Memorandum submitted by the Department
of Energy and Climate Change
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.[4]
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 1 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 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.[5]
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[6]
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, capital investment of some £5 billion per
annum in new and existing fields (see Chart 3 in Annex 1) 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 five
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
mainland Scotland. A range of alternative options including power
generation and the production of liquefied 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 2007 a 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 cubic metres per
year (cm/y) of gas transportation capacity (equivalent to about
5% of UK annual demand), involving 10 licensees in three 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/y 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
2008-09 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;
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.
Consultation
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.
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
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% 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[7]
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 12 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 noting 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 billion—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 billion 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 employed directly within the industry
is 350,000 with a further 100,000 employed in export activities
by supply chain companies, bringing 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 the
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 sizeable
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 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 3years.
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
£49 million in training to OPITO standards in 2007. The industry
has directly invested £52 million over six 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 million 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 five from other countries. These pipelines
land at 16 reception terminals in seven 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 £5 million to
£300 million.
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 it 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% 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 downgrading 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.
4
See: https://www.og.berr.gov.uk/information/bb_updates/chapters/reserves_index.htm
Back
5
The production projections for 2008-13 are as published at
https://www.og.berr.gov.uk/information/bb_updates/chapters/Section4_17.htm.
After 2013, oil production is assumed to decline at 4.5% per annum
and gas production to decline at 5.2% per annum.
The demand projections are consistent with the Updated Energy
and Carbon Emissions Projections published at
http://www.berr.gov.uk/whatwedo/energy/environment/projections/index.html)
in November 2008.
Back
6
Higher oil prices and technological developments could also increase
the extent to which existing discoveries are commercial; improved
geological knowledge can also affect the estimates of the commerciality
of existing discoveries. To date, recent increases in oil and
gas prices have not resulted in a significant reclassification
of the status of existing uncommercial discoveries to probably
or possibly commercial; some reclassification has occurred but
the extent has been masked by downgrading of reserves for technical
reasons. Back
7
Available from http://www.hm-treasury.gov.uk/prebud_pbr08_northsea.htm. Back
| 
