuss this and details will be set out at Budget 2015.
  • Work on options for supporting exploration through the tax system, such as a tax credit or similar mechanism, in a way that is carefully targeted and affordable. The government will open discussions with industry and the new Oil and Gas Authority in 2015, with further consultation with industry.
  • Develop options to improve access to decommissioning tax relief and work with the Oil and Gas Authority to consider options for reforming the fiscal treatment of infrastructure, with further consultation with industry in 2015.

So despite the current low oil prices there are no plans to make any immediate radical changes to the existing regime which remains in place subject to yesterday’s proposed changes.

We will need to wait until we see the detailed consultation documents but our initial thoughts are as follows.

As a general comment, while the proposals are referred to by Treasury as a radical plan to reward investment, we see them more as tinkering at the edges, and are not convinced that they are sufficiently radical to achieve the objectives set out by Government.

The drastic rise in the SCT rate from 20% to 32% in 2011 was a political move to raise much needed cash whilst limiting increases in fuel duty and a reaction to the rise in oil price from around $70 per barrel to over $100. However in the current proposals there appears to be no commitment to link the rate of SCT to profitability and the 2% reduction announced yesterday leaves the industry in a world which is significantly less attractive than where it was at the time of the 2011 changes.

However along with the token 2% cut in the rate of the Supplementary Charge there is a commitment to reduce the rate of Supplementary Charge “over time” when affordable. Of course one of the consequences of a cut in SCT rates (as opposed to a cut in the rate of ring fence CT) is that it dilutes the value of the field allowances, and will not help current developments which are sheltered from SCT by field allowances.

Although the Government acknowledges that the scheme of field allowances introduced in 2009 has been successful in its aim of promoting investment, they have highlighted the complexity, uncertainty and distortions that the current regime has introduced and are therefore proposing a move to a more straightforward “Basin Wide” investment allowance.

A basin wide investment allowance, while welcome, does not appear particularly well targeted to investments more in need of assistance, meaning that in a resource constrained environment there is less help available for where it is most needed. It would however generate much needed certainty about the tax reliefs that will be available (subject to future changes in law) when an investment decision is first made.

The proposed targeted relief for seismic surveying is likely to assist smaller players and is an area where the cost to Government in providing some upfront relief may be more manageable in the current economic climate.

As there are existing mechanisms for enhanced tax relief for North Sea costs, providing an exploration tax credit presumably would mean some form of cash refund for companies in the exploration phase. This would be a welcome measure for companies which are currently not tax paying. However the relief is going to be highly targeted and clearly not going to be generally available. Until we have a better view of the targets it is difficult to know whether this will have the significant impact needed to improve levels of exploration.

Similarly, given the already extensive CT loss relief rules for decommissioning, the commitment to improve access to decommissioning tax relief is interesting. We presume the Government are thinking of a PRT-style loss carry back to previous owners who might have more CT capacity than the existing owners, to help encourage new entrants. How this would work in practice could however be problematical as previous owners who have retained significant North Sea interests may wish to retain access to all or part of their past capacity. However it is a positive step that Government have recognised that the lack of tax capacity is a real concern and a continuing impediment to assets being transferred.

Reforming the fiscal treatment of infrastructure is long overdue and the case for reform cannot be more pressing giving ageing infrastructure with high running costs given the current low oil prices

With regards to PRT Government have acknowledged that most respondents who commented on this issue suggested a move towards a 0% rate of PRT was desirable. However they have concluded that this would not be the most efficient use of resources. They have nevertheless given an undertaking to keep the rates of PRT “under review”.

We feel it is unlikely that there will be any significant changes to the PRT regime in the near future except possibly in respect of infrastructure taxation as mentioned above, given that the major part of this infrastructure is currently within the scope of PRT. While some changes are clearly needed to the PRT regime as it applies to infrastructure we believe that there are better, targeted ways of achieving this rather than across the board rate reductions.

Hopefully more radical changes will result from the discussions planned for 2015. For the moment however it seems a case of “jam tomorrow”.

What is clear from this announcement, and has been evident in previous reviews (of which there have been many), is that there are a large number of diverse interests in the industry influenced by each company’s particular portfolio. This means that it has been difficult for the industry to speak with a single voice, and no doubt this will continue, with those who are able to shout the loudest perhaps having the greatest success in bringing about change.

It is however hoped that Treasury will be able to see through this and introduce a regime that will give the best result for the industry as a whole. We can only wait and see.

03 Dec 2014

2014 Autumn Statement

In today’s Autumn Statement the Chancellor acknowledged the need for the tax system to offer some help to the oil and gas industry, which is seen as a very important industry for the economy as a whole. He announced a number of changes, and noted that further proposals would be announced by the Chief Secretary to the Treasury, Danny Alexander, tomorrow.

