Memorandum by Professor Michael Laughton
Energy from renewable sources would result in
significant increases to the present electricity supply cost levels.
This submission seeks to explain and to quantify factors underlying
these circumstances from a power systems engineering perspective.
The feasible cost limits for consumers are not addressed. Instead
the focus here is on the costs arising from maintaining power
supply security, ie "Keeping the lights on".
Extra costs arise mainly from the:
Simple substitution of existing lower
cost electrical energy supplies by higher cost alternatives (+
6% to + 33%).
Higher system operating costs due
to lower utilisation of necessary existing or new conventional
generating capacity, operating at lower load factors and thus
lower efficiency and higher long-run marginal costs (+12% to +39%).
Extra transmission network capital
costs for network modifications and additions that will be required
for the accommodation of renewable generation occurring in geographical
locations without adequate, or even any, existing network connections.
Extra constrained-off payments to
renewable plant unable to access the electricity market because
of network constraints (potentially a significant future revenue
stream for renewable plants in Scotland).
With regard to current costs of supply a May
2008 update of the widely used analysis of the costs of generating
electricity from the leading firm of Consulting Engineers, PB
Power, is shown in Table 1.
The costs of renewables can be seen to be considerably
higher than those of coal, gas and nuclear plant; therefore it
can be concluded without any reservation that if, say, 20% of
electricity generation is supplied by renewables displacing the
equivalent contributions from a combination of existing conventional
plant, then the average generation cost and hence price of electricity
supplied will increase.
COSTS OF ELECTRICITY GENERATION (MAY 2008)
|Energy Source||Cost of Electricity
|Open Cycle Gas Turbines||7
|Integrated Gasification Combined Cycle (IGCC)
The present day supply of electricity in the UK comes from
three main sources of energy namely, coal, gas and nuclear. The
approximate respective shares of the electricity market met by
these fuels are shown in Table 2.
FUEL USED ON AN ELECTRICITY SUPPLIED BASIS IN THE UK
|Other fuels and renewables||4.5
Applying the costs of table 1 to the percentage contributions
of energy sources in Table 2 gives a weighted average generation
cost of 4.3p/kWh.
The effects on the present electricity supply system of simply
substituting the costs of energy obtained from these conventional
sources with the costs of electricity from renewable energy sources
and neglecting all other costs is shown in Table 3. Six hypothetical
energy contributions are considered replacing equivalent amounts
of either gas or coal-fired electricity, or all of nuclear plus
an appropriate amount gas or coal derived electrical energy from,
in turn, 20% onshore wind, then alternatively 10% from onshore
and 10% offshore wind and finally adding a 7% contribution from
INCREASE IN PRESENT DAY ELECTRICITY GENERATION COSTS FROM
THE SIMPLE SUBSTITUTION OF EXISTING CONVENTIONAL SOURCES WITH
HIGHER COST RENEWABLE ENERGY
% of Coal/gas
equivalent % of
|20% onshore wind||0.28p/kWh|
= + 8.3%
10% offshore wind
= + 16.9%
10% offshore wind
+ 7% tidal
= + 30.5%
= + 32.4%
The results show that even with this basic substitution of
supplies the generation costs increase from between 6% and 33%.
Applied across the total primary and secondary production in 2006
of approximately 360 TWh pa from the major power producers these
increases translate into extra generation costs of between £1
billion and £5 billion pa.
3. HIGHER SYSTEM
Unfortunately the problems of calculating the extra costs
cannot be solved by simply the substitution of alternative energy
source costs as above in Table 3. Electricity supply depending
on renewables adds a whole new set of problems and also costs
The power demand on the national grid varies over the course
of a day, a rise and fall every 24 hours, a night-time minimum
and a daily maximum, with a minimum summer load of about 23GW
and a winter peak above 60GW (see Figure 1). A mixture of different
types of conventional generation plant with varying degrees of
speed of response is indispensable to meet the base-load, mid-range
and peak-load requirements.
Whereas the commercial operation is measured against energy
delivered (area under the curve in Figure 1), the central grid
control by the National Grid Company (NGC) has to ensure that
the power generated balances the power demand, ie the height of
the curve at all times; thus the electrical power system operated
by the National Grid has to have sufficient capacity installed
that can be scheduled as required to meet demand. Most renewable
energy cannot be scheduled or the availability predicted sufficiently
DAILY LOAD VARIATION ON THE UK NATIONAL GRID SYSTEM SHOWING
MAXIMUM AND MINIMUM DEMAND DAYS FROM 1 JULY 2005 TO 30 JUNE 2006
The total power generated by wind turbines in Britain, for
example, is not constant and suffers from large variations depending
on the weather pattern over the country. Figure 2 shows, for example,
the total output of all the wind turbines delivering power
TOTAL WIND POWER TO THE UK NATIONAL GRID IN NOVEMBER/DECEMBER
to the National Grid during the recent winter months of November/December
2006. This power represents about 70% of all the wind power generated,
the rest being delivered directly to the low voltage distribution
systems and not to the high voltage grid transmission system.
