Scotland's Independent Expert Commission on Oil and Gas: report

The maximising the total value added report includes recommendations designed to facilitate long term stability and predictability for the industry.

4. The Fiscal Regime

Key messages:

  • Fiscal policy making has been influenced by the short-term impact on production tax revenues, causing substantial uncertainty with negative effects on investment.
  • Stability and predictability must be central to the fiscal regime in the UKCS.
  • The optimal fiscal regime should reflect the current and future context of the basin. There is a need to re-assess the combination of tax rates and allowances which will fulfil these requirements.
  • The tax system needs to strike an appropriate balance between incentivising development, maximising returns to the nation and ensuring that an appropriate share of economic rents are collected by the Government. These objectives are not mutually exclusive. A tax system which maximises returns to the nation is entirely compatible with ensuring an appropriate stake for Government.
  • Allowances should be predictable at the stage of evaluation and based on economic rather than physical factors.


1. The widely-accepted purpose of the UKCS taxation system is to collect a fair share of the economic rents from oil and gas exploitation to the state on behalf of the nation. The effective operation of this concept should also result in a fiscal regime which provides incentives to:

  • explore and appraise discoveries;
  • develop new fields and incremental/ EOR projects'; and
  • produce oil and gas until such a time as it becomes uneconomic, before tax, to do so.

2. The oil and gas sector exhibits characteristics that require special consideration in terms of economic policy and taxation. These characteristics include:

  • revenue streams which are inherently uncertain and are secured over the long-term;
  • significant up-front and decommissioning costs; and
  • a range of technical and financial risks.

The efficient collection of economic rents in practice has to reflect these complexities.

3. Translating this into a practical tax system has proved to be a fraught subject over many years, resulting in the current system in the UKCS which, as detailed in Chapter 2, is now very complex in its operation and has been subject to frequent changes. This is largely due to the ad-hoc nature of its development in response to specific short-term issues.

The case for change

4. The changing underlying features of the investment environment, need to be considered in determining the design of an efficient tax system which is sustainable for the future. The regime requires to be adapted to reflect the changing features of the investment environment domestically and to ensure the UKCS remains internationally competitive as a basin to investors appraising opportunities globally.

5. An efficient system should not inhibit investments which are economic before tax, neither should it subsidise projects which are uneconomic before tax. As highlighted in the Wood Review, an efficient fiscal system should also have flexibility to adapt and encourage investments across the diverse range of UKCS opportunities, including; frontier areas, new plays, technically challenging areas and mature oil and gas.

6. The regime should aim to be non-distortionary, sustainable over the longer term, and it should operate with minimum compliance costs on companies - either through its complexity or reporting requirements. The Commission recommends that these objectives must be central to the UKCS policy approach and fiscal regime.

7. It is very clear to the Commission that stability and predictability must be central to the fiscal regime in the UKCS. In a maturing environment, where prospectivity is lower and accumulations are likely to be smaller, it is increasingly important to manage the balance between risk and reward for the industry and for Government.

8. Oil and Gas companies prefer to invest in stable, predictable regimes, especially in large opportunities. Where the UKCS cannot promise the large opportunities it once could, it must be able to offer a stable and predictable regime - and one which recognises its place in the global market.

9. Government should recognise that oil and gas investment decisions and their consequences are particularly long-term in nature. The fiscal regime should therefore reflect the appropriate time periods for the industry which typically extend well beyond Government budget periods.

10. It is recommended that Government considers how it might provide assurances to industry that a commitment to fiscal stability and predictability will be fully honoured and will reflect a full understanding of the unique investment environment of the oil and gas sector.

Recommendation 1: Government should seek to ensure international competitiveness, stability and predictability that is appropriate to the maturing environment of the UKCS and the competing investment environment globally.

TVA within the broader fiscal and policy framework

11. There must be a clear recognition of TVA within the broader fiscal framework.

12. It has been recommended that informative data sets should be developed by Government to improve decision making, this will assist with the assessment of proposed changes to the fiscal regime. The Commission advocates embedding a greater understanding and knowledge across all arms of Government of the likely impact upon TVA of any proposed changes.

