Memorandum submitted
by the Department of Energy and Climate Change (UKOG 16)
1. The
Department welcomes this opportunity to provide evidence to the Committee’s
initial inquiry, into UK offshore oil and gas.
2. The UK’s endowment of oil and gas resources
is a major asset to the country. The
Government’s overall objective for the management of these resources is to maximise
their economic recovery over time, and to maximise the consequent benefits to
the UK economy and to UK employment.
The underlying geology and the evolution of future oil and gas prices,
together with the development of the necessary technology, will be the dominant drivers of investment and,
hence, ultimate recovery levels. However,
Government does have a crucial role to play in ensuring that the regulatory and
fiscal regimes help deliver the best possible future for the UK Continental
Shelf (UKCS).
3. This
memorandum first offers some background information on the broad ambit of the
Committee’s inquiry – the extent of the UK's oil and gas reserves and the
contribution these can make to the UK's future energy needs – and then some
comments on the seven questions specifically identified in the Committee’s call
for evidence.
The extent of the UK's oil
and gas reserves and the contribution these can make to the UK's future energy
needs
4. The Department publishes estimates of
the UK’s oil and gas reserves each year[1].
They are compiled from the oil and gas
companies’ estimates of their individual fields’ reserves. In accordance with standard industry and
geological practice, the discovered volumes of oil and gas remaining to be
produced are categorised into “proven”, “probable” and “possible” reserves
depending on the likelihood of the oil and gas being technically and commercially
producible. “Proven” corresponds to at
least 90% probability of production, “proven plus probable” combined
corresponds to a 50% probability of production while “possible” has a 10%
probability of being produced in full. As time passes and technology improves,
reserves tend to be reclassified, moving from possible and probable into
proven. Typically “proven plus
probable” is taken as the central estimate of reserves.
5. The central estimate of oil reserves
remaining at the end of 2007 was 780 million tonnes, and the central estimate
of gas reserves remaining at the end of 2007 was 647 billion cubic metres
(bcm).
6. Chart 1 in the Annex to this memorandum
shows the pattern of UK oil reserves, and cumulative production, over time;
Chart 2 presents the same information for gas reserves. It is clear that, provided exploration
work continues, additions to the reserves base will continue to be made, and
will continue to support significant oil and gas production for many years to
come.
Additional and undiscovered resources
7. The Department also publishes estimates
of “Potential Additional Resources” (discovered volumes not currently
considered producible for technical or commercial reasons) and “Undiscovered
Resources” (potentially recoverable resources in mapped leads that have not yet
been tested by drilling). Potential
Additional Resources (PARS) are also reviewed every year, and where appropriate
can also be re-classified as reserves if new technical information becomes
available or the economics of production improved. Estimates of Undiscovered Resources are also updated each year,
taking into account any new geological information from exploration and
appraisal drilling, seismic survey etc.
Summary Table Giving Ranges of UK Discovered Hydrocarbon
Resources
8. (Reserves plus Potential Additional
Resources, as at end 2007:
billion
barrels of oil equivalent)
|
|
|
|
|
|
Oil and
Gas |
Lower |
Central |
Upper |
|
|
|
|
|
|
Fields
in production or under development |
5.5 |
8.2 |
11.4 |
|
Other
significant discoveries not fully appraised |
0 |
1.6 |
3.2 |
|
Reserves |
5.5 |
9.8 |
14.6 |
|
Potential
Additional Resources |
0.9 |
2.3 |
4.7 |
|
Total
Discovered Reserves and Resources |
6.4 |
12.1 |
19.2 |
|
|
|
|
|
|
Cumulative
production to date |
37.5 |
|
|
Total remaining hydrocarbon potential
9. An indication of the total remaining recoverable
resources on the UKCS can be obtained by adding the central estimates for
discovered reserves and PARS to a range representing the possible range for
undiscovered resources that might become producible in due course. Figures for resources not yet discovered
are naturally subject to a higher degree of uncertainty than those for
discovered resources. But with the
increasing maturity of the UKCS, there is understandable interest in the
question of how much further production is likely. To facilitate more meaningful answers to such questions, the Department’s
estimates for undiscovered resources now include two mid-range estimates of
undiscovered resources - the lower of 5.2 billion barrels of oil equivalent
(boe) corresponding to a reasonable estimate of what might be found based on
current knowledge, the higher of 8.7 billion boe corresponding to a reasonable
estimate of what might be found with better understanding of the basins or
better technology.
10. Taking account of this range of
possibilities for undiscovered reserves, our current best estimate of remaining
recoverable hydrocarbon resources from the UKCS is of a figure of around 20
billion boe. But it is of course
entirely possible that the development of better understanding and
technological change will in the event enable higher figures to be reached.
UKCS Oil and
Gas Production Projections
11. The
chart below shows actual and currently projected UKCS oil and gas production,
and actual and currently projected UK demand for oil and gas[2].
As shown, the UK is expected to
become increasingly reliant on imported oil and gas. Nevertheless, UKCS oil and gas production can be expected to
amount to a large proportion of our oil and gas needs, and overall energy
needs, for many years to come. This
prospect is of great significance for UK energy security, and well as for its
economic benefits.
12. While
central projections of oil and gas production are shown in the chart, there is
in reality a wide range of possible outcomes because the rate of production is
dependent on a number of different factors including the level of investment
and the success of further exploration. Operators continue to find it difficult to predict production
accurately as older fields mature and their reliability reduces. A significant share of future oil and gas
production is expected to come from new fields, compounding the difficulty of
making accurate forecasts given the risks of project slippage and uncertain
start-up profiles. The central
projections are therefore our best estimates rather than a definitive
prediction of future production of oil and gas from the North Sea. There is similar uncertainty surrounding
projections of future UK oil and, especially, gas demand.
Oil
Production and Reserves
13. After
a dramatic build-up following the start of offshore oil production from the
North Sea in 1975, and against a background of rapidly falling dollar oil
prices, UK oil production peaked in the mid 1980s ahead of the Piper Alpha
disaster in 1988 which resulted in a sudden and dramatic decline in production,
due partly to the loss of the Piper field itself, and partly to the effects of
extensive work programmes to implement new safety measures. With recovery of production from existing
fields and increasing numbers of new fields coming on stream (following a
period of significantly higher development expenditure in the early and mid
1990s), oil production reached a second (and higher) peak in 1999. Until 1997, exploration activity had
maintained the level of discovered oil reserves remaining. The subsequent lower level of exploration
activity has not added sufficient to "ultimate recovery" (i.e. the
total of cumulative production to date and estimated remaining discovered
reserves) to prevent an overall decrease in remaining reserves. Unless future exploration activity[3] results in a significant increase in ultimate recovery, the level of
discovered reserves remaining (currently representing less than a third of ultimate
recovery) will set a natural limit on the level of oil production which, over
time, can be expected to continue to decline as remaining reserves are
depleted.
