Memorandum submitted by BG Group
EXECUTIVE SUMMARY
— One of the most active companies
in the UK Continental Shelf (UKCS), BG Group believes that the
UKCS continues to offer significant upstream opportunities but
hydrocarbon production from the province will only be maximised,
if there is the right fiscal, regulatory and investment climate.
— Hydrocarbons that amount to as much
as 25 billion barrels of oil equivalent (boe) could still be produced
from the UKCS—compared to 37.5 billion produced to date.
— Liquefied natural gas (LNG) imports
can contribute significantly to the UK's security of gas supply.
— Once two new LNG terminals are operational,
the total capacity of the UK's three LNG import terminals will
be equivalent to one-third of the country's current gas demand.
— HM Treasury's outline proposal of
a Value Allowance, allowing relief from Supplementary Corporation
Tax (SCT) for certain kinds of fields, could lead to security
of supply benefits with oil and gas volumes that would not otherwise
have been produced becoming commercially viable.
— BG Group believes that high pressure,
high temperature (HPHT) fields that are expensive to drill and
technically challenging and small field discoveries close to existing
infrastructure could benefit in particular from a Value Allowance
and the company has submitted to HM Treasury a worked proposal,
outlining how this might work.
— In the medium to longer term, HM
Treasury might want to consider abolition of SCT—a move
that would bring tax treatment of the oil and gas industry more
closely in line with that of other industries—though this
would require safeguards around capital expenditure relief.
— Uncertainty around the legal and
regulatory framework for decommissioning is restricting commercial
activity.
— There is a need for the obligation
for industry to meet all decommissioning liabilities to be coupled
with a legal and regulatory framework, which is both clear and
demonstrably fair to all licensees and which will facilitate the
process of licence transfers in future.
BACKGROUND
BG Group is an international natural gas company,
active in 27 countries across the world. The company's centre
of gravity lies in upstream exploration and production but it
works right along the gas-chain and aims to link equity and contracted
gas resources to high value markets. The strength of its position
in liquefied natural gas (LNG) means that BG Group has considerable
flexibility in where and when it can deliver volumes.
Despite the rapid internationalisation of the
company's business over the last two decades, the UK is still
responsible for around 25% of total Group production. BG Group
is one of the most active players in the North Sea, responsible
for the equivalent of around 7% of UK gas production. Its total
oil and gas production in 2008 was 61 million barrels of oil equivalent
(boe). The company's combined capital investment and operating
spend in the UK upstream were in excess of £650 million last
year and are expected to be around £675 million this year.
Despite the fact that the UK Continental Shelf is now a mature
province, BG Group believes that its levels of investment in UK
and Norwegian waters will enable it to continue producing at least
50 million boe per annum from the North Sea out to 2013 and beyond.
BG Group is one of the most active explorers
in the UKCS, drilling around eight major exploration and development
wells on average per year and establishing a strong track record
of discovery successes. For example, BG Group is the company that
drilled the exploration well, which led to the discovery of the
Buzzard oil-field—the largest discovery in the North Sea
for a decade. BG currently has a 22% equity share of Buzzard.
This field, which came onstream in 2007, is producing in excess
of 200,000 boe on an average day.
The company has also found oil and gas in its
last three drilling operations in Norway and, over time, those
hydrocarbons are likely to come to the UK or Continental European
markets. BG Group's Dragon LNG import terminal, which it shares
with Petronas, will be open for business at Milford Haven in West
Wales in the next few months.
THE EXTENT
OF THE
UK'S OIL
AND GAS
RESERVES AND
THE CONTRIBUTION
THESE CAN
MAKE TO
THE UK'S
FUTURE ENERGY
NEEDS
In our view, the best estimates of the remaining
potential of the UKCS come from the upstream industry's umbrella
body, Oil & Gas UK, which pools information from across
member companies. Their calculation is that the province has produced
37.5 billion boe over the last 40 years. Their estimate is that
it is capable of producing another 25bn boe of oil and gas.
Company business plans already suggest that
the first 10 billion should be accessible—just over 6bn
from existing fields and sanctioned projects and around 3.5 billion
from new fields and brownfield projects. The ability of upstream
companies to produce the remaining 15 billion is more questionable
and will depend on the degree to which exploration activity is
encouraged and sustained and the climate for investment that prevails.
Too often the impression that has been given
has been that there is little left in terms of North Sea reserves.
The figures we quote above make it clear that this is not the
case.
The UKCS still produces around 70% of the country's
natural gas requirements with imports accounting for the rest.
It is the case that that figure will decline significantly over
the next decade or so—the former BERR forecast that the
figure would be between 20% and 25% of demand met by indigenous
gas by 2020—but the pace at which UKCS production decreases
will be highly dependent on the investment climate.
The graph below shows the Oil & Gas UK
view that production could amount to as little as 12% by 2020;
in contrast, with the right incentives, production could continue
to meet around 40% of demand.
Natural gas is the cleanest of the hydrocarbons,
producing 22% less CO2 than oil and 40% less than coal on combustion.