13. To this end the Commission has recommended that the new Regulator should have a formal right of consultation on fiscal or regulatory issues which could have an impact on investment or production in the UKCS.

14. It is within this context that the Commission has recommended that licence terms should be investigated as a means of ensuring greater certainty for operators investing in the UKCS. For example, through incorporating a commitment to meaningful consultation with the Regulator and industry on regulatory or fiscal changes and through formally placing MER and TVA as central to those considerations [34] .

A positive investment sentiment

15. The sentiment attached to the UKCS approach to fiscal policy has not always been positive. Over the past decade, the UK Government has made numerous substantive changes to the UKCS fiscal regime, resulting in instability which damaged investor confidence at the time.

16. The creation of this new positive sentiment from Government - which is discussed in greater detail in Chapter 5 - should be reinforced through the actions of Government. This will help to create a fiscal framework which is stable, predictable, competitive internationally and flexible in responding to market forces for long-term investment and value generation.

Recommendation 2: The fiscal regime and policy approach should serve the purpose of creating and reinforcing the positive investment sentiment; any changes to the fiscal regime should be credible for long-term, and set in light of achieving maximum TVA.

Simplification and targeted incentives

17. The UKCS fiscal regime is central to the long-term sustainability of the sector. The following section highlights a number of issues where improvements could deliver substantial benefits for producers, investors and government.

18. The specific impact of each measure has not yet been modelled, however the measures proposed are likely to have a positive impact on investment, exploration activity and production all of which are central to extending the longevity of the sector and benefit the public finances in the longer term. For example, an investment cost-based allowance for Supplementary Charge as recommended below has the potential to increase long term activity and tax revenues compared to the existing field allowances.

  • New Field Developments

19. New field developments are currently subject to Corporation Tax ( CT) at 30% and Supplementary Charge ( SC) at 32% with allowances for costs all being available on 100% first year basis. In addition there is a plethora of field allowances against the SC based on the physical characteristics of the fields.

20. These allowances are designed to help fields which are relatively high in cost (per boe). The physical features are essentially proxies for costs. However, by their nature they do not accurately and sufficiently reflect the actual costs being incurred.

21. Costs may be relatively high for a multiplicity of reasons. If the physical criteria do not qualify then the allowance available could be too low to produce the desired incentive - to render projects which are economic before tax, commercial on a post-tax basis. The allowance could also be unnecessarily large.

22. Under the current system investors will often not know whether they will be entitled to a field allowance or not when appraising discoveries. In practice, eligibility for a field allowance has become akin to on-going negotiations between investors and the UK Government and it therefore lacks transparency and predictability.

23. In Budget 2014 a new allowance against the SC for Uhp/ HT fields was proposed, based on capital expenditure. It is proposed that the allowance will represent a proportion of capital expenditure incurred, with 62.5% suggested as a minimum rate. There is considerable merit in this approach.

24. This would base the allowance on a key economic feature of the project, targeting an area which requires increased investment. Crucially, the details of the scheme would be known well in advance of any investment decision; enhancing the transparency and predictability of the tax treatment.

25. It is proposed that that this new allowance will also apply to exploration expenditure within the vicinity of a discovery. This should incentivise exploration and potentially encourage cluster developments. This allowance also brings with it the benefits of automatically accommodating cost inflation. This is an issue which is currently so prevalent in the UKCS that it has already arrested the development of some new fields.

A cost-based allowance

26. The Commission therefore recommends that the current system of new field allowances be replaced by a single allowance based on field investment costs.

27. The allowance must apply to all types of fields, not just to Ultra High Pressure / High Temperature ( Uhp/HT) ones, to include tight gas fields for example, where costs are very high. There will be transitional issues with respect to the existing allowances and care would be required to ensure that the new allowance did not result in less relief than is now available for current new investments. Grandfathering arrangements can prevent this through a staged introduction of the new allowance.