14. In
the absence of significant new fields starting production or major incremental
projects in existing fields, UK oil production tends to decline at 10-15% or
more per annum. However, if (large)
enough new fields start production (as happened in 2002, with Elgin/Franklin
and Shearwater coming into full production), or there are enough significant
incremental projects in existing fields, the decline can be arrested or even
temporarily reversed.
Gas
Production and Reserves
15. Prior
to the late 1990s the rate of natural gas production from the North Sea was,
effectively, constrained by the level of domestic demand for gas (with gas from
most fields being sold under long-term field depletion buyer's nomination
contracts), though throughout the 1980s some demand was met by direct imports from
the Norwegian Frigg Field. The
"dash for gas" in the 1990s saw a large increase in demand for gas
for power generation and, from 1998 with the opening of the Bacton–Zeebrugge
Interconnector, significant exports were possible, allowing UK production to
increase faster than UK demand. An increasing proportion was "associated
gas" i.e., produced in association with oil (for example from the oil
fields in the central and northern North Sea) rather than from the
"dry" gas fields in the Southern Basin of the North Sea. Gas production peaked in 2000 and has been
declining sharply since 2003 as new fields starting production have been too
few and too small to compensate for the decline in production from existing
fields. As with oil reserves,
estimated ultimate recovery of gas increased through to 1997 as additions from
exploration more or less kept pace with the increasing rate of production. Technical and commercial reassessments have,
subsequently, reduced ultimate recovery at the proven plus probable plus
possible level. Remaining gas reserves
represent less than a third of the total discovered to date.
16. The
rate of decline of UK gas production has until recently been less dramatic than
the rate of decline of UK oil production. Compared with oil production, which exhibits some seasonality (as
maintenance tends to be scheduled for the summer months), gas production
fluctuates much more over the course of the year, reflecting the strong
seasonality of gas demand.
How can
the UK’s remaining offshore oil and gas reserves be exploited most effectively?
What barriers are there to exploiting
such reserves? What steps need to be taken to unlock resources west of Shetland?
17. As discussed in the previous section, the
UKCS still has substantial oil and gas resources. At the beginning of 2008
our central expectation was that 12 billion boe of discovered hydrocarbons had
yet to be produced, with additions from fields yet to be discovered estimated
to be between 5 to 9 billion boe, giving a best estimate of remaining
recoverable resources of around 20 billion boe.
18. Over the course of 2008 the UK’s combined
oil and gas production was some 1 billion boe (2.6 million barrels per day);
this represents around 60% of the UK’s total energy consumption and 80% of its
oil and gas demand. After more than 40 years of continuous
activity, production has however peaked and, without continuing capital
investment, would naturally decline at around 10-15% per year in line with
other mature basins. Over the past several years, annual capital
investment of some £5 billion per in new and existing fields (see Chart 3 in
Annex) has reduced this decline to 5-7.5%.
19. To exploit the remaining resources, both
discovered and undiscovered, and to continue to slow the decline, it is essential both to attract substantial
further investment - against fierce competition from oil and gas regions
throughout the world - and to maintain a population of oil companies,
particularly those with operational skills to identify and then exploit the
opportunities in the basin.
20. Clearly, geology and the levels of future
oil and gas prices will be key determinants of future investment; and little
can be done to influence these. In a mature basin such as the UKCS, other
factors can be equally important to attract investment: the costs of activity
must be low; regulation and commercial practices must be appropriate and follow
the grain of activity; skills of individuals, of the companies that make up the
supply chain, and of licensees, must match the opportunities; technology must
be developed to reduce the costs and risks of finding and developing new fields
and fully exploiting those already in production; and infrastructure, both
facilities and pipelines, must be maintained and accessible. The policies pursued over the past few years
have been designed to achieve these objectives.
21. Licensing policy is aimed at providing
regular opportunities for the whole spectrum of companies to access acreage
suited to their skills. The Department
has been actively seeking and encouraging new licensees, particularly
operators, to come into the basin, and have adapted the types of licences
available to meet the needs of the industry. The Promote and Frontier types of licence have been added to the
Traditional licence, all with a structure to encourage activity. (The
Promote licence is a short-life, low-cost licence to encourage exploration and
prospect promotion activity; the Frontier licence offers larger areas and
longer exclusivity to encourage exploration of challenging territory in the
Atlantic approaches.) Similarly the
“Fallow” initiative has been introduced to drive new exploration and
development activity on older licences in parallel with the “Stewardship”
process which puts pressure on the bottom quartile of fields in production to
improve performance. With the support
of the whole range of licensees, these approaches have demonstrably increased
the opportunities and levels of activity in exploration, appraisal and
development in the basin.
22 We are also working with the industry to
reduce commercial and administrative inefficiencies and costs. Through PILOT (an industry, Government,
trade union forum which is chaired by the Secretary of State) industry has
produced Codes of Practice for commercial activity between licensees and within
the supply chain. DECC has recently
agreed to play a more active role in helping to monitor and enforce these
Codes. To reduce the costs to industry
of our administration of the licensing regime we have e-enabled much of the
transactional process and have further improvements underway. We have also worked with industry to enable
them to reduce the burden of their necessary obligations to hold geological
data.
23. The maturity of the UKCS means that the
majority of new finds and developments will be small, and unlikely to be able
to support the cost of substantial, dedicated, production and export
infrastructure. It follows that access to existing
infrastructure (both pipelines and facilities) on fair and reasonable
commercial terms is critical to the full exploitation of the basin. Through PILOT, industry has developed an
Infrastructure Code of Practice aimed at ensuring transparent and timely
negotiations for that access. The
Department has agreed to assist in the enforcement of that Code, in particular
to help provide an expected timeline for negotiation. Beyond that function however, the Secretary
of State has powers on application to set tariffs and terms for access to
infrastructure, and has published Guidance on disputes over third party access,
to aid industry in understanding our approach to resolving such disputes. The nature of access to infrastructure is
changing as the basin matures, and the Department, in discussion with industry,
is currently revising the Guidance to accommodate these changes.
24. We see technology development as
primarily a task for industry but, where it is appropriate and there is a
particular need, we support individual technology development or more
fundamental research, particularly where this will encourage the pooling of
industry resources. Projects in the
oil and gas field have been supported by the Technology Strategy Board, and
DECC has contributed to development and university research projects supported
by the industry’s club financing (the Industry Technology Facilitator). The Department also funds geological and
geophysical analysis of parts of the UKCS with the aim of attracting bids for
specific areas in licensing rounds.
