Memorandum submitted by Professor Alex
Kemp
EXECUTIVE SUMMARY
The UK Continental Shelf is now a maturing petroleum
province. The average size of new field is likely to be less than
20 million barrels of oil equivalent. Unit costs of exploitation
are now relatively high, with the average being in the $15-$20
per boe range. At oil prices generally employed for long-term
investments the taxable capacity of many new fields and projects
is quite modest, with many having negative returns at prices of
$30 and less. The recent tax increase could reduce total field
investment to 2030 by £1 billion or so, with operating expenditures
being reduced by a similar amount. Total production could be reduced
by around 200 million boe. If the price fell significantly investment
would fall sharply. There is a strong case for reducing the investment
uncertainty by designing a schedule whereby the rate of Supplementary
Charge changes automatically with oil/gas prices.
The is also a case for reducing the non-level
playing field against new players, removing the Supplementary
Charges on income from new tariff contracts, and providing an
R and D incentive for tertiary recovery.
1. Context
The recent changes to taxation of North Sea
oil and gas should be seen in the context of the present and prospective
phase in the development and depletion of the nation's hydrocarbon
resources. Production peaked in 1999 and has been declining steadily
since then at a pace which has been faster than anticipated. Oil
production declined by 11% in 2005 and gas by over 8%. Given the
delays in the completion of new storage capacity and gas import
schemes the decline in gas production has come at an unfortunate
time, resulting in high wholesale winter prices in particular.
Oil and gas together constituted around 74% of the UK's primary
energy needs in 2005 and will continue to account for much of
the country's requirements for many years ahead. The UK is now
a net gas importer and in a few years will become a net oil importer
as well. For security of supply reasons and to provide adequate
time for the completion of gas import schemes and the development
of other energy sources it is clearly a national priority that
the exploitation of the remaining indigenous oil and gas should
be economically maximised.
2. Smaller Fields and Higher Unit Costs
Total depletion of North oil and gas to date
has amounted to 35.4 billion barrels of oil equivalent (billion
boe). The DTI's central estimate of the remaining potential is
23.1 billion boe with low and high estimates of 13 billion boe
and 43.3 billion boe respectively. But most of the remaining reserves
are likely to be located in relatively small fields and located
in areas with inadequate infrastructure. A key example is West
of Shetland where there are currently over 20 undeveloped gas
fields. The consequence is that unit costs of development and
production are relatively high. Over the last two years there
has also been a major cost escalation affecting all inputs, but
particularly key ones such as drilling rig rates and steel prices
(the latter driven by demand from China and thus not particularly
related to the recent oil price increases). For the next generation
of fields the consequence is that field development and operating
costs average $15 per boe and for the generation after the average
could be $20 per boe.[1]
Exploration and appraisal costs are additional to the above. The
prospective taxable capacity from new fields and incremental projects
needs to reflect these likely exploitation costs.
3. Investment Decisions, Oil/Gas Prices and
Taxable Capacity
Prospective taxable capacity also depends on
the oil and gas prices used for long-term investment decisions.
Oil companies are generally cautious on this matter. A recent
survey of licensees by the Royal Bank of Scotland[2]
found that the median values were $33 per barrel and 23 pence
per them. The present author employed prices of (a) $40, 36 pence,
(b) $30, 28 pence, and $25, 24 pence in a recent detailed study
of the prospects for activity in the UK Continental Shelf. The
economic modelling of the fields and incremental projects found
that the size of the returns to investors on most of them was
quite small. Many are unacceptable, particularly under the $25,
24 pence price scenario. The returns were calculated in terms
of net present values discounted at the cost of capital[3]
which is the conventional way by which investments in the industry
are assessed. Taxable capacity is best measured in terms of the
size of the net present value or wealth generated by the fields
or projects. The effect of any tax increase is similarly best
measured by the extent to which the net present value is reduced
and its resulting acceptability to the investor.
4. The Recent Tax Increase and their Effects
on Field Developments
In the Pre-Budget Statement it was announced
that the Supplementary Charge to corporation tax would be increased
from 10% to 20%. The resulting tax rate for fields and projects
developed before 16 March 1993 becomes 75% from 1 January 2006,
given normal corporation tax at 30% and Petroleum Revenue Tax
(PRT) at 50%. For exploration and field developments since 16
March 1993 the rate becomes 50%. In general the tax increase reduces
the net present value (or wealth generated) from fields or projects
by 16.667%. In a detailed study of these effects on all categories
of fields and projects (including new discoveries and fields not
currently being examined for development) the present author found
that from 2006 to 2030 the numbers of projects/fields offering
a net present value greater than £10 million before the tax
increase but less than that amount after the tax increase (and
thus not sufficient to compensate for the risks involved) were
as follows:
NO. OF PROJECTS/FIELDS DETERRED TO 2030
Prices
| Discount rate 10%15%
|
| $30, 28p | 16 | 24
|
| $40, 36p | 12 | 24
|
| $25, 24p | 22 | 16
|
| | |
The value of the total reduction in field investment varied
according to the oil price and discount rate but averaged around
£1 billion at 2006 prices. The total reduction in field operating
expenditures also averaged around £1 billion. The total loss
of production form these fields/projects was around 200 million
boe. These may be defined as fairly modest reductions in activity.