28. As with the current Brownfield Allowance ( BFA) a cap on the size of this cost based allowance would be needed to prevent outright subsidies and a lack of cost consciousness. The allowance could simply be based on investment costs (as has been proposed for the new Uhp/HT allowance) or it could be based on investment per boe of resources. The respective merits of these two approaches should be tested.

29. This proposal would substantially increase the transparency of the fiscal regime for investors and therefore contribute towards a more predictable regime, which is flexible enough to adapt to a changing commercial environment.

Supplementary Charge

30. The detailed redesign of the system of field allowances, away from the current plethora based on physical characteristics to one based on costs, should be seen in the context of the rate of SC as well. Allowances against corporate tax and/or SC rate reductions would each act to incentivise investment.

31. A lower tax rate would involve a reduced rate of relief for expenditures as well as a lower rate payable on income. The Commission recognises that a lower rate of SC can involve a 'deadweight loss' of tax revenues. This should be seen against the extra exploration, field development, production efficiency and EOR activities generated by the rate change. Any rate reduction could be accompanied by a reduction in the size of the field allowances.

32. In current circumstances the Commission recommends that the comparative merits of a rate reduction along with downward adjustments to the system of field allowances be considered afresh. This would allow Government to reassess the appropriate balance between headline rates and the nature and size of the field allowances and the aggregate effect on the nation's public finances.

33. While policies to enhance production efficiency are primarily a matter for regulation a reduced tax rate could provide further incentives to operators to invest by increasing the return from the necessary expenditures.

  • Oil/Gas Treatment

34. There is a need for larger allowances for predominantly gas fields to compensate for lower expected revenues.

35. Gas prices have been in the range of 50%-60% of oil prices in recent years. However, the cost per boe of developing a gas field is similar to the cost of developing an oil field. An allowance for gas fields should still be based on investment costs as opposed to the physical characteristics of a field. This could equitably deal with the fact that gas fields in the SNS cost less to develop than gas fields in the CNS, NNS and WofS. In the latter regions the value of the allowance could be greater in order to reflect this reality - consideration would be required as to how this would interact with proposals to move to a streamlined cost based allowance system.

  • Incremental Investments/ EOR

Operating costs

36. Consideration should be given to the Brown Field Allowance ( BFA) applying to operating costs as well as investment costs for incremental investments.

37. The current BFA provides an allowance against the SC based on investment costs per boe of incremental oil/gas resources, with a ceiling. This means that only incremental capital costs, excluding decommissioning spend and sunk costs, are included in the calculation of what costs are eligible.

38. The allowance is larger for PRT-paying fields to compensate for the extra tax payable in relation to those. However, some EOR projects have large operating costs. An example is polymer flood where the purchase of expensive polymers can continue for several years. CO2 EOR schemes may also involve substantial additional operating costs, depending, for example, on the transfer price of CO2.

39. The estimation of operating costs for this purpose would involve definitional and practical hurdles in its implementation. However, the ability to utilise independent verification should help to overcome these difficulties.

40. If the proposed cost-based field allowance were introduced more widely it is possible that it could be adapted to replace the Brownfield Allowance as well. The issue of large operating costs in some EOR projects would then need attention. It is recommended that consideration be given to the possible application of the cost-based field allowance to incremental/ EOR projects. This could be simpler but as efficient as the present Brownfield Allowance.


41. Currently the headline rate of tax in PRT-paying fields is 81%. In order to achieve maximum economic recovery from these mature fields it is important that investments in incremental projects or asset transfer to companies specialising in the extensions of the lives of these fields are not discouraged. In some cases, a tax rate of 81% may inhibit these activities

42. It is also necessary to incentivise EOR projects, such as CO2 EOR, which require substantial investment. There is an inconsistency in the tax treatment of incremental/ EOR projects in PRT-paying fields compared to non PRT-paying fields which deserves remedial attention. Currently the difference in tax is substantial.