West of Shetland
25. The area to the west of the Shetland
Islands and the Hebrides is the largest remaining area of significant
prospectivity on the UKCS, holding some 10 to 20% of UK’s remaining oil and
gas. The area represents a potential 3
- 4 billion barrels of oil equivalent - around 17% of the UK's remaining oil
and gas reserves and includes some 10 to 15% of remaining UK gas reserves. It is
remote, being nearly 400 km from the nearest gas terminal, and most of the gas
discoveries are too small to support the necessary gas infrastructure on their
own The existing gas pipelines (WOSPS,
EOP and FLAGS) do not have capacity in the short and medium term to support
major development
26. Exploration and development has been
hindered by the lack of gas transportation capacity and no one company or single
field has been sufficient to drive the building of this infrastructure. As a result of the Energy Review in 2006, a
Government/industry Taskforce was established to get the right infrastructure
in place to the west of Shetland so that, with minimal impact on the
environment, development and exploration in the area could be speeded up. The
Taskforce includes representatives from leading oil and gas companies with gas
projects that have the potential to start within 5 years:
Total - operator of the
Laggan and Tormore fields
Chevron -
operator of Rosebank and Lochnagar
BP - operator of
the Clair field
ExxonMobil - operator of Tobermory
DONG Energy -
participant in Laggan, Rosebank and Tobermory.
27. The Taskforce started work in November
2006, to examine the potential for a multi-field development with gas export to
the mainland Scotland. A range of alternative options including
power generation and the production of Liquified or Compressed Natural Gas
close to the point of production, were also considered and rejected on at an
early stage on cost grounds. The Taskforce identified four types of gas
gathering hub, three of which were located offshore with a direct pipeline
connection to St Fergus and the fourth, onshore at the existing Sullom Voe
terminal in the Shetland Islands. All were assessed to be technically feasible.
28. In September 2007a well was drilled by
Total into the Tormore prospect close to the Laggan field which identified
additional gas. At the same time Chevron commenced an
extended appraisal programme of their Rosebank/Lochnagar discovery in the
growing confidence that they had a viable development further to the west.
29. These developments offered better prospects
for development, and the Laggan/Tormore and Rosebank/Lochnagar partners
co-sponsored an independently managed process in the autumn of 2008 to test the appetite for third party
investment in a basic engineering study and ultimately, in the collective
project. This revealed a potential requirement for about 18 million cu. m/year
of gas transportation capacity (equivalent to about 5% of UK annual demand),
involving 10 licensees in 3 separate licence groups.
30. Total have now commissioned the basic
engineering study for Laggan/Tormore and the work is proceeding primarily on
the basis of an onshore gas gathering hub located at the existing Sullom Voe
Terminal in the Shetland Islands.
31. For the gas export pipeline, there are
two options (see Chart 4):
- A direct pipeline
from Sullom Voe to St Fergus on the Scottish mainland, or
- An indirect route
using a new shorter pipeline to connect Sullom Voe to the existing, 100%
Total-owned Frigg UK gas pipeline and then via Frigg to St Fergus.
In either
case, the pipeline is expected to have capacity for the 18 million cm/d of gas
identified in the third party investment process. We understand that the partners
consider that there is a commercially viable development option for
Laggan/Tormore, with development sanction in September 2009 and first
production in late 2013. The parties interested in developments west
of Shetland are now moving towards a decision on development later this year
which will be followed by a submission of a development plan to the Department
for consideration. The Department considers that this
collaborative process has a real prospect of providing infrastructure to
deliver gas to the market in 2013/14. It will be a collective solution that reflects the requirements
of players in the West of Shetland area prepared to commit to development.
What can be done to minimise the environmental impact of exploiting oil
and gas reserves? How should this be
encouraged or financed?
32. A comprehensive framework
of environmental protection measures has been developed to minimise the impact
of oil and gas activities. This is embodied in the relevant legislation,
consistent with and in large part derived from the legislative framework of the
European Community (EC). In addition, the UK is a signatory to the
Oslo and Paris Convention for the Protection of the Marine Environment of the
North East Atlantic (the OSPAR Convention).
It is Government policy to
implement and apply all of the OSPAR Commission’s decisions and
recommendations.
33. This robust offshore
environmental protection regime, which covers oil and gas development
throughout its life cycle, from the initial licence application to the final
decommissioning of facilities, as detailed in the remainder of this
submission. All activities that could
potentially impact on the environment are subject to rigorous assessment, and
significant activities are controlled through the issue of permits, consents or
authorisations. There is also an inspection
and enforcement regime in place to confirm compliance with the conditions
included in the environmental approvals.
34. The robust regime is
reflected by the industry’s performance, and the UK has a good environmental
record with no significant impact on the marine environment resulting from
offshore oil and gas activity.
Environmental aspects of licensing
35. To meet the requirements
of EC Directive 2001/42, transposed into UK legislation by the Environmental
Assessment of Plans and Programmes Regulations 2004, a Strategic Environmental
Assessment (SEA) is carried out before oil and gas licensing is
undertaken. The SEA is subject to
public consultation and evaluates both the individual and cumulative impacts of
offshore oil and gas activity at a strategic level. Licence areas can be withheld if mitigation of potentially
adverse effects is not considered to be feasible, or if there is insufficient
information available to determine the potential impact of the licensing
activity. For example, the 2008/9
Offshore Energy SEA recommends that an area to the west of the Hebrides and the
deepest parts of the southwest approaches should continue to be withheld from
oil and gas licensing due to significant gaps in our knowledge of these areas.
36. Following the completion
of a SEA, operators are invited to apply for licences in selected areas, usually
as part of a licence round. The licence
application process includes an Environmental Competency Assessment. Applicants must have, or commit to develop,
an Environmental Management System (EMS) that satisfies the requirements of
OSPAR Recommendation 2003/5; must have adequate oil spill liability provision;
and must prepare a high-level Environmental Impact Assessment (EIA) to identify
the environmental sensitivities in the area that is the subject of the
application.
37. An EMS is designed to
achieve the prevention and elimination of pollution from offshore sources; the
protection and conservation of the maritime area against other adverse effects
of offshore activities; and continual improvement in environmental performance. All of the 81 licensed operators on the UKCS
have an independently verified EMS.
Project specific regulation
38. The granting of a licence
does not automatically confer any rights or permissions for activities within
the licensed area, and all proposed projects are subject to an environmental
assessment.
39. The Offshore Petroleum
Production and Pipelines (Assessment of Environmental Effects) Regulations 1999
implement the EC EIA Directive, and require the operator to undertake an
environmental assessment for a wide range of projects. For all new developments, significant
increases in production and large pipelines, the assessment must take the form
of an Environmental Statement that is subject to Public Notice.
