Memorandum by Mr Colin Gibson
The author has more than 40 years' experience
in the electricity supply industry, including five years as Power
Network Director of National Grid Group (1993-97). This post carried
responsibilities covering the electricity transmission system
of England and Wales for Commercial Development, System Design,
Asset Management, and System Operation. The author was General
Manager of the generation business of National Grid through the
period of privatisation up to his joining the main Board. Prior
to this he held various posts in planning, design, and operations
in the electricity supply industry in Scotland.
SUMMARY
The evidence presented proposes that the extra
system costs caused by the intermittency of renewables should
be for the account of the renewable owners and thus part of the
competitive generation market. These system costs occur in both
the short-term operational time scale, and in the long term planning
time scale. An alternative market structure is suggested which
will ensure that long term risk to Security of Supply is contained.
Whilst the author believes the costs given to
be of the correct order, it is more important that the principle
be established that all the costs imposed on the system by a development
are carried by that developer within the competitive generation
market.
1. FITTING RENEWABLES
INTO THE
GB SYSTEM
1.1 GB is essentially an "islanded"
system—the only major interconnection is the link to France.
This is important since electricity cannot be stored in any meaningful
and practical manner on a large scale, so GB must ensure that
it can match demand in an operational timescale (frequency control);
and match demand in a planning timescale (contain the risk to
Security of Supply).
1.2 Some forms of renewables present problems
for both frequency control and Security of Supply risk. Wind farm
output is both intermittent and unpredictable: tidal power is
intermittent but predictable.
1.3 The link to France is limited in both
capacity (2GW), and by virtue of its being direct current and,
therefore, limited in its ability to contribute to frequency control.
On the other hand, North America and the European mainland are
strongly interconnected over a large land area with varying weather
patterns. They are, therefore, better positioned to accommodate
a larger proportion of renewables such as wind turbines with intermittent
and unpredictable output.
2. TECHNICAL
LIMITS TO
RENEWABLE ENERGY
2.1 In an operational time scale, these
limits are dictated by the capability of other operating plant
to provide frequency control to compensate for the intermittency
of wind. In a planning time scale, the low probability of wind
farms generating at the time of system maximum demand would require
the construction of `back-up' plant to contain the risk to Security
of Supply.
2.2 The former (frequency control) requires
that extra `response and/or reserve' plant is carried on the system.
The cost of this (taken to be some £3/MWh of wind output)
is not attributed to the wind farm as part of the competitive
generation market, but it becomes part of the cost of running
a stable system. This cost should be charged to the wind farms.
2.3 The latter (containing Security of Supply
risk) is not recognised in BETTA as a separate requirement, nor
is it the responsibility of a particular party. There appears
to be an assumption that the market in energy [MWh] will provide
sufficient incentive for new plant capacity [MW] to be built to
provide the necessary plant planning margin to contain the risk.
However, the addition of wind farms, compared to thermal plant,
will, because of intermittency, increase the risk. The capital
costs of building "back-up" plant (open cycle gas turbines,
say) to contain the risk should be, in principle, part of the
competitive generation market and charged to the wind farms. These
costs could amount to some £20/MWh on the basis that 100MW
of wind would have to be supported by 80MW of gas turbines.
2.4 Initially, the extent to which renewable
plant can be connected to the system will be limited by the amount
of "response and reserve" and "back-up" plant
available and for which the customer is prepared to pay. Ultimately,
the large amount of renewables proposed would make the system
frequency very difficult and expensive to control. If all these
costs were charged to the generator then the market would decide
the limits for renewables.
2.5 An alternative to the provision of "back-up"
plant would be to recognise power capacity [MW] as a separate
product to be met by competitive tender for long term contracts.
Generators would receive fixed annual payments for providing assured
capacity at peak demand times effectively covering their capital
charges. The greater the generator's confidence of delivering
power capacity at times of peak, the greater the proportion of
installed capacity it would commit. This arrangement leaves the
energy market free to optimise operational costs. Because the
capacity payments would be "high quality earnings" and
the energy market would be operating more efficiently than at
present, the overall costs will be lower, and the Security of
Supply risk contained.
3. TECHNOLOGICAL
ADVANCES
3.1 Given the differences in total costs
(see 7 below) it is unlikely that further technological advances
will make renewables economically competitive. Other types of
generation could also make technological advances thus maintaining
the differential.
4. SUPPORT AND
SUBSIDIES
4.1 Currently, in the main, subsidies to
renewables are being provided by the electricity consumer—not
by Government. This comprises not only ROCs but also the costs
imposed by intermittency and the costs of extra transmission plant
if the wind farms are located remotely eg north west Scotland.
In a properly competitive market these costs would be met by the
wind farm developer.
4.2 Policy should be directed towards providing
a competitive market which is equitable to all types of generation
without subsidies and without preferential treatment.
5. TRANSMISSION
NETWORKS
5.1 The amount of investment in transmission
will be dictated by the location of the renwewables. In an endeavour
to achieve higher load factors, it is proposed to build wind farms
in remote locations and offshore. Building in north west Scotland,
for example, will require not only reinforcement of the local
system but also reinforcement of the GB system all the way to
the south of England. This is evident from examination of National
Grid's Seven Year Statement.
5.2 However, account should be taken of
the low load factor of wind farms and their probable output at
the time of winter maximum demand in deciding on transmission
reinforcement. Therefore, in many cases, justification on technical
requirements will not be established, and a decision will need
to be made on economic grounds based on "constrained off
payments".
6. EXTERNAL COSTS
6.1 No comments.
7. GENERATION
COSTS
7.1 A useful source for these costs is "The
Future of Nuclear Power" which uses the concept of "levelised
cost". This gives the costs of nuclear, clean coal, and gas
generation at around £40/MWh. It gives the costs of offshore
and on shore wind as £85/MWh and £55/MWh respectively.
However, these wind costs do not appear to include the extra costs
of intermittency of wind nor the extra costs of transmission.
Also, the specific capital costs for wind farms have increased
since the data for this study were collected.
7.2 The costs for the intermittency of wind
generation could add some £25/MWh making the costs of offshore
and onshore £100/MWh and £80/MWh respectively. The costs
of extra transmission requirements are difficult to calculate
but the cost of the Beauly-Denny line alone which was proposed
to accommodate about 2GW of wind in north west Scotland would
add £8/MWh. Extending this to cover the GB system (see 5.1
above) could easily incur costs of the order of £20/MWh.
This would make the total cost of onshore wind generation as seen
by the customer about £100/MWh—an increase in cost
of £60/MWh compared to a mixture of nuclear, coal, and gas.
So, for say 10GW of wind, the extra cost would be £1.6 billion
p.a.
7.3 For the Severn Barrage, the capital
charges and operating costs would be some £73/MWh, the cost
of containing the risk to Security of Supply some £12/MWh,
and extra transmission £3/MWh, giving £88/MWh in total.
Because this scheme is predictable (though intermittent), it could
make a contribution to stabilising system frequency and voltage,
worth say £7/MWh giving a net cost of £81/MWh. To make
the scheme competitive with nuclear, coal, or gas, credits for
flood control and road usage would have to sum to £40/MWh.
8. COMPARISONS
WITH TRANSPORT
AND HEATING
8.1 No comments.
9. EU TARGETS
9.1 No comments.
10. COSTS OF
CARBON
10.1 The cost comparisons given above include
the cost of carbon.
11. BIOFUELS
11.1 No comments.
9 June 2008
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