Call for Evidence
Review of the oil and gas fiscal regime: a
call for evidence
The Law Society of Scotland’s response
October 2014
© The Law Society of Scotland 2014
Introduction
The Law Society of Scotland aims to lead and support a successful and respected Scottish
legal profession. Not only do we act in the interests of our solicitor members but we also
have a clear responsibility to work in the public interest. That is why we actively engage and
seek to assist in the legislative and public policy decision making processes.
To help us do this, we use our various Society committees which are made up of solicitors
and non-solicitors and ensure we benefit from knowledge and expertise from both within
and out with the solicitor profession.
The Energy Law Sub-Committee, of the Law Society of Scotland, has had the opportunity
to consider the “Review of the oil and gas fiscal regime: call for evidence” and have the
following comments to put forward in response to the questions posed in the consultation
document.
Comments
Question 1: How do stakeholders expect economics of UKCS projects to evolve over
the
coming
decades,
including
new
and
incremental
investments?
Would
stakeholders expect to see greater variety in field economics than has been the case
in the past? How could evolution of the fiscal regime support the objective of
maximising economic recovery as the economics of the basin change?
The UKCS is a complex basin. Some areas are extremely mature and have been producing
for many years whilst other areas are frontier regions where little or no development has
occurred. As we understand, although there have been some large discoveries in recent
years these tend to be the exception rather than the rule. The average size of discoveries
has dropped significantly over the years with two thirds of new field discoveries being fields
with reserves of less than 50 million barrels of oil equivalent (boe) (Oil & Gas UK Activity
Survey 2014). Giving the decline in the average field size the basin as a whole is likely to
be less attractive to potential new entrants. Existing companies may well be considering
whether the cash being spent on the UKCS could yield better returns if invested elsewhere.
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In the context of existing mature fields we would presume that given the certainty which has
been provided in respect of tax relief for decommissioning costs (by the introduction of
Decommissioning Relief Deeds in 2013) companies are more likely to wish to extent field
life where commercially possible. Whether this will be commercially possible is a function of
a number of factor . One of these will be whether tax relief is available on costs of
incremental investment. Whilst the “brownfield allowance” provides welcome tax relief in
respect of certain spend an extension to its scope to include enhanced oil recovery using
carbon dioxide injection potentially could encourage investment and hence lead to an
extension of the life of fields, so supporting the objective of maximising economic recovery.
Part of the decision on whether a small field is material in the context of competing
worldwide opportunities will be the tax reliefs available. The “small field allowance” is
obviously a useful tool in encouraging such investment in the UK. In the context of small
fields commerciality can depend on the ability to use third party infrastructure for
transportation and processing. It might be possible to investigate whether an infrastructure
owner which gives access to infrastructure to allow field development might be permitted
some degree of tax relief on tariff income.
Question 2: How will the changing economics of the basin affect risk? What is the
role of the fiscal regime in sharing risk between industry and government?
At a minimum the fiscal regime should provide certainty for companies which are
considering investing in UKCS projects. Companies have to contend with commodity prices
which can, at times, be volatile and with fluctuations in other costs, such as rig day rates
etc.
The introduction of the Decommissioning Relief Deed in 2013 was a very useful measure
which provided certainty in respect of one important factor which is taken into account when
making investment decisions. Such certainty is important in modelling investments.
The increase in the Supplementary Charge from 20% to 32% in 2011 was not, as we
understand, well received by industry. Whilst the call for evidence explains that the increase
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in the rate of Supplementary Charge from 20% to 32% has to be considered in the context
of the budget deficit at that time, increases in taxation with no consultation is inconsistent
with a desire to increase investment. An unpredictable tax regime (and indeed uncertainty
of any nature) is likely to deter investment. This is particularly the case in a global industry
like the oil and gas industry where the UK is only one of a number of countries competing
for investment from oil and gas operators.
Question 3: In recent years prices for oil and gas have diverged, with the result that
gas production is relatively less economic. This is particularly and issue in the
Southern North Sea, which is largely a gas producing region. To what extent should
the fiscal regime reflect the differing economics of oil and gas production, and of
different regions in the UKCS?
There would be logic in differentiating between the tax rates in respect of oil and gas given
the recent divergence in prices. Gas is likely to play an increasingly important part in the
energy mix of the United Kingdom going forward. We have heard some operators with a
large percentage of gas assets in their portfolios complaining that when tax increases have
occurred (often justified on the basis of high product prices leading to large profit levels) no
real account has been taken of the lower profit margins realised in respect of gas
production.