40. The Offshore Petroleum
Activities (Conservation of Habitats) Regulations 2001 implement the EC
Habitats and Wild Birds Directives, and apply to all projects and
activities. Where a project or activity
could affect the integrity of a protected habitat or species, an Appropriate
Assessment (AA) is required to demonstrate that any effect would be
insignificant.
Activity Specific Legislation
41. In addition to the
project level legislation being applied to activities such as the drilling and
testing of wells, all minor pipelines and pipeline works and minor production
increases; all activities that could adversely affect the environment are
strictly regulated (further information can be found at Annex 2). Assessments
are required for:
·
seismic and other survey activity
·
the use and discharge of chemicals
·
the discharge of oil
·
atmospheric emissions
·
oil spill response
42. Most of these activities
are controlled by the issue of activity specific permits, consents or
authorisations containing legally binding terms and conditions. In addition, every offshore installation
must be the subject of an approved Oil Pollution Emergency Plan. The offshore sector is also included in the
EU Emissions Trading Scheme.
43. Whilst the majority of
the project and activity level legislation referred to above has been developed
specifically to control offshore oil and gas operations, the industry is also
subject to non-sectoral environmental legislation that is applied to all marine
activities. For example, all deposits
in the sea that are not covered by oil and gas industry legislation will be
controlled under the Food and Environment Protection Act (FEPA) 1985, Part II
Deposits in the Sea. The industry is
also subject to regulations relating to merchant shipping. The environmental controls are therefore
similar to those imposed on other marine activities and to those imposed on
terrestrial activities.
44. In addition, DECC
continues to work closely with industry to improve environmental performance,
by encouraging initiatives such as the increased use of reinjection for
produced water (a by-product of the production process that is contaminated
with reservoir hydrocarbons); the preferential use of chemicals with little or
no environmental impact; and energy audits to determine the most efficient way
to meet power requirements and reduce atmospheric emissions.
Environmental aspects of decommissioning
45. The EIA for a proposed
development will include consideration of the long-term impacts, including
those arising from decommissioning.
However, there is usually a lengthy period between project sanction and
decommissioning, and UK Government policy could change during that period. There is therefore an additional requirement
for a detailed assessment at the time of decommissioning, which is submitted as
part of the decommissioning programme.
Enforcement
46. DECC actively ensures
that industry is complying with the conditions included in environmental
approvals, following a four step process of audit and review, inspection,
investigation and enforcement. A
risk-based inspection strategy is used to prioritise the installations that
will be inspected. Inspections provide
evidence and assurance that operators have been, or are complying with the
requirements, restrictions or prohibitions imposed upon them by the relevant
statutory provisions and that pollution prevention procedures are being
implemented.
47. Offshore environmental
incidents involving oil and chemical spills to sea and notifications of
non-compliance with permitted activities are reported to DECC. All reported environmental incidents are
reviewed and where applicable action is taken to ensure that response
procedures are implemented to minimise the potential impact of any
pollution. Where any spill results in,
or there is a threat of, significant pollution, the Secretary of State’s
Representative (SoSRep) has the power to take control of the situation. Although
the SoSRep has never been required to take significant action in relation to
offshore oil and gas activities, there is close liaison between DECC, the
SoSRep, and the industry. Legislation requires
operators to carry out Oil Spill Response exercises to test and further
strengthen pollution response.
48. DECC also collaborates with the Maritime
and Coastguard Agency (MCA) to ensure that an effective pollution
identification aerial surveillance capability is maintained for UK offshore oil
and gas activities within the UK Pollution Control Zone. At the international level the UK supports
the activities of the Bonn Agreement (Maritime Pollution and Prevention).
49. Where oil and chemical
spills to sea occur, or breaches of regulatory requirements are identified, the
circumstances will be investigated. If it is considered necessary, enforcement action may be taken to ensure
that: preventative or remedial measures are taken to prevent pollution,
measures are put in place to achieve regulatory compliance and operators are
held to account when failures to comply occur. DECC has the power to revoke permits, enforce actions, prohibit
activities and to prosecute offenders.
There have been 11 reports to the
Procurator Fiscal and 9 prosecutions since 1998.
Finance
50. The vast majority of the
costs associated with the environmental regime, including the assessment of
applications, the issue of environmental permits, consents and authorisations
and the associated enforcement activity is met by the offshore oil and gas
industry. In addition to their project
costs, including any waste treatment and disposal expenditure, an application
or maintenance fee is levied for most permits. In order to streamline the handling of the large numbers of
permits required and to reduce the administrative costs where possible, there
are a number of e-commerce developments underway to simplify application and
reporting processes.
Case Study – Moray Firth
51. In 2006, a licence
application was received for an area in the Moray Firth that overlapped with a
Special Area of Conservation (SAC) for bottlenose dolphins. A draft Appropriate
Assessment (AA) was prepared to inform the licensing decision, which concluded
that the licensing could proceed, subject to appropriate mitigation measures
being employed for specific activities.
52. The AA was subject to
public consultation and several detailed responses were received, a number
of which expressed concerns about the interpretation of data that had been
included in the draft AA. Following a meeting with many of the relevant stakeholders in
January 2009, DECC proposed a substantial research programme, to be funded by
DECC and others, that will seek to provide firm data on the significance of the
proposed licence area for bottlenose dolphins (and other marine mammals) during
the summer months.
53. The stakeholders welcomed
this proposal and it is hoped that the research programme will commence in May
2009. No decision will be made on whether to issue a licence for this
area until the findings have been collated and fed into the AA process.
Consulation
54. Staff within DECC’s
Offshore Environment Unit in Aberdeen have a wide-ranging specialist knowledge
of environmental issues. Nevertheless,
the value of consulting with other government departments and bodies who may
have an interest in the proposals is recognised, and DECC routinely seeks the
views of the Centre for Environment, Fisheries and Aquaculture Science (an
agency of Defra), the Fisheries Research Services (an agency of the Scottish
Executive Marine Directorate), the Environment Agency, the Scottish Environment
Protection Agency, the Joint Nature Conservation Committee, Natural England, Scottish Natural Heritage,
the Countryside Council for Wales and many others. DECC also has a good relationship with industry, and regularly
meets both Oil and Gas UK (the industry representative body) and operators to
provide advice and discuss the legislative requirements, in addition to making
presentations at workshops, seminars and conferences.
Summary
55. Whilst the continued
development of the UKCS offshore oil and gas sector is considered to be crucial
to the security of the UK’s energy supply, the Government is committed to
ensuring that the impact of oil and gas activity on the environment continues
to be minimised. Legislation adopted over the last 10 years
has resulted in the development of a comprehensive, robust and effective
environmental regime, which is consistently applied, understood by industry and
fully satisfies the UK’s international obligations.