43. There is therefore a case for a reduction in the PRT rate from its current 50% level to encourage investors to examine Improved Oil Recovery ( IOR) / EOR schemes while still providing relief to the operator for decommissioning of the relevant infrastructure further down the line. This would reduce the reliance on the BFA for such investments.

44. A reduction in the PRT headline rate would also increase the return to expenditures on enhancing production efficiency. Increased investment in the development of mature fields, production efficiency and EOR (alongside a reduced reliance on BFA for PRT fields) would minimise the deadweight loss and maximise the return from PRT fields. The potential for increased production levels and delayed abandonment will generate benefits for the industry and for the nation.

  • Exploration

45. The current Ring Fence Expenditure Supplement ( RFES) allowance for exploration offshore should be able to be carried forward for a greater number of accounting periods.

46. For investors in a taxpaying position relief at 62% is currently available for exploration expenditure, with all allowances set at 100% of capital costs on a first-year basis. The recent increase in the Small Field Allowance has improved the expected full cycle return for companies that are in a taxpaying position and undertake successful exploration activity.

47. However, for investors not in a tax-paying position exploration, appraisal and development losses can currently be carried forward at 10% interest for 6 accounting periods. This is typically not a very long period in light of the long term nature of oil and gas investments and projects. The main development expenditure can often (at least in part) be undertaken after this 6-year period has expired.

48. For onshore activities a 10-year accounting period is now permitted, and, after 3 years the allowance can be utilised elsewhere. It is arguable that there should be no limitation to the carry forward period for offshore exploration to reflect the uncertainties and realities of the investment environment. However, an extension to at least 10 accounting periods would be very beneficial.

49. In light of the changing nature of investors in the UKCS, it is more and more common for exploration to be carried out by smaller, independent operators who are less likely to be in a tax paying position. This measure would therefore be likely to have a positive impact on investment and exploration activity through increasing the expected full cycle return for smaller or newer companies who are not in a tax-paying position - a return which is currently considerably less than that for full current tax paying investors.

50. Changing the basis of the new field allowance to one based on investment costs should also go some way to enhancing the investment clarity for explorers. However, consideration should also be given to extending the eligibility of the proposed capital investment allowance to include exploration more widely than only in the vicinity of a single discovery.

  • Transfers of licence interests

51. It is widely recognised that the tax system should not inhibit the transfer of licences to companies that want to take forward further development and generate additional value. Significant progress has been made in ameliorating capital gains tax on licence transfers, particularly where the seller continues to invest in the UKCS.

52. In 2009, reinvestment relief was introduced for trading companies making disposals of licences, giving an exemption for the capital gain arising on the disposal, provided the proceeds received are reinvested in specific UKCS activities. The scope of qualifying reinvestment activities was widened in 2010, and Budget 2014 announced that the relief will also become available to pre-trading companies when Finance Act 2014 is passed.

53. Together with the substantial shareholdings exemption, which is capable of exempting gains arising on the disposal of corporate entities providing certain conditions are met, the capital gains tax regime from 2014 is expected to offer appropriate reliefs that prevent artificial inhibition of licence transfers.

54. Budget 2014 introduced changes intended to limit the ability of a company to utilise certain tax reliefs after a change in its ownership (known as "loss-buying targeted anti-avoidance rules", or "loss-buying TAARs").

55. These changes had a disproportionate impact on oil and gas companies which were still in the 'pre-trading, exploration and appraisal' stage, by limiting their ability to set exploration and appraisal expenditure against profits accruing after any change in ownership. Again this has a disproportionate impact on smaller, independent companies which are increasing in number in the UKCS market.

56. It was anticipated that the loss-buying TAARs could inhibit exploration and appraisal activity, by denying the investor any opportunity to realise tax relief for unsuccessful exploration. Budget 2014 announced that exploration and appraisal expenditure would in future be excluded from the impact of the TAARs.

57. It is important that this announced change becomes law, in order to remove any unintended barrier to exploration activity.