Question 4: Decommissioning will become an increasingly important activity in the
UKCS in the coming decades. Is the fiscal regime set up to ensure that
decommissioning will be undertaken in the most cost effective way?
To a certain extent the parameters of what needs to be done in respect of decommissioning
are set by the requirement to carry out decommissioning as per the Petroleum Act 1998
and the UK’s international obligations such as its obligations under the United Nations
Convention on the Law of the Sea (UNCLOS 1982) and under the OSPAR Convention and
OSPAR decision 98/3. It is clearly in the interests of the UK that decommissioning is carried
out in a cost effective manner given that the majority of decommissioning costs will be met
by the UK in the form of tax reliefs.
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From a tax relief perspective one lingering issue in respect of tax relief for decommissioning
costs is the limitation in the level of Supplementary Charge relief to 20% notwithstanding
that the Supplementary Charge rate is 32%. Consideration should be given to providing
relief at the full 32% (although this should not have a cost efficiency implication).
We suspect that now that there is certainty on the levels of decommissioning tax relief
which will be available moves to making decommissioning more cost effective will result
more from new technologies and from experience in actually carrying out decommissioning
in the UKCS as opposed to changes in the tax regime. Co-operation between operators in
planning decommissioning programmes could also potentially reduce costs – for example
sharing of rigs by operators to carry out a programme of well abandonments.
Question 5: How sensitive are project economics to changes in commodity
price/input costs?
Projects are very sensitive to changes in commodity prices and input costs.
For example in 2011 following the increase in Supplementary Charge from 20% to 32%
there was a period of uncertainty as Statoil said it was putting the Mariner and Bressay
developments on hold. Statoil only resumed the Mariner Project once field allowances had
been brought into being which it considered largely neutralised the effect of the rate of
increase in Supplementary Charge.
More generally operating costs have been increasing in the UKCS. Oil & Gas UK report that
the average unit operating costs per barrel of oil equivalent rose to over £17 in 2013 and is
expected to exceed £18 in 2014. They stated that “in the space of 12 months, around 300
million boe of reserves are no longer considered recoverable as a result of operating cost
increases that are shortening the economic life of fields.” They have also indicated that in
such a background a significant fall in oil and gas prices could be serious for the industry.
Question 6: How can the government ensure the regime provides certainty and
stability even as prices and costs change? What criteria should apply in judging any
changes to the regime?
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The introduction of decommissioning relief deeds in 2013 was a good step forward in
providing certainty in respect of one important aspect of the UK fiscal regime. This was
essentially a fiscal stability contract.
Certainty could be provided by having a lower tax rate with less tailored allowances. This
linked perhaps to a more general fiscal stability contract with operators (which would be a
radical move) could provide certainty and stability.
Question 7: Do stakeholders have evidence of specific areas of the tax regime where
changes could improve certainty for investors?
The obvious changes would be:
(i)
not to change tax rates (such as Supplementary Charge) without prior consultation
with industry; and
(ii)
reducing the headline marginal tax rate and removing specific field reliefs.
Question 8: Is there evidence that the UKCS is becoming uncompetitive and if so, to
what extent is the fiscal regime contributing to this? What range of options is there
to ensure that the UKCS is perceived by investors as attractive to invest in?
There have been examples of companies putting UK assets up for sale with the aim of
utilising sale proceeds for investment elsewhere – for example to use sale proceeds to
invest in shale in the US. Marathon Oil marketed its UKCS assets (and Norwegian assets)
in 2014 at a time when it was ramping up investment in the US. There is an opportunity cost
of doing business in the UK and some operators appear to be of the view that that cost is
too high.
With the UK being seen as a high cost environment by oil and gas companies and with the
average size of new discoveries diminishing it is important that the tax regime takes
account of the fact that investing in the UKCS is less attractive than it once was.
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From the perception perspective it is likely that companies from out-with the UK look at the
marginal tax rates at 81% for PRT paying fields and 62% for non-tax paying fields and are
deterred from investing on that basis without realising that available field reliefs may reduce
the effective tax rate considerably.
From a perception perspective a lower marginal tax
rate and simpler reliefs might be more attractive.
Question 9: What are the advantages and disadvantages of the more bespoke
allowances introduced in recent years? How can any disadvantages be mitigated?
What would be the pros and cons of reverting to a simpler regime with fewer or no
allowances and what would need to be considered as part of that transition?