How effective is the current fiscal and regulatory
regime in which the industry operates?
56. The regulatory regimes as regards
licensing, and environmental protection, have been addressed in earlier
sections of this memorandum, and decommissioning is discussed later. This
section focuses on the fiscal regime.
57. The North Sea fiscal regime is one of the
main mechanisms for capturing for the nation the economic benefit from the UK's
oil and gas resources. In support of its
overall objective of maximising the economic recovery of the UK's oil and gas
reserves, the Government aims through the North Sea fiscal regime to encourage
investment in and production from the UKCS while ensuring a fair return for the
UK taxpayer from the UK's national resources. The regime has been developed and adjusted over time in response
to developments in the industry and the economic climate in which it operates, with
the introduction, amendment to and abolition of a number of different fiscal
measures.
58. Responsibility for the North Sea fiscal
regime is split between HM Treasury (HMT) and HM Revenue & Customs (HMRC). HMT
has overall policy lead and leads on policy formulation while HMRC supports HMT
and leads on policy maintenance. Both
work closely with DECC in developing policy and DECC plays a central role in
interaction between the fiscal departments and industry stakeholders. The following comments have been
agreed with HMT and HMRC.
59. The fiscal regime which currently applies
to oil and gas exploration and extraction from the UK and the UKCS consists of
three elements:
•
Ring Fence Corporation Tax
With some important
modifications (e.g. relating to capital allowances and losses), this is
calculated in the same way as the standard corporation tax applicable to all
companies, with the addition of a "ring fence" and 100% first year
allowances for virtually all capital expenditure. The ring fence prevents taxable profits from oil and gas
extraction in the UK and UKCS being reduced by losses from other activities or
by excessive interest payments by treating ring fenced activities as a separate
trade. The current rate for non-ring
fence profits is 28% and 30% for ring fence profits. HMRC has recently simplified the general capital allowances
regime but this does not impact on the 100% first year allowance rules within
the ring fence.
•
Supplementary Charge
This is an additional
charge of 20% (10% prior to 1 January 2006) on a company's ring fence profits
excluding finance costs. The
supplementary charge was introduced from 17 April 2002.
•
Petroleum Revenue Tax (PRT)
This is a special tax on
oil and gas production from the UK and UKCS. It is a field based tax charged on profits arising from
individual oil fields. The current
rate of PRT is 50%. PRT was abolished for all fields given development consent
on or after on 16 March 1993. PRT is
deductible as an expense against corporation tax and the supplementary charge.
The
marginal tax rate on new fields is thus 50%, while the marginal tax rate on the
older fields paying PRT is 75%.
60. A Ring Fence Expenditure Supplement (RFES) assists
companies that do not yet have any taxable income for corporation tax or the
supplementary charge against which to set their exploration, appraisal and
development costs and capital allowances. The RFES increases the value of unused expenditure carried
forward from one period to the next by a compound 6 per cent a year for a
maximum of six years. It applies to
all unrelieved expenditure from 1 January 2006. This is intended to help support new entrants into the basin.
61. The current North Sea fiscal regime gives
Government a system that: incentivises investment; creates a fair return to the
UK; is simple to operate; has accelerated payments (compared to other sectors);
and sets relief against profits / tax paid. It gives industry: competitive tax rates; immediate tax relief
for almost all revenue and capital expenditure; full tax relief for
decommissioning expenditure; and Government effectively sharing in risk and
reward. The regime is kept under
review. Since the start of 2006, the
Government has been engaged in discussions with industry about "structural
concerns" over aspects of the North Sea fiscal regime. These discussions were driven by concerns,
both within Government and industry, that elements of the existing fiscal
regime were having a negative impact on investment decisions – and therefore
running contrary to Government's wider objectives. Following almost two
years of discussions, Government published a consultation document in December
2007 setting out a range of proposed reforms to the regime to remove anomalies
and change elements that Government felt were potentially restricting
investment – most of these were taken forward in Budget 2008. None of these proposals involved changes to
tax rates.
62. A further package of reforms to the North Sea fiscal
regime was set out at Pre‑Budget
Report 2008 which should help encourage investment in the UKCS. Building on the changes to the North Sea
fiscal regime made at Budget 2008, and productive discussions with industry
over the past year - involving BERR/DECC as well as HMT and HMRC - HMT and HMRC
published a consultation document on the North Sea fiscal regime alongside Pre‑Budget
Report 2008. Supporting investment[4]
set out a further package of reforms
which should help encourage investment in the UKCS. In particular, the consultation document
raises the concept of a "value allowance" that could be built into
the fiscal regime to help bring forward challenging developments. A number of other proposed changes which
responded positively to representations by industry have been widely welcomed
by industry.
63. Discussions with industry
over the past year have been wide-ranging and the proposals set out at PBR 2008
covered a disparate array of issues. In
addition to the idea of targeted incentives (where Government wished to discuss
the potential of a value allowance), they addressed: the North Sea fiscal regime and chargeable gains taxation; a number
of fiscal issues arising from "change of use" from oil and gas
production to other energy-related activities such as carbon capture and gas
storage; and several other features of
the PRT regime, including issues concerning licence expiry and simplification
of some features of the PRT regime.
64. A consultation period
which ended on 13 February 2009 was intended to give stakeholders the chance to
comment on the Government's proposals for changes to the North Sea fiscal
regime and to engage further on the question of potential fiscal incentives, in
particular to discuss the concept of a value allowance incentive in more
detail. It is intended that, if
confirmed in light of the present consultation, the package of changes will be
finalised at Budget 2009 and legislated in Finance Bill 2009. Where possible, draft legislation for the
proposed measures has been published on the HMRC website to allow interested
stakeholders a chance to comment.
What
effect is the recession and the credit crunch having on the industry? What is the impact on the financing of
exploration and development?
65. The impact of the current economic
climate on oil and gas companies is significantly different from that on
industry more generally. The key
development of the past twelve months for this sector has been the substantial
fall in oil prices. From a peak of
almost $150 a barrel in July 2008, prices have fallen to the region of $40-50
more recently. Though almost all
current developments would have been financed and committed in an oil price
environment well below the recent peaks – oil prices varied between $50 and $70
a barrel over 2005 and 2006, for example - the sudden fall in prices and the
uncertainty about future prices dominate the business outlook for this sector. Companies have reacted by substantially
curtailing exploration expenditure, and by reviewing and in many cases
deferring discretionary investment which is not likely to lead to early
production.
66. The credit crunch, by contrast, has been
a less salient concern for many players.