The specific changes announced today; the reduction in supplementary charge, the extension of RFES, and the introduction of a cluster allowance, all of which are dealt with in more detail below, are to be introduced in the spring 2015 Finance Bill, and we would expect them to be enacted prior to the General Election in May, as there is understood to be cross party support for the measures.

While we will have to wait and see what is announced tomorrow, it is expected that there will be a further round of consultations on a number of specific issues that have been identified in the general call for evidence consultation that has taken place this year with a view, presumably, to including such changes in the second Finance Bill of 2015 anticipated at the end of summer / early Autumn following the General Election.

In addition to the above measures mentioned in the Chancellor’s speech a number of other changes are also being introduced now (see “Other Changes” below).

Reduction in Supplementary Charge (SC) rate

The rate of SC is to be reduced from 32% to 30% with effect for profits generated after January 1 2015. Treasury has stated that the aim is to encourage additional investment and drive higher production, and that they aim to reduce the rate further in due course as when the Government can afford to do so.


It is not thought, given the limited number of companies actually paying SC, that this change is likely to cost Government much (the Government estimate is £55m for next year), and can be seen as more of a token gesture of sympathy to the oil industry at a difficult economic time. It is unlikely to have much impact on investment initially as the rate reduction is not much more than 3% of the prior 62% rate, the reduction has a corresponding impact on the value of field allowances, with for many companies the benefit being long into the future. It does however indicate that the Government acknowledges that change is needed. It must be hoped that real lasting effective changes will come out of whatever further consultation takes place next year.

It will not be possible to take account of the drop in rate in calculating deferred taxes until the change has been substantially enacted, which is not likely to be until next spring, although if the effect of the reduction is expected to be material then a company should disclose its impact in its next set of results. 


Ring Fence Expenditure Supplement extension

After a number of years of lobbying the Government have agreed to increase the maximum number of periods for which Ring Fence Expenditure Supplement claims are available from 6 to 10.

However claims 7 to 10 will only be available in respect of losses and pre trading expenditure incurred after 5 December 2013, together with supplement thereon.

We will have to await the draft legislation next week to determine the exact mechanics of this change but, based on the wording of the announcements to date, it seems likely that one will have to maintain two “parallel”  RFES pools, a total pool (which can generate 6 periods of claim)  and a post 5 December 2013 pool. Any post 5 December 2013 loss will need to be included in both. Both pools would be uplifted for each period when a claim was being made on the first pool but the second pool would remain “dormant” until the first pool had generated 6 periods of claim. Once 6 periods of claim had been made the amount of losses in the first pool would become irrelevant and only those losses in the second pool would be eligible for RFES. There presumably will be specific provisions dealing with the offset of profits or unrelieved group ring fence profits, which we would expect to work in the most favourable way such that profits would be set against the first pool to the extent possible and only an excess profit set against the second.


This measure is targeted at providing relief for new expenditures rather than existing losses which seems sensible, although perhaps less generous than hoped for by companies with existing losses. Groups which moved into loss for the first time after 2013 will benefit most from these changes whereas groups which have already made RFES claims (perhaps in modest amounts) will not benefit to the same extent. An alternative methodology where each year’s spend can be uplifted would have more merit but it seems that this approach has been rejected, not least we understand because of its perceived computational complexity. However this new proposal would seem to have many of the same computational complexities.

It is of course possible for groups which are still in an overall loss position and have used their 6 periods to obtain additional periods of RFES on new spend by arranging for that spend to be incurred by a new entity. There are issues with this type of planning and this new measure will therefore ensure, at least for the next few years, that such planning does not need to be considered. 

Now that it is clear that the additional claims will not apply to pre December 5 2013 losses companies will need to carefully review their position and projections before the end of the year to determine whether claims already made should be withdrawn.

It appears that there is to be no extension to the time limit to of two years in which claims can be withdrawn (in most cases) which is unhelpful.

It is unclear why the measure is backdated to 5 December 2013 (the date of the 2013 Autumn Statement) but perhaps this is simply to align the change with the onshore allowance which was introduced from that date. The use 5 of December will, however introduce a degree of computational complexity which is unwelcome.

The Treasury estimate that the cost of these measures will be £20 million over the next 6 years with no cost until 2016/17. This seems to be a very conservative estimate of the benefit, although perhaps reflects the period over which these losses will arise.

New Cluster Allowance

Cluster Allowance

After extensive consultation and discussions the final form of the cluster allowance has now been decided. It will be given at the rate suggested in the consultation process, i.e. 62.5% of qualifying relievable capital costs in a cluster. The percentage can be altered by regulations. “Relievable” means that the expenditure is incurred for oil-related activities, namely oil extraction activities as defined in s274 CTA 2010, or activities consisting of the acquisition, enjoyment or exploitation of oil rights. The rules will broadly follow those adopted for the onshore “shale” allowance introduced last year.