Several studies of wind speeds in GB show that there are
significant periods in an average year when demand is high as
in the winter period shown in Figure 2 and wind output is low.
Such large-scale variability occurs for wind (or wave power) when
a large high-pressure weather system moves in over the whole country
or a large part of it, those occurring in the winter are invariably
accompanied by low temperatures, frost and fog, the occasions
when heating and lighting loads can also be at maximum, ie at
winter peak load times.
In particular, a typical year would have over 1600 hours
when wind generated output would be less than 10% of maximum rated
installed wind generation capacity, including 450 hours when demand
is between 70-100% of peak demand.
Although the risk of system failure is greatest when demand is
at its absolute peak, the risk is still significant relative to
this for demands within a few percent of the peak, say within
2 to 4 GW of peak in the system of NGT.
Sufficient electrical power has to be supplied to meet demand
at all times, however, and so conventional plant capacity that
can be scheduled has to be available when renewable power generation
is not to be had.
To summarise the situation:
The system generating capacity requirement is
measured against the peak system demand. In the UK this peak occurs
in the winter. The National Grid has historically required a 20%
capacity plant margin above peak load.
The renewable capacity connected to the system
does not lead to an equivalent amount of conventional capacity
being retired from the system.
The Severn Barrage, for example, has zero power
output daily and such periods can coincide inevitable with peak
system power demand; therefore the Severn Barrage, although contributing
carbon free electrical energy, does not replace any conventional
capacity, ie has a zero capacity credit.
Wind, on the other hand has a small capacity credit
that is determined by a balance of risks, ie of the probability
of little output measured against the consequences of lack of
supply. For the UK an approximate rule is that the amount of conventional
baseload capacity that can be retired is the square root of the
wind capacity measured in GW. Thus 25GW of wind installed, sufficient
to supply about 15% of electrical energy demand, would allow about
5GW of conventional plant to be retired without compromising National
Grid security of supply standards.
An equivalent amount of conventional capacity,
or slightly less, has to be retained and to operate at lower load
factors producing electricity at higher unit costs.
These requirements mean that with regard to wind
generation alone the requirement for conventional plant capacity
will never be less than the system peak load.
Some of this supporting capacity (in Germany called "shadow
capacity") would be on "hot standby", ie connected
to the network and operating at part load to ensure a stability
of connection as in the case of steam plant, or available for
instant start-up and connection as is the case for hydro and gas-turbine
plant. Such plant operates at a low load factor
and at a lower efficiency. As pointed out in a Royal Academy of
lower plant utilisation incurs a higher cost per unit of energy
supplied. The rise in the capital recovery component of energy-supplied
costs is illustrated in Figure 3.
Costs of generation depend on a number of factors including
capital expenditure, fuel, carbon emissions, operation and maintenance
and general overheads, some of which are fixed and some variable
depending on plant output. Using the percentage of breakdown of
costs supplied by PB Power for Table 1 above the cost increases
associated coal and gas-fired plants can be calculated for different
EFFECT OF PLANT UTILISATION ON THE UNIT COST OF ELECTRICITY
If wind and tidal energy is inserted into the system, then
the percentages of electrical energy supplied by a combination
of gas, coal and nuclear plants will have to be reduced accordingly.
A number of different scenarios can be explored, the decreases
in load factors calculated and the extra unit costs found as shown
in Table 4.
The increases in average generation costs are thus likely
to be range in the range from +12% to +39%. ie 0.5-1.65p/kWh,
or approximately £1.9b-£6b pa added to the major power
producer 2006 costs depending on the assumptions made, the highest
being associated with the inclusion of tidal energy, the lowest
with onshore wind alone.
Finally, additional further investment may be required to
ensure energy supply against the possible loss of high load factor
conventional plant capacity if retired. With additional wind capacity
connected it is theoretically possible to withdraw some plant
from the system without compromising security of power (not energy)
supply considerations. In order to maintain the existing standards
of security of energy supply, however, other supporting plant
in the form of gas turbine or diesel plant may be added. The additional
costs could be of the order of 0.2 p/kWh to 0.3p/kWh, the same
as the increase in costs due to lower load factors. They are the
sole subject of various reports such as the SCAR Report from ILEX
Consultants in 2002
and a review report from UKERC in 2006.
These reports do not consider the additional costs associated
with the substitution of existing conventional sources with higher
cost renewable energy plant, however, as shown in table 4.
INCREASE IN ELECTRICITY GENERATION COSTS WITH SUBSTITUTION
OF EXISTING CONVENTIONAL SOURCES WITH HIGHER COST RENEWABLE ENERGY
SOURCES AND INCREASED LONG-RUN MARGINAL COSTS OF RETAINED CONVENTIONAL
% of Coal/gas
|20% onshore wind||0.50p/kWh|
10% offshore wind
= + 22.8%
10% offshore wind
+ 7% tidal
= + 38.7%
4. EXTRA RENEWABLE
Increased generation costs are not the only cost increases
caused by a large addition of renewable power capacity to the
national grid, however, because considerable investment in new
grid reinforcements will be necessary. Many of the best renewable
energy sites are far from the existing transmission system, especially
in the North-West of Scotland. Some examples along with the estimated
costs for new transmission lines are as follows:
Scottish and Southern are now planning for possible
future renewable energy developments in the Western Isles, Orkney
and Shetland, as well as undertaking an environmental impact study
of the sector between Beauly and Bonnybridge, which would alone
require a £200 million investment.
