Supplementary memorandum submitted by
Ofgem
I welcomed the opportunity to meet with you
and other members of the Committee last month. Following our meeting,
you asked us to give you some background information on new electricity
generation requirements; the windfall to generators under the
European Emissions Trading Scheme; the causes of fuel poverty;
and the link between gas and oil prices.
NEW ELECTRICITY
GENERATION REQUIREMENTS
Peak electricity demand in Britain is currently
around 62 gigawatts (GW). This compares with a total generating
capacity of 75GW. Of that 75GW, approximately 39% is from coal;
38% from gas; 14% nuclear; 5% oil; 2% hydro; and 2% wind. In addition
there is an electricity interconnector with France which is capable
of importing or exporting about 2GW.
However, Britain's nuclear power plants are
ageing and many coal and oil-fired plants will have to close as
a result of the Large Combustion Plant Directive (LCPD). The LCPD
requires large generators to meet stringent air quality standards
by January 2008 or to opt out of the LCPD. If they opt out, they
must close by the end of 2015 or after 20,000 hours of operation
from January 2008, whichever is soonest. Some 12GW of coal and
oil-fired generating plant falls into this opted-out category.
All of this plant, some 15% of Britain's present total capacity,
will have to close by the end of 2015. In addition, according
to current timetables, 7.4GW of nuclear generation capacity will
have closed by 2020. Another 2.4GW is due to close by 2023. Only
Sizewell B, the pressurised water reactor (PWR) in Suffolk, has
a significant lifespan beyond 2020; it is due to close in 2035.
However, plant life extensions should allow some delay in these
closure dates.
The closure of existing plant means that there
is a substantial requirement for new build. Several factors will
affect the level and nature of new build:
— Market prices and economics:
Expected levels of coal, gas, carbon and power prices are the
major factor driving investment in new capacity. Higher carbon
prices will tend to skew investment towards lower carbon generation
plant, such as gas and nuclear. However, market participants are
unable to predict the future. In addition, they value diversity,
particularly if market and political signals are uncertain. As
a result, generators are likely to favour a diverse mix of generating
assets in the future, including some new coal.
— Planning: The biggest single
obstacle faced by new generators and transmission owners will
remain planning provisions—particularly for major electricity
infrastructure. The UK Government's Planning Bill aims to improve
the planning process for major infrastructure projects, but this
legislation would apply only to England and Wales, where planning
delays are less acute at the moment.
— Grid connections: The electricity
transmission networks—the wires which carry electricity
from generators to customers—require investment to enable
more generation to connect. New lines need to be built, especially
to help connect more renewables, and better use needs to be made
of existing lines. Ofgem is playing its part by allowing a 100%
increase in investment in the energy networks and by reviewing
the arrangements for allowing generators to gain access to the
networks.
— Skills: The power sector has
an ageing workforce and the Sector Skills Council estimates that,
without a marked increase in recruitment and training, a significant
shortage of skills could develop as early as 2013. Building significant
numbers of new power stations and new network infrastructure would
require a strengthening of the science, engineering, project management
and on-site trade/technician skills base. The longer lead times
for nuclear power would allow the industry more time to plan ahead.
— Lead times: The whole process
from decision to invest through to start up can take about five
years for a combined cycle gas turbine (CCGT) power station: two
years for design, planning consent, project planning and permitting,
two for construction and six months for commissioning. A coal-fired
power station might take around seven years, of which four to
five years would be needed for construction. A new nuclear power
station might take around five years for construction but has
an extended licensing period that would extend the overall programme
towards ten years. In addition, there could be bottlenecks in
the supply chain depending on demand for construction from other
sectors.
— Subsidy: The renewable electricity
industry in Britain is supported by a subsidy through the Renewables
Obligation (RO). The proportion of Britain's energy coming from
renewables has increased since the RO was introduced but by far
less than is required to meet the target. Other countries have
different support mechanisms, eg feed-in tariffs. Whether they
have more or less renewable energy than Britain will be influenced
partly by the support scheme but also by other factors—such
as a lack of planning constraints and the availability of spare
transmission capacity.
WINDFALL TO
GENERATORS UNDER
THE EU ETS
The European Union Emissions Trading Scheme
(EU ETS) aims to reduce emissions of carbon dioxide and combat
the serious threat of climate change. It works on a "cap
and trade" basis:
— EU Member State governments are required
to set emissions limits for all installations in their country
covered by the scheme.
— Each installation is then allocated
allowances equal to that cap for the particular phase in question.
The allocation of allowances is set out in the National Allocation
Plan for the particular period. The first phase of the EU ETS
ran from 2005-07; Phase II runs from 2008-12.
— Installations can meet their cap
by reducing emissions below the cap and selling the surplus allowances.