As such, it will play an important role in acting as a bridge
to a low or no carbon future. It has been acknowledged in the
course of the climate change debate, that the substitution of
natural gas for dirtier hydrocarbons in power generation can play
an important part in the global bid to reduce carbon emissions.
Given the unpredictable pace of development
of renewables, the need to decommission a significant percentage
of existing UK coal and nuclear fired generation in forthcoming
years and the long lead time required for new nuclear power stations,
large quantities of natural gas will be required to fill the gap.
Given that the UK could be between 70%[1]
and 80%[2]
reliant on oil and gas to meet its primary energy needs[3]
in 2020, it is important to maximise indigenous production of
hydrocarbons.
SECURITY OF
SUPPLY AND
LNG
The UK Government should not underestimate the
contribution to security of gas supply that LNG imports can make
to the security of gas supply position in the UK.
The next few months will see a major addition
to the UK's LNG import capacity with the opening for business
of the Exxon/Qatargas South Hook terminal and the BG Group/Petronas
Dragon LNG terminal.
The Dragon terminal in Pembrokeshire will have
the capacity to handle 2.2m tonnes of LNG a year. Between them,
these three LNG terminals have the capacity equivalent to one-third
of the UK's annual gas demand at current levels.
LNG developments will both add to the UK's security
of gas supply and reduce the percentage of gas storage capacity
that the UK will need, compared to other EU countries with lower
levels of indigenous gas production.
FISCAL INCENTIVES
In BG Group's view, by introducing new players
through revision of the licensing arrangements, the UK Government
has taken an important step in opening up the basin; but, to win
international capital, the investment environment must be competitive
and attractive.
The UK has much to offer international investors:
high quality skills, political stability and established oil and
gas infrastructure. However, the fiscal regime must also be such
that the risk-reward equation for new exploration and development
is attractive compared to the international opportunities available
to investors.
Although oil and gas companies prospered during
the period of high oil and gas-prices, now that prices have fallen
back, the impact of the 20% Supplementary Corporation Tax and
the additional 2% Corporation Tax—which apply only to oil
and gas companies—is particularly significant, rendering
a large number of discoveries uncommercial.
During HM Treasury's series of recent consultations
on North Sea tax reform, BG Group's initial preference for reform
was a 25% uplift on capital allowances. Our view was that this
would encourage activity and lead to more discoveries. This could
be applied across the board for new exploration and/or developments
or it could be targeted on certain kinds of fields with a view
to bringing into play discoveries that were particularly challenging
to develop—either technically or commercially.
We understand HM Treasury's principal reservation
about such a proposal: namely, that it ran the risk of offering
this incentive without having any guarantee of additional hydrocarbon
production. For that reason, BG Group was happy to work up a proposal
around HMT's preferred Value Allowance option.
BG Group believes there are two types of fields
in particular where real potential exists for a Value Allowance
to deliver significant security of oil and gas supply benefits:
high pressure, high temperature (HPHT) fields and small fields.
HPHT fields are defined as those which have
a reservoir temperature of in excess of 300° F and a wellhead
pressure of in excess of 10,000 psi. These are extremely costly
to drill but they can contain large volumes of oil and gas. For
example, the initial reserves estimate for a recent BG Group HPHT
discovery, Jasmine, are 130-240mmboe—a significant discovery.
BG Group is one of the leading companies in HPHT operating in
the North Sea at present.
BG Group's interest in small fields relates
to prospects and discoveries that are near existing hubs of activity
and which can often be linked to existing infrastructure and brought
onstream. The fact that such fields can be developed using existing
infrastructure rather than requiring their own new infrastructure
can often make the difference between a discovery being commercially
viable or non-viable.
We know from specific examples within our own
portfolio that properly designed Value Allowances, offering relief
from SCT for certain kinds of field, would turn some marginal
prospects and discoveries into commercial opportunities. This
would generate additional oil and gas volumes that would not otherwise
be produced. We submitted our proposal to HM Treasury ahead of
the February 13 deadline and we are hoping that a Value Allowance
scheme similar to that proposal will be announced in the Budget
in April of this year.
Another area of discussion between government
and the industry in recent months has been Enhanced Oil Recovery
(EOR). Ministers and officials acknowledged that thinking on EOR
and research into relevant technologies are not sufficiently advanced
for this area of activity to be included in the current consultation
on North Sea tax reform.
BG Group would argue that enhanced natural gas
recovery needs to be considered in parallel with EOR and that
the goal should be techniques for enhanced hydrocarbon recovery
rather than just EOR. It is highly likely that enhanced hydrocarbon
recovery will require further adjustments to the tax-regime to
make it viable. A debate around these issues should start now.
Given the high oil-price environment that prevailed
until the last few months, we understand why there was little
appetite in HM Treasury and the Government for more radical reform
of the North Sea tax-regime ahead of the 2009 Budget. However,
HM Treasury may want to consider further measures in the medium
and long-term, as the province's challenges become greater and
the technical and commercial challenges of finding and developing
new hydrocarbons become more difficult.