The major oil companies, with substantial revenues from production, have
relatively little dependence on external finance. The largest companies have indicated their intention to
maintain capital investment levels at global level (ExxonMobil, Shell, Total,
BP), although within that broad intention, it appears that some projects may be
deferred while the participants seek lower material and supply costs to improve
the project economics. Some medium-sized
companies with significant production are similarly placed. Other medium sized companies, along with smaller
companies, are more dependent on external finance. Those without production, or facing heavy development
expenditure, can face serious financial pressures. A number of companies have been bought by stronger competitors,
and one prominent exploration company has gone into administration. It
is worth note that historically the banks most involved in lending for North
Sea developments are RBS and HBOS. The
current difficulties of these banks are a complicating factor in the outlook
for UKCS investment.
67. An aspect of the current financial freeze
with a particular impact on the oil and gas sector is the unavailability of new
equity. This is of particular concern
to smaller exploration companies, since banks have never, even in more
favourable times, been willing to finance exploration activity. If these companies cannot raise equity,
they will be unable to secure bank loans or project finance for new
developments, even if the developments are in themselves viable and project finance
otherwise available. Since most
developments involve a group of participants, the inability of even a junior
partner to raise finance may hold up or even stall development.
68. Companies in the supply chain, as opposed
to those engaged in exploration and production, are broadly speaking exposed to
a similar combination of circumstances to those faced by industry at large – a
substantial reduction in demand for their products and services, and a very
difficult financing climate. There are many reports of difficulties in obtaining
short-term credit or working capital.
Significant numbers of redundancies have been announced.
69. The combined impact on investment must
inescapably be a significant fall. As
noted earlier, the maturity of the UKCS as an oil province implies that
production will fall by some 10-15% a year if there is no new investment in
production. The benefit of the
sustained investment by the industry over recent years – running at an annual
rate of about £5 bn - has appeared in a markedly slower rate of decline of
around 5-7% a year. A recent survey of
activity intentions by Oil and Gas UK however estimated that capital
expenditure in development and drilling may fall by between £1 bn. and £2
billion in 2009. Industry’s view of
the geological attractiveness of the basin has not changed markedly - the
decline in investment is a reflection of a combination of lower oil prices
making some investments economically unattractive or higher risk, an
expectation that costs will fall in the near term, and a reduction in the
availability of funding whether internal, equity or bank borrowing. The impact will be felt particularly
sharply in exploration spending, though development work will also be affected
over time. A falling-off of
development investment can be expected to result in a progressive increase in
the rate of decline, as existing fields decline more rapidly and new fields are
delayed or cancelled. For employment,
the industry has estimated that each £1 billion drop in investment will result
in the loss of 20,000 jobs.
How are
the skills needs of the sector being met?
How transferable are these skills?
Employment numbers and age profile
70. The number of people in employed directly
within the industry is 350,000 with a further 100,000 employed in export
activities by supply chain companies, bring the total to 450,000. Within the
350,000 figure 34,000 are employed directly with oil and gas companies and
major contractors, 230,000 in the wider supply chain and the remaining 89,000
are jobs supported by the economic activity of the industry. This is an
increase in employment of about 30% since 2004. The number of females employed
by the industry has increased gradually over recent years with around 1,800
females travelling offshore, the majority of whom are employed in the catering
sector. The age profile of females is younger with average age being 34.1 years.
71. There are distinct clusters of high
employment within the industry around the UK, with the Aberdeenshire area
accounting for 39% of the total employment. The other regions with sizable
employment levels are East of England 5%, North West England 6%, and London and
the South East 21%.
72. The supply chain mixture of businesses
includes the following:
Engineering
Construction 16%
Structural
metal products 10%
Technical
consultancy 9%
Legal
services 5%
Business
and professional services 5%
Public
administration 4%
Renting
of machinery 3%
73. The average age for the whole workforce
is currently 41 years, which is the expected average age of a workforce in the
range 20 to 60 years.
Training
74. The industry has its own skills academy –
OPITO, based in Portlethen near Aberdeen.
The academy embodies the concept, which Government supports, of
employers taking ownership of the skills and workforce development agenda in
their sector. It is therefore able to
respond quickly to the specific needs, or emerging needs within, the
sector. OPITO exceeds DFES guidelines
for industry led and funded skills academies.
Their goal is to actively coordinate and consolidate the activities,
efforts and resources, needed to address employers’ demand for skilled people. They also have the objective of addressing
STEM (science, technology, engineering and mathematics) subjects within schools,
as most jobs in the industry require a strong engineering and technical
background.
75. OPITO is working with colleges and
universities in particular through the Technician Training programme, which is
an exemplar training provision. It was launched in 2002 and trains around 100
technicians each year with the course lasting around 3 ½ years and there are
currently 390 young people in training. Each year’s intake is determined through a demand forecasting
exercise to ensure employment for all those who finish their training. This is followed by two years practical
training and there is a 96% completion rate after 3 ½ yrs.
76. Salient points on OPITO:
- It has over 50
industry specific competence standards, created by employers to deliver
against the needs of the workplace.
- In 2007, 96,000
people were trained to the OPITO industry standards.
- Industry employers
directly invested approximately £49m in training to OPITO standards in
2007. The industry has directly invested £52m over 6 years in its
flagship Modern Apprentice scheme.
- OPITO exports UK training
into 24 countries.
- It works with
foreign Governments and national oil companies to help develop overseas
workforces to the UK standards.
- It has a direct
annual workforce investment of £10.1 m. for 2008 (schools, education
provision, teacher training materials, career and lifestyle road shows,
apprentice schemes, workforce development programs etc).
- New subsea
technician qualification introduced recently to meet emerging needs within
the sector.
- Runs a bespoke
training programme for ex-military personnel with relevant skills (a
valuable source of recruitment for the sector).
77. There are a high level number of training
providers within the industry, delivering OPITO standard training - a link on OPITO’s
website (http://www.opito.com)
lists these providers and the variety of training they provide.
78. Falke Nutec who provides offshore
survival training to the industry reports high levels of offshore training with
15,000 trainees going through the offshore survival course in the last year.
79. Industry, in conjunction with Step Change
in Safety, and OPITO has also developed an introductory training programme that
introduces the key safety elements required by all employees offshore. The course is being delivered by an OPITO
approved training establishment. Training will also be given to current
employees within the industry with refresher training being given annually.
80. The challenge for the
industry and OPITO now is to sustain training and
recruitment programmes through the current downturn, and ensure there is a strong
skills base maintained to enable the industry to maintain its capability and be
ready to take full advantage of the expected recovery in oil prices and
economic activity.
What are
the implications of an ageing existing infrastructure on the security of
supplies from the North Sea?