The advantages of bespoke allowances include the fact that they are targeted – the reliefs
are aimed specifically at areas where the development cost will be high or where there are
other targeted challenges rather than taking a scatter gun approach. A large number of
investments would not have taken place but for the field reliefs. According to Oil & Gas
UK’s “Activity Survey 2014” “more than half of all investment in 2014 is in receipt of field
allowance”.
The disadvantages of the bespoke allowances include:
(i)
Complexity – the range of reliefs includes reliefs for high temperature, certain ultra-
heavy oil fields, certain smaller fields, certain deepwater gas fields, certain shallow water
gas fields and certain additional developments to developed oil fields.
(ii)
Perception – there is a risk that investors consider the headline marginal rates at
62% and 81% and make investment decisions based on those figures.
Question 10: What should be the future of PRT and why?
Given the small number of fields which are subject to PRT, and the even smaller number
which might actually pay PRT or become liable to do so, we question whether it is worth
retaining PRT.
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Question 11: How can the fiscal regime best support the themes of the Wood
Review?
Some of the key issues raised in the Wood Review were (i) the need for operators to focus
on maximising economic recovery for the UK as well as pursuing their individual
commercial objectives and (ii) the need for fiscal stability consistent with the challenges of
maturity”. (Wood Review – Page 5).
The fiscal regime could support these themes by:
(i)
Expanding the scope of reliefs to increase investment or alternatively reducing the
marginal rate of tax and restricting or removing specific reliefs. This could encourage new
and incremental development. A lower rate of tax received from a field in production is
better than a high rate of tax which would have been payable had the relevant company not
decided to use the cash in a project overseas. Such increased investment could help
maximise economic recovery for the UK;
(ii)
Avoiding unexpected changes in tax rates as these destabilise the industry and
create uncertainty and mistrust which can lead to decisions not to invest in the UK. A
general fiscal stability agreement could provide even greater certainty.
Question 12: The main way in which the fiscal regime currently helps maximise
economic recovery is through the system of field allowances which help make more
marginal projects commercially viable. It is important that allowances are cost
effective and prioritised where they can achieve greatest impact. Are field allowances
targeted on the most valuable projects to maximise economic recovery?
In the main it would appear that they are well focussed (although an extension of the Brown
Field Allowance to include enhanced oil recovery using carbon dioxide could encourage
further spend on maximising production) thus extending field life, prolonging tax take from
the fields and assisting with the UK’s security of supply concerns.
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Question 13: The Wood Review also identified asset stewardship and technology as
key issues, including aging infrastructure, under-investment in assets and
insufficient uptake of Improved Oil Recovery and Enhanced Oil Recovery techniques
and technologies. What evidence is there that the fiscal regime could support action
in these areas?
The Oil & Gas UK Activity Survey 2014 reported that the total related reserves in respect of
brownfield projects rose by 25% in the reporting year even though the number of projects
had risen by only 2. The survey considered that the introduction of the brownfield allowance
had been a significant contributory factor and that the brownfield allowance could have a
bigger role to play to promote increased and enhanced oil recovery.
The brownfield allowance does not currently extend to enhanced oil recovery using carbon
dioxide and an extension of the allowance to capture such EOR could lead to further
investment and extension of field lives.
Question 14: Exploration rates have been relatively low since 2009. What evidence is
there that further action on fiscal policy could have a meaningful impact on
exploration rates?
Companies must take investment decisions in the context of their wider asset portfolio’s
and their global investment programmes. The fiscal regime in each country in which it
operates is a major consideration in each investment decision.
High rig rates are one issue which can deter companies from drilling. Oil & Gas UK report
that “semi-submersible rig day-rates have almost doubled over the last three years and
jack-up rig day rates have increased by 60 per cent. Such cost increases have been a
major deterrent to exploration activity, as many exploration wells are simply unaffordable at
current prices.”
The government’s change to the arrangements to the taxation of bareboat chartering
(which applies to drilling rigs and accommodation vessels) has the potential to increase day
rates and push more discoveries into the zone of unaffordability.
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Question 15: Investment in existing fields is becoming increasingly important as part
of maximising economic recovery. How do the economics of incremental
investments differ from other developments and does that justify a different tax
treatment? How effective has the brownfield allowance been in supporting
incremental investment?
Please refer our response to Question 13 above.
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For further information and alternative formats, please contact:
Brian Simpson
Law Reform
DD: 0131 476 8184
E: [email protected]
The Law Society of Scotland
Atria One, 144 Morrison Street
Edinburgh EH3 8EX
www.lawscot.org.uk
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