One option HM Treasury may wish to consider
over time is abolition of SCT, bringing the oil and gas industry
in line with the rest of industry. This would mean CT being payable
at 28%—a move that would be certain to release additional
hydrocarbons from discoveries that are currently uncommercial
because of the SCT regime. However, such a move would require
certain safeguards in relation to capital expenditure relief.
While it might be acceptable to offer relief
on capital expenditure at the reduced rate on new developments,
it would not be acceptable in relation to past and existing developments,
given the large amount of sunk costs and the eventual requirement
to decommission them. The solution would be to lock in capital
expenditure relief at the rate at which tax was paid on the income
from those assets. This would mean a guarantee that decommissioning
on PRT fields would be relieved at 75% and at 50% for CT/SCT fields
only.
While SCT abolition might appear at this stage
in the cycle to be a radical option, it is essential in the medium
and long term that measures are taken to maximise North Sea production,
if we are to maintain and retain the existing infrastructure required
to land as much oil and gas as is economically possible.
PARTNER ALIGNMENT
AND DEPARTMENT
OF ENERGY
"INTERVENTION"
One of the principal challenges facing a company
active in oil and gas exploration is gaining the backing of partner
companies to proceed with exploration and development programmes.
This challenge is heightened in a mature province like the UKCS
because some partners may have priorities in other basins on which
they would rather focus. The current global credit "crunch"
and economic downturn is also having an impact, dulling many companies'
appetites for investment and risk.
There is no simple solution to this problem
but we have noted and we welcome the inclination of senior officials
formerly in the DTI and BERR—now in the Department of Energy
and Climate Change—to intervene and encourage companies
to support activity or release their equity in relevant blocks.
Although sometimes this is carried out formally through schemes
such as the Fallow Initiative, on other occasions it has been
pursued more informally. As an active player in the North Sea,
this approach has tended to be helpful to BG Group.
We do not believe that officials need further
legislative or other regulatory powers to underpin this intervention
but we welcome the trend and believe it has a positive impact
on activity levels.
ASSET INTEGRITY,
THE CHALLENGE
OF AGEING
INFRASTRUCTURE AND
DECOMMISSIONING
The oil and gas industry in the UKCS has been
particularly successful at maintaining and extending the life
of its fields and assets. It is not unusual for offshore infrastructure
to continue to operate between 10 and 20 years longer than initially
envisaged. Asset and field-life extension will continue to be
a focus, as companies gain more and more expertise at extracting
as much oil and gas as they can from their fields.
This activity has to be carried out safely so,
as assets age, more investment is needed to maintain the integrity
of those assets and to ensure that all of those who work in the
industry do so safely. With ageing assets, there is an increasing
risk that infrastructure failure may suddenly jeopardise the economic
viability of a suite of dependent installations.
In the future life of the province, there are
also limited numbers of developments that will be able to justify
their own "greenfield" infrastructure to bring hydrocarbons
to the beach. This means that there is likely to be ongoing and
perhaps increasing pressure on existing infrastructure to handle
and process new oil and gas finds.
In BG Group's case, our intention is to focus
our activity around hubs. This means that we will seek efficiencies
by using existing platforms and pipelines to land the product
of new discoveries. However, in the event of a requirement to
decommission part of our existing infrastructure, there will be
a need for the remaining infrastructure to work harder. This will
mean additional capital and operating costs to ensure that that
infrastructure can continue to function efficiently and safely.
There is a case in such instances for additional relief on this
additional expenditure to be made available.
BG Group would also urge the Department of Energy
to introduce more clarity and certainty to the position relating
to the decommissioning of assets. BG Group supports an active,
transparent and efficient asset-trading regime in the North Sea.
One important area where, in our experience, the process of licence
transfers has become slower, more expensive and more complex in
recent times is with respect to legacy decommissioning liabilities.
We understand the obligation on DECC to ensure
that all decommissioning liabilities are met by industry but we
believe that this obligation should be coupled with a legal and
regulatory framework, which is both clear and demonstrably fair
to all licensees. Increased clarity will greatly facilitate the
process of licence transfers in future.
We support the initiative taken by DECC in clarifying
the existing law relating to infrastructure owners on multi-block
licences in the Energy Bill and we are also in favour of further
guidance with respect to the application of liabilities imposed
under the Petroleum Act. We would welcome a statement by DECC
as to when and how it would seek to apply the existing regulations
in S.29 and S.34, requiring former licensees to undertake a decommissioning
programme.
At this point in time, we do not fully understand
how this fundamental principle in the decommissioning regime would
be applied in practice. This uncertainty tends to restrict commercial
activity, with some companies reluctant to take on assets, which
they will then become liable to decommission. We believe further
detail as to the application of this process will benefit the
industry by:
— Reducing the level of security required
by transferors.
— Simplifying commercial negotiations.
— Speeding up the time required to
execute transfers.
This in turn should help increase the number
of participants in the UKCS by reducing costs and maximising ultimate
recovery of hydrocarbons.
March 2009
1 Oil & Gas UK estimate Back
2
Dept of Energy estimate is "up to 80%" Back
3
Primary energy needs includes fuel for industrial usage, heating
and transportation-not just fuel for power generation Back
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