81. The main focus for security of supplies
in the upstream industry is on gas, because it is less easily transported from
other areas of the world and less easily stored compared to oil. As a result,
gas shortages could be felt by consumers much more rapidly than shortages of
fuels derived from oil. The following points are therefore directed at gas.
82. There are 36 pipelines supplying gas into
the UK; 32 from UKCS fields and 5 from other countries. These pipelines land at
16 reception terminals in 7 separate locations around the coastline. The
pipelines typically vary from 16” to 44” to diameter, and can be in excess of
200 miles long. Once onshore, the gas is fed into the pipelines forming the
National Transmission System (NTS), and then through local distribution systems
to industrial and domestic consumers.
83. For UKCS fields, there are a large number
of platforms and facilities that produce gas. These vary from wellhead valves
on the seabed, up to large production platforms accommodating 200 people and
containing large amounts of equipment. A network of smaller pipelines is used
offshore to connect more remote fields into main production or collection
platforms (termed ‘hubs’), from which pipelines run to shore.
84. Gas production first started in the UKCS
in 1967 from BP’s West Sole field, where the platforms and pipelines are still
in operation. The development of platforms and pipelines has continued steadily
from the late 1960s to the present day, moving from early infrastructure in the
Southern North Sea into deeper water areas further north and eventually to the
west of the Shetland Islands. New developments are still taking place in all
areas of the UKCS. The graph below shows the number of fields starting
production over time:
85. Many platforms and pipelines were
originally designed for a life of 20 to 30 years. Hence a lot of these
facilities are now at or beyond their design life. The design life was
originally linked to the expected length of production, but this has been
extended for many facilities due to better than expected reservoir performance
or new nearby fields being connected to the platform. For example, three new
fields have previously been connected into the West Sole facilities, and a
further two new fields will soon be connected, leading to a further 10 years or
more of production from the combined fields.
86. Calculation of a design life has not
always been carried out rigorously, typically being based on an assumed rate of
corrosion in main equipment items and sometimes crude assessments of the
accumulation of fatigue damage in main structures. The actual rate of
deterioration depends on many factors, including material and manufacturing
specifications, the reservoir fluid composition and condition, the operating
environment and the maintenance philosophy. The successful operation of older
facilities demonstrates that careful management of all the factors affecting
deterioration is the key to extending the design life.
87. It is generally accepted that the low oil
and gas prices during the 1990s led to reduced effort being spent on
maintenance. This has led to increased ‘downtime’ of offshore facilities, and
was one of the main drivers for DECC to start the Stewardship initiative for
producing fields in 2004. At around the same time, the Health and Safety
Executive (HSE) started a Key Programme on Asset Integrity (KP3) on the basis
of similar concerns.
88. The HSE report on KP3 was publicly
released in 2007 and described a number of difficulties with maintenance
management systems and overall condition of infrastructure. However, it also
concluded that some of the main components of platforms (main hydrocarbon
boundary, jacket and primary structural integrity) were reasonably well
controlled. Industry has responded positively to the challenges laid down in
the KP3 report, and the indications are that maintenance activity has increased
in recent years as a result of this programme and the DECC Stewardship
initiative.
89. The table below summarises the
contributions of various pipelines to UK gas supply, grouped by terminal. The
percentage contributions are averaged for the 2008/09 winter to date.
|
Pipeline |
Source
of gas |
Percentage
contribution to UK winter supply |
Date of
construction |
|
1 |
Foreign |
17 |
2005 |
|
2, 3 |
UKCS,
Foreign |
17 |
1977 to
1978 |
|
4, 5, 6 |
UKCS |
9 |
1992 to
2004 |
|
7 |
UKCS |
7 |
1993 |
|
8 |
UKCS |
7 |
1999 |
|
9 |
Foreign |
7 |
2006 |
|
10 |
UKCS
storage |
6 |
1984 |
|
11, 12,
13 |
UKCS |
6 |
1982 to
2003 |
|
14, 15,
16 |
UKCS |
6 |
1968 to
1990 |
|
17, 18,
19, 20 |
UKCS |
5 |
1971 to
1993 |
|
21, 22 |
UKCS |
4 |
1984 to
1994 |
|
Others
(14) |
Mostly
UKCS |
6 |
1967 to
1995 |
Summary
90. It is possible for offshore
infrastructure to be operated successfully beyond the notional design life,
provided that this is properly resourced and managed by the operators. DECC and other regulators are seeking to
ensure that this takes place. There is
significant diversity and robustness in the arrangements for gas supply from
the UKCS and abroad. DECC is
continuing to work with industry to better understand and improve where
possible the resilience of gas supply arrangements.
Is the right policy framework in place
to manage the decommissioning of that infrastructure as resources are depleted?
91. The Government has a responsibility to
ensure that all offshore installations and pipelines are decommissioned with
regard to safety, environmental, social and economic impacts. DECC manages a decommissioning regime that
addresses these factors and conforms to international commitments and public
expectations, whilst minimising the risk that the taxpayer might have to step
in if companies default. Legislation
has been updated to take account of changes in industry practices and the
growth of smaller players in the sector.
DECC balances the national interest in maximising oil and gas activity
and use of the offshore infrastructure
against the responsibility for ensuring effective decommissioning.
Legislative background
92. Oil and gas decommissioning is regulated
by Part IV of the Petroleum Act 1998, as amended by the Energy Act 2008. Notices setting a decommissioning obligation
on all the companies responsible for an installation or pipeline are served at
the start of field life. If interests
change hands, the new company is given an obligation notice and we release the
selling party from their liability, if the risk is acceptable. Towards the end of field life the companies
are asked for a decommissioning programme which must be approved by the
Secretary of State. The parties are
then responsible for carrying out the work specified in the programme.
93. Obligations to carry out an approved
programme are joint and several. If one
party defaults the other companies must pay the defaulting party’s share. This is an important concept and helps
mitigate the risk and protect the taxpayer in a potential default situation.
Decommissioning scope and programmes
94. The industry has begun to decommission
the 500 installations and 35,000 kilometres of pipelines on the UKCS but with
UK oil and gas continuing to supply around 70% of our prime energy demand,
decommissioning work will be spread over the next 40 or more years. The cost of this work is currently estimated
at £23 billion with individual installations costing from £5m to £300m.
95. It is important that this ongoing
decommissioning work is carried out in a sound manner consistent with our
international obligations. The OSPAR Convention
came into force in 1998. Ministers adopted a binding Decision, OSPAR
Decision 98/3, to ban the disposal of offshore installations at sea. The Decision recognised there would be
difficulty in removing the ‘footings’ of large steel jackets weighing more than
10,000 tonnes and in removing concrete gravity base installations. As a result derogations may be granted in
these cases. But there is a presumption
that all installations will be removed entirely and exceptions will only be granted
if an assessment and consultation process shows that there are significant
reasons why leaving in place is preferable to re-use, recycling and final
disposal on land.