  • Third Party Access to Infrastructure

58. Government should consider the impact that the Supplementary Charge on third party tariff income is having on third party access to infrastructure. .

59. Inefficient third party access to infrastructure has been a problem in the UKCS for many years. Such access is widely regarded as being essential to produce Maximum Economic Recovery. The UK Government has acquired powers to be more interventionist in setting terms and conditions, including tariff determination, but it is widely perceived that DECC has not used these powers very proactively.

60. The new Regulator should become much more proactive in this area and effective regulation is certainly the most important element in the solution to this problem. Taxation arrangements can only play a secondary role. However, it is arguable that, if tariffs are to reflect the costs of the third-party tariffing activity then, to encourage this, the applicable tax rate should not incorporate a surcharge above corporation tax (Supplementary Charge).

61. There is therefore a case for abolishing SC on third-party tariffing activity on the same grounds as PRT was abolished on new tariffing contracts in 2003. This could encourage asset owners to be more willing to provide the service as advocated in the Wood Review, and in turn to reduce the tariffs being charged to the third party.

62. The removal of SC from third party tariff incomes also requires consideration to be given to the relevant deductible costs. In principle, only the incremental costs from the tariffing activity should be disallowed for the purposes of calculating what is due under the SC. Effective regulation should ensure that the benefits of the tax reduction are passed on in lower tariffs.

63. In this context it is relevant to note that the provision of third party infrastructure services provided by licensees in the UKCS are currently subject to CT at 30%, while similar services provided by non-licensees would be taxed at 22% in 2014-15 and 20% from 2015-16 (albeit capital allowances for non-licensees are not as generous).

64. The difference in treatment has grown substantially in recent years, as ring fenced CT rates have remained at 30% while onshore CT rates have fallen considerably.

Recommendation 3: The simplification of the UKCS fiscal regime should be a key objective for Government. A number of specific and targeted improvements to the fiscal regime (outlined in this chapter) are recommended.


65. Chapter 2 demonstrated that there is a need to align the taxation system to the current and emerging environment. The high-level key recommendations outlined above are aimed at ensuring an appropriate broader fiscal framework in the long-term, consistent with the aims of MER and TVA.

66. The implementation of the specific, targeted, recommendations outlined in this Chapter would represent a move towards a regime which minimises distortions whilst ensuring that projects which are economic before tax remain commercially acceptable after tax.

67. These recommendations also seek to ensure that licensees contemplating long term investments can be confident that their tax liabilities will be relatively predictable. Central to this is a fiscal regime which incorporates appropriate flexibility to respond to a range of external factors, particularly oil and gas price fluctuations, non-uniform UKCS development opportunities, and cost changes.

68. Prior to implementing any of these measures it will be important for detailed analysis to be carried out to assess the impact each measure would be likely to have on investment in exploration, field development, production efficiency, EOR and tax revenue. As part of this Government should ensure that the design and implementation of these measures is consistent with the principles of MER and TVA.

69. Central to this assessment Government should consider the impact of each policy measure, including any potential deadweight losses, on the public finances. This will determine the most appropriate approach for implementing specific recommendations set out in this chapter ( i.e. a selected implementation, phased implementation or as part of a more fundamental reform to the tax regime).

Constitutional Change

70. In the event of a Yes vote, both Governments should adopt a collaborative approach with regards to the operation of the fiscal regime, with a view to maximising synergies, minimising costs and with a clear focus on providing clarity and certainty to the industry. This approach would be in the interests of both governments, industry and taxpayers.

71. Putting stability and predictability as central to the fiscal regime, the Commission has recommended that in the event of Yes vote in September's independence referendum, while basic policies may well differ between Scotland and the rest of the UK, as far as possible policy implementation should be coordinated.

72. Any changes to the regime, even when they are considered to be in the positive, should be properly consulted upon, and should be confirmed and implemented within a well-publicised timescale to enable the oil and gas industry to take full account of any such changes within their future business plans.


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