Unlike the onshore allowance the rate of allowance which has been set was not increased from the indicative rate given in the consultation document which could be disappointing for some companies.

There is no specific definition of capital so it is considered that the normal case law precedents apply. This has been an area of contention for the additionally developed (“brown field”) allowance but is perhaps less likely to be an issue here where the costs concerned will initially primarily be exploration and development costs which will typically all be capital.

Qualifying costs are those in respect of capital expenditure incurred in relation to a cluster area on or after 3rd December 2014. Once an area has been determined as a cluster area all subsequent qualifying capex will qualify for the allowance.

The cluster area allowance is generated when the costs are incurred by the company incurring those costs in the cluster concerned.

A “cluster area” is defined to mean an offshore area which DECC determines to be a cluster area. The determination process is similar to that for existing field determinations, giving affected licensees the right to make representations on any proposed determination.

A cluster area will not include any previously authorised oil field unless this has been decommissioned before the cluster is determined.

Companies will have an option before a cut-off date (yet to be specified but suggested in the consultation process to be 1st January 2017) to exclude a field from the cluster determination if another allowance would be more beneficial.


The criteria which will determine what is a cluster e.g. whether there is an HPHT or uHPHT prospect in the area, are not set out in the legislation but presumably will be specified in secondary legislation. The Treasury have suggested that these will be set at pressure more than 690 bar and temperature more than 149° Celsius, lower limits than those originally proposed.

We assume that the absence of a requirement for an HPHT field in the legislation is that this can be used as a more general allowance and that other types of areas will ultimately be capable of being determined as a cluster.

There seems to be an element of subjectivity in the determination of a cluster area as this can only be determined by DECC. The taxpayer is allowed to make representations but unless the criteria for establishing a cluster are made more specific it is difficult to see on what grounds any objection could be made.

The cluster allowance activated in any period is the smaller of the closing balance of unactivated allowance at the end of the period and the company’s relevant income from that cluster for that period. As with other field allowances the activated allowance is deductible from the company’s profits subject to the supplementary charge.


The Treasury have listened to a number of the representations that were made through the consultation period: for example there no longer needs to be commercial alignment between all of the participants in the cluster; if one participant in the cluster fails to meet its obligations it will not have a detrimental effect on the other participants; and there will be no loss of allowance if the HPHT prospect fails to meet the relevant requirements. There is however still no possibility of relief if there is never any income generated from the cluster.

A reimbursement of costs on the acquisition of a licence does not qualify if any part of the original cost qualified for a cluster allowance to the seller.

There are detailed rules which apply to determine the level of allowances in periods where there are transfers of interests and in particular there is a requirement for part of the allowance to be transferred with a cluster licence. The transferor can elect specify the amount to be transferred within a minimum and maximum range. If no election is made the minimum amount will automatically transfer.

Other Changes

In addition to the items mentioned in the Chancellor’s speech the following changes were also announced.

  • Abolition of the Fair Fuel Stabiliser price based trigger point for both the supplementary charge and fuel duty.
  • Provision of funding for the Oil and Gas Authority to ensure that it will have the resources it needs to carry out its function effectively.
  • Establishment of a new £5 million fund to provide independent evidence directly to the general public about the robustness of the shale regulatory regime, and ensure that the public is better engaged in the regulatory process.
  • Allocation of £31m for a system of subsurface research test centres, to establish world leading knowledge applicable to a number of energy technologies including shale and carbon capture and storage.
  • A commitment to bringing forward proposals for a shale long-term investment fund, in the next Parliament.


The Fair Fuel Stabiliser was generally thought not fit for purpose, being fixed in sterling rather than dollars, and being based on price rather than profit.

The other measures are not directly fiscal but are to be welcomed as they seek to address some of the previously identified issues particularly around the difficulty of progressing shale gas exploration.

Non “Oily” matters

There is a proposal to limit the level of banking profits that can be sheltered by brought forward losses.


There are many companies in the oil and gas sector that are carrying forward significant levels of losses but this measure seems specifically directed at the banking sector as a result of them having been “bailed out” by the UK Government, and it is not thought that such a restriction is ever likely to be imposed on the oil and gas sector which by its long term nature is always likely to go through periods of loss making particularly as a result of major developments in difficult locations.

The rate of the above the line R&D credits is to be increased from 10% to 11% with effect from April 1 2015.


There doesn’t appear to be any proposal to change the rate applicable to ring fence profits. The benefit of this relief has always to a certain extent been limited in the oil & gas sector due to the propensity to capitalise most R&D type costs. However this increase should be of some benefit to the industry, albeit HMRC recently rather disappointingly notified the industry that they were not proposing to do anything about the instalment payment cash flow disadvantage that arises for ring fence companies if a credit rather than an enhanced deduction is taken.