The Economics of Renewable Energy - Economic Affairs Committee Contents


Memorandum by Professor Michael Laughton

1.  INTRODUCTION

  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).

2.  SUBSTITUTION OF EXISTING ELECTRICAL ENERGY SUPPLIES WITH HIGHER COST RENEWABLE SOURCES

  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.

Table 1

COSTS OF ELECTRICITY GENERATION (MAY 2008)[103]


Energy Source
Cost of Electricity
p/kWh

Wave
21.8
Tidal
12.6
Wind-offshore
10
BFBC
7
Open Cycle Gas Turbines
7
Integrated Gasification Combined Cycle (IGCC)
6.4
Wind-onshore
5.6
CFBC
4.6
CCGT
4.2
Coal Plant
4.2
Nuclear
3.8


  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.[104]

Table 2

FUEL USED ON AN ELECTRICITY SUPPLIED BASIS IN THE UK


Fuel
%

Coal
37.5
Nuclear
18
Gas
36
Oil
1
Imports
2
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 tidal sources.

Table 3

INCREASE IN PRESENT DAY ELECTRICITY GENERATION COSTS FROM THE SIMPLE SUBSTITUTION OF EXISTING CONVENTIONAL SOURCES WITH HIGHER COST RENEWABLE ENERGY


Replacing same
% of Coal/gas
Replacing
equivalent % of
Nuclear/ coal/gas

20% onshore wind
0.28p/kWh
= +6.6%
0.35p/kWh
= + 8.3%
10% onshore
10% offshore wind
0.72p/kWh
= + 16.9%
0.79p/kWh
= +18.6%
10 onshore
10% offshore wind
+ 7% tidal
1.30p/kWh
= + 30.5%
1.38p/kWh
= + 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 OPERATING COSTS ARISING FROM THE NECESSARY RETENTION OF CONVENTIONAL GENERATING CAPACITY

  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 to consider.

  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 accurately.

Figure 1

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

Figure 2

TOTAL WIND POWER TO THE UK NATIONAL GRID IN NOVEMBER/DECEMBER 2006[105]


  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.[106] 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[107] and at a lower efficiency. As pointed out in a Royal Academy of Engineering study[108], 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 load factors[109].

Figure 3

EFFECT OF PLANT UTILISATION ON THE UNIT COST OF ELECTRICITY PRODUCED


  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[110] and a review report from UKERC in 2006[111]. 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.

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 PLANT


Replacing same
% of Coal/gas

20% onshore wind
0.50p/kWh
= +11.6%
10 onshore
10% offshore wind
0.97p/kWh
= + 22.8%
10 onshore
10% offshore wind
+ 7% tidal
1.65p/kWh
= + 38.7%


4.  EXTRA RENEWABLE DEPENDENT TRANSMISSION COSTS

  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 £800 million.

  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.[112] 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 OPERATING COSTS ARISING FROM CONSTRAINED-OFF PAYMENTS

  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[113] (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.[114] 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.

June 2008




103   Communication, PB Power-Costs include capital expenditure, fuel, operation & maintenance, general overheads and carbon emissions. Back

104   Digest of UK Energy Statistics 2007, DTI, London Back

105   Sourced from PB Power Back

106   "The non-market value of generation technologies", OXERA, June 2003 Back

107   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

108   "The cost of generating electricity", Royal Academy of Engineering, London, 2004, p12. Back

109   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

110   "Quantifying the System Costs of Additional Renewables in 2020", ILEX Energy Consulting Report to the DTI, October 2002. Back

111   "The Costs and Impacts of Intermittency", UKERC, 2006. Back

112   "Overview of the Proposed 400kV Overhead Transmission Line near Beauly, Scotland", Report by