The cost of the cable linking Lewis to the mainland
is put at £250 million.
Scottish Power say that they have plans for £165
million investment in the southwest of Scotland.
Even when such sources are connected to the grid
the existing transmission system does not always have the capacity
to transmit the power as required. The interconnector between
Scotland and England is a case in point and an offshore subsea
cable is under consideration. A PB Power study of 2002 estimates
a 200km, 2000MW HVDC subsea cable off the west coast would cost
To these can be added the upgrading costs of both transmission
and distribution networks of many sites around the coasts as offshore
wind farms are developed. Under forthcoming legislation, which
will create a Great Britain-wide market in electricity, the costs
of such investment will be spread to all consumers nation-wide,
rather than being borne within the local area alone.
Taking the recent cost estimates of the Beauly to Denny transmission
line as an example the expenditure required £190 million
where the return on capital with depreciation, running costs and
maintenance added, required a net annual charge to the consumer
of £22.32 million pa.
By this measure every £1 billion required for new transmission
facilities is matched by an implicit standing charge of 0.3p/kWh.
5. EXTRA SYSTEM
Unlike in other EU countries the National Grid happens to
operate basically an island system with sole responsibility for
balancing instantaneous power supply and demand and maintaining
frequency of electricity supply, voltage control and dynamic stability.
Eventually with increasing wind and other generation capacity
in the other EU systems the large uncontrolled variations in power
produced from such as wind sources can be offset by technical
support from neighbouring systems. In Denmark, for example, with
a high percentage of wind capacity in the system such support
is required frequently; however with a feed-in tariff policy in
operation guaranteeing renewable energy priority access to the
grid, the necessity of having to export electricity to balance
the Danish system results in electricity exports at below the
subsidised costs or, more expensively, constrained off payments
to the wind generators.
Priority access to the grid and appropriate compensation
for renewable generators throughout the EU is to be strengthened
by a draft EU directive
(p. 17, para. 31,) that states:
"In certain circumstances it is not possible to fully
ensure transmission and distribution of electricity produced from
renewable energy sources without affecting the reliability and
safety of the grid system. In these circumstances it may be appropriate
for financial compensation to be given to those producers."
In addition Article 14, in particular p. 31, 14(2), adds:
"Without prejudice to the maintenance of the reliability
and safety of the grid, Member States shall ensure that transmission
system operators and distribution system operators in their territory
guarantee the transmission and distribution of electricity produced
from renewable energy sources. They shall also provide for priority
access to the grid system of electricity produced from renewable
energy sources. When dispatching electricity generating installations,
transmission system operators shall give priority to generating
installations using renewable energy sources insofar as the security
of the national electricity system permits."
Such operational practices have worrying implications for
the costs of electricity supply in the UK! Constrained off payments
are already made by the National Grid. They are given whenever
generated output from a generator cannot be accepted by the transmission
system and therefore must be "constrained off". The
reasons can be various, but, in total, represent a charge on the
transmission operator. The costs are substantial and figure largely
in the economic justification for new transmission capacity.
As noted already the national transmission system has not
been configured to align with the geographical locations of renewable
energy sources and severe limitations on transmission access are
possible without prior, not post, investment in new network capacity.
A particular problem arises with the future development of
the extensive renewable resources in Scotland, for example, where
the total planned renewable generation capacity if realised (contracted
and consented for connection) will far exceed local demand and
interconnector upgraded transmission capacity.
New transmission lines to England or connections to other European
systems would take many years to construct. It would be an intolerable
cost if for several years renewable generators had to be supported
by substantial constrained off payments under the terms of the
EU Directive because of a lack of timely network investments.
Communication, PB Power-Costs include capital expenditure, fuel,
operation & maintenance, general overheads and carbon emissions. Back
Digest of UK Energy Statistics 2007, DTI, London Back
Sourced from PB Power Back
"The non-market value of generation technologies",
OXERA, June 2003 Back
Load factor is simply the ratio of average output to peak output,
so that a plant with, say a 50% load factor is operating at only
50% of capability. Back
"The cost of generating electricity", Royal Academy
of Engineering, London, 2004, p12. Back
The fixed cost p/kWh increases can be found from (fixed cost /
load factor), the variable cost increases from decreases in the
plant conversion efficiencies with lower load factors. Back
"Quantifying the System Costs of Additional Renewables
in 2020", ILEX Energy Consulting Report to the DTI, October
"The Costs and Impacts of Intermittency", UKERC,
"Overview of the Proposed 400kV Overhead Transmission Line
near Beauly, Scotland", Report by ICF Consulting, 3 August
Contrary to the view that a feed-in tariff policy would accelerate
the development of renewable electricity generation in the UK
there is no evidence that the very substantial support afforded
by the Renewable Obligations Certificates has held back the planned
investments in renewable resources. Back