5. The Tax Increase Exploration, and Possible Investment
Risk Premium
The increase in the tax can also reduce exploration as the
expected full cycle returns are reduced. The effect is complicated
as the rate of relief for exploration is also increased by the
tax increase. Any net negative effect is in addition to those
outlined above. Similarly, the recent increase coming on top of
other increases in recent years will increase the investment uncertainty
in the UKCS. In turn this could lead investors to put an extra
premium on the size of their minimum expected returns to compensate
for the perceived higher risk. The assurance that the Supplementary
Charge will not be increased for the rest of the present Parliament
is only of limited benefit to an investor who has to consider
a much longer time period.
6. Undeveloped West of Shetland Gas Fields very Marginal
The present author has recently conducted a detailed study
on how 23 undeveloped gas discoveries West of Shetland could be
developed. The main conclusion was that a cluster development
was clearly the most desirable from a national viewpoint, but,
given the modest sizes of the fields and the high infrastructure
costs, the investments were very marginal.[4]
The tax increases have made them even more marginal.
7. Disadvantaged Position of New Entrants
The tax system applied to the UKCS has also some attractive
features from the viewpoint of encouraging investment. Capital
allowances are available on 100% first year basis for all investments.
For existing taxpaying licensees the system is in essence a cash
flow tax with the Government sharing all the project risks more
or less immediately to the extent of 50% for new exploration and
developments (and 75% on "old" fields). This is advantageous
to licensees able to utilise the allowances from existing income.
New players are being actively encouraged to enter the UKCS to
examine prospects not considered of core interest by others. New
players do not have tax cover and cannot utilise the front-end
allowances available to existing tax payers. This disadvantage
is increased with the increase in tax rate (which increases the
rate at which relief is given for investments). The Government
has acknowledged this problem and provides that unutilised allowances
be carried forward at 6% compound interest. This rate is a risk-free
one and is well below the cost of capital for exploration and
development. It needs to be increased if anything approaching
a level playing field is to be produced.[5]
8. Increased Tax on Tariff Income
Third party use of infrastructure is central to the economically
efficient development of the many small but currently undeveloped
fields. The revised Code of Practice is designed to promote speedy
agreements at competitive tariffs. The recent tax increase applies
to tariff income. This will not promote competitive tariffs. Asset
owners can attempt to have a clause in the contract which would
lead to any tax increase being passed on in higher tariffs. The
problem was recognised in 2003 when it was decided that PRT would
not apply to income from new tariff contracts. It was expected
that the net benefit would be passed on in lower tariffs. Consistent
with this there is a strong case for removing the Supplementary
Charge on new tariff contracts.
9. Need to Kick Start Tertiary Recovery
Currently there is little tertiary recovery taking place
in the UKCS. The potential increase in recovery from the use of
tertiary recovery techniques is very substantial. Example technologies
are (1) chemical flood (such as with surfactants or polymers),
(2) air injection, (3) microbial EOR, (4) low salinity water flood,
(5) CO2 injection and (6) miscible gas injection. To give these
a kick start a tax relief for R and D relating to such schemes
could be given. A practical method would be the application of
the R and D credit to the Supplementary Charge. (It should be
noted that loan interest is not allowed as a deduction against
the Supplementary Charge.)
10. Reducing the Perceived Investment Risk
The several tax changes over recent years have increased
the perceived investment risk. It is also clear from the author's
recent study that if a substantial fall in oil prices took place
a reduction in the tax rate would be necessary to sustain investment
activity. Under current rules, a tax rate reduction would require
a discretionary change by Government. This could certainly not
be assumed to happen by a prudent investor. To reduce the investment
uncertainty is certainly desirable and accordingly consideration
should be given to the introduction of formula whereby the rate
of Supplementary Charge is clearly and directly related to oil
prices. This is not straight-forward in practice because of (a)
the co-existence of gas and oil and (b) the volatility of prices
in the short-term. These problems can be dealt with by the use
of conversion factors and ranges of oil (and oil equivalent gas
prices) over a specified period of time.
26 June 2006
1
For a fuller discussion see AG Kemp and L Stephen, Prospects
for Activity Levels in the UKCS to 2035 after the 2006 Budget,
University of Aberdeen, Department of Economics, North Sea Study
Occasional Paper No. 101. April, 2006. Back
2
See Royal Bank of Scotland, Survey Report, 5th RBS North Sea
Conference, Aberdeen, January 2006. Back
3
A G Kemp and L Stephen, ibid. Sum of the annual profits discounted
at the cost of capital minus the initial investment costs. The
method used by the ONS to measure profitability is conceptually
unsound. Back
4
See A G Kemp and L Stephen, Options for Exploiting Gas from West
of Scotland, University of Aberdeen, Department of Economics,
North Sea Study Occasional Paper No 100. December, 2005. Back
5
The carrying forward of allowances with interest will not level
the playing field for an exploration company as exploration costs
will only be relieved if a discovery is made. Back
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