Alternatively, they can let their emissions remain higher than
the cap and buy allowances from other participants in the EU emissions
market in order to meet the cap. A carbon market has emerged which
enables this trade in allowances to happen.
The UK National Allocation Plan has granted
electricity generating companies—free of charge—a
proportion of the tradeable emissions permits they need to meet
their obligations under the scheme. Ofgem has long argued that
these permits should be auctioned to energy companies rather than
given free of charge. We are pleased that 7% are being auctioned
from 2008 and hopefully that all permits will be auctioned from
2012.
Phase II of the EU ETS runs from 2008-12. Although
the generators receive most of their required allowances for free,
the full traded allowance price is reflected in the price of electricity
traded on the wholesale market. This is because:
— the generators who need to buy extra
allowances to cover their emissions will, as you would expect,
factor the cost of these allowances into their price;
— the generators who hold enough allowances
can sell them. They will only generate if the electricity price
is high enough to compensate them for using, rather than selling,
their allowances.
The free allocation of allowances therefore
increases generators' profits over the five years of the phase.
With carbon prices up 25% in the past year, the £9 billion
windfall that Ofgem identified in January covering the period
from 2008-12 is now worth in excess of £11 billion calculated
at today's market prices.
It is less clear whether the full cost of allowances
is passed through to end user prices. We believe that is certainly
the case for the sales to large and medium industrial and commercial
suppliers and largely the case for domestic customers. There is
some evidence that, at times of rapidly rising prices, some of
the vertically integrated power companies smooth their price increases
to domestic consumers by cross-subsidising between generation
and supply. The surplus generation profits from the EU ETS increase
their ability to do this.
Ofgem originally highlighted this issue in its
response to the Government's Energy Review in 2006. Ofgem also
highlighted that by reducing the free allocation of allowances
to generators to the maximum extent possible would mitigate this
effect and could provide for measures to alleviate fuel poverty.
FUEL POVERTY
Fuel poverty has three main causes: low incomes,
poor housing and high energy prices. After a considerable period
of decline from 1996, fuel poverty is now rising and current estimates
suggest that 4.5 million households could be fuel poor.
The above factors have not contributed equally
to changes in fuel poverty. The Government's 2007 Fuel Poverty
Annual Report stated that, "For the reduction in overall
fuel poverty between 1996 and 2005, with all the changes in methodology
excluded, nearly three quarters was due to increased incomes,
around a fifth was due to energy efficiency measures, with the
remainder due to energy price reductions." The Scottish Household
Condition Survey 2002 attributed the reduction in fuel poverty
in Scotland to the following factors: 50% to increases in household
income, 35% to reduced fuel prices and 15% to improvements in
energy efficiency.
I have written to you separately with further
information on the scale of the fuel poverty challenge; the steps
to target existing measures under the Fuel Poverty Action Programme;
and our view of the work that still needs to be done.
Oil and gas price link
There is a strong correlation between oil prices
and wholesale gas prices. The high oil price can affect UK gas
prices via two main mechanisms:
— European contract prices and their
impact on Britain, via arbitrage across the interconnector; and
— any remaining British gas supply
contracts that contain oil-indexation.
European contract prices
The European gas price is affected by the contractual
link between oil (and a number of oil-related products) and prices
for gas in contracts to supply gas into Europe. In most European
supply contracts gas prices are indexed to movements in oil prices
with a lag of between three and nine months. This contractual
link affects GB prices due to the operation of the interconnector
and the arbitrage in trading based on relative prices at Zeebrugge
in Belgium and at the National Balancing Point (NBP) in Britain.
This occurs in two main ways:
— Summer effect: Higher European prices
during summer will tend to increase UK gas exports across the
interconnector, as UK suppliers seek to sell surplus UK supplies
into the higher priced continental market. This pushes up UK summer
gas prices, which in turn increases the price of gas injected
in to storage for use during the following winter. The cost of
this higher priced gas, added to storage and cycling costs, can
push forward winter prices higher to the extent that storage is
expected to be the marginal source of gas on a significant number
of winter days.
— Winter effect: During winter, GB
gas demand is typically greater than UK Continental Shelf (UKCS)
supply, with European imports, via the interconnector, and storage
providing the balance of supplies. When this occurs, the price
of the European gas will influence the GB gas price, either directly,
when imports are the marginal source of supply, or indirectly
through storage prices as outlined above.
UKCS oil-indexation
In Britain some long-term gas contracts are
still linked to indices that include oil prices. However, these
contracts represent a very small proportion of UK gas supplies.
Since market liberalisation in the early-1990s, these contracts
have not tended to influence British gas prices. When there was
a significant surplus of UK supplies, gas from these relatively
high-priced contracts was not required to meet demand other than
on a very small number of days of high demand. As the supply/demand
balance has tightened these contracts' influence on British prices
will increase.
5 June 2008
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