96. The OSPAR Decision is the principal
international ruling regarding decommissioning and in the majority of cases
installations will be brought on land for recycling and waste disposal. However, DECC is keen to encourage the
re-use of facilities e.g. for other oil and gas developments, gas storage,
renewables or carbon sequestration and companies have to consider these options
in their plans. The Energy Act 2008
extends the oil and gas decommissioning regime to offshore gas storage and
carbon sequestration projects.
97. Decommissioning programmes need to
consider the safety, environmental, social and economic impacts of a
project. All programmes must include an
environmental impact assessment which addresses the impact on climate change by
detailing potential emissions and consumption of natural resources and energy.
98. Transparency and openness is an important
aspect of the regime and DECC consults other departments and agencies and
requires companies to consult the public; the outcome of the consultation must
be reported in the programme before approval by the Secretary of State.
99. DECC publishes comprehensive guidance
notes explaining its policies, the programme approval process and the factors
that companies should consider. The
notes were revised in January to take account of comments from industry and
clarify how the new Energy Act provisions will be implemented.
Changing industry practices and update of legislation
100. The Petroleum Act 1998, which consolidated
earlier legislation, was drafted over 20 years ago when most fields were in the
hands of the oil majors. Since then the
majors have sold many assets to independents and smaller companies, which have
also developed new fields. These
companies have fewer financial resources than the majors and bring an increased
risk that they might not be able to meet their decommissioning
liabilities. New business models and
commercial arrangements have also meant it has not always been possible to
share liabilities equitably between all the companies responsible for an
installation or pipeline because of the wording of the legislation.
101. The Energy Act 2008 addresses these issues
by closing a number of gaps in legislation and giving the Secretary of State
power to require financial guarantees whenever he believes that the risk to the
taxpayer is unacceptable. Prior to the
Energy Act the Secretary of State could only require guarantees to be provided
once a decommissioning programme had been approved and programmes are only
developed towards the end of field life when there is a clear understanding of
technical abilities and legislative requirements. The Energy Act enables new projects to go ahead with the
assurance that the taxpayer will be properly protected.
102. There was full and open consultation with
industry and other interested parties on the new legislation and where
possible, industry concerns were accommodated.
In particular, the Act clearly
specifies which licensees can be given a decommissioning obligation, addressing
an issue created by the way that licence partners divide their interests under
commercial agreements. DECC continues
to work closely with industry to ensure we understand their concerns and our
requirements remain fit for purpose.
Risk assessment
103. DECC uses a transparent risk assessment
process to determine the risk of companies defaulting on their decommissioning
obligations. This assessment process
supports decisions whether to require financial guarantees for new projects
when licence interests change hands or when company circumstances change.
104. The costs of decommissioning the installations
for which a company is responsible are compared to the net worth on its balance
sheet. We look at all the company’s
UKCS interests and the strength of any corporate group to which they belong. Given the current financing climate, we also
look at cash flow and debt repayment data.
If the costs of the project, or the company’s UKCS liabilities, are more
than 50 per cent of the net worth, DECC will discuss the situation with the
company to confirm its assessment.
105. If the assessment indicates a medium or
high risk we will check if the company has a parent or other associate which
has sufficient assets to cover the decommissioning costs. Decommissioning obligations can be placed on
the associated company to spread the risk.
If the risk cannot be mitigated, DECC will require a financial guarantee
after first giving the company an opportunity to make representations, and
consulting the Treasury on any implications for tax.
106. Security can be cash or bank guarantee such
as a letter of credit. Guarantees need
to be from a suitably rated financial institution and the current down grading
of banks and reluctance to lend money restricts industry options. DECC recognises this and invites alternative
forms of security whilst ensuring our requirements remain proportionate. Despite the increase in smaller companies
operating in the UKCS, financial guarantees have only been necessary in a
minority of developments and security costs are not a significant element in
project budgets.
Summary
107. DECC operates an efficient regime ensuring
sound decommissioning is carried out in a manner consistent with the UK’s
international obligations and public expectations. A flexible approach enables decommissioning policy to take
account of industry concerns and the open and transparent process ensures
stakeholder access. The risks of
company defaults are monitored and assessed throughout field life and
mitigation measures instigated if the risk to the taxpayer is unacceptable.
108. DECC recognises the impact of liabilities
on trading of licence interests and future developments and works with the
industry to minimise any restriction on future oil and gas activity. DECC recognises the opportunities for re-use
of structures for other energy or climate benefits. The Energy Act 2008 has updated the decommissioning regime to
meet the requirements for future oil and gas activity. Clear guidance and a
transparent risk assessment process help companies understand their
position. This is particularly
important as Government and industry cope with the impact of the banking crisis
and the current low oil price.
March 2009
ANNEX 1: Charts
Chart 1
Chart 2
Chart 3
Chart 4: Gas pipeline
alternative routes for West of Shetland developments
ANNEX 2
Key
Activity-Level Environmental Legislation
·
The Offshore Chemicals Regulations 2002 (as amended) - control
the use and discharge of all operational chemicals, and implement OSPAR Decision
2000/2 on a harmonised mandatory control system for the use and reduction of
the discharge of offshore chemicals.
·
The Offshore Petroleum Activities (Oil Pollution, Prevention and
Control) Regulations 2005 - control all deliberate oil discharges. Major discharges are waste streams
contaminated with reservoir hydrocarbons, e.g. produced water.
·
The Offshore Combustion Installations (Prevention and Control of
Pollution) Regulations 2001 (as amended) – control the quantities of noxious
pollutants emitted from combustion equipment on qualifying installations, and
implement the Integrated Pollution Prevention and Control Directive for
offshore oil and gas installations. The
regulations ensure that Best Available Techniques are employed to reduce
emissions.
·
The Greenhouse Gas Emissions Trading Scheme Regulations 2005 (as amended) –
authorise the emission of greenhouse gases (currently only CO2), and
implement the EU Emissions Trading Scheme.
·
The Offshore Installations (Emergency Pollution Control) Regulations
2002 -
ensure that operators have appropriate measures in place to prevent oil spills
and to ensure that if they occur they are handled effectively.
·
The Merchant Shipping (Oil Pollution Preparedness, Response and
Co-operation Convention) Regulations 1998 - require operators to prepare and submit
an Oil Pollution Emergency Plan (OPEP), covering all activities where there is
a risk of hydrocarbon spill and detailing the action to be taken should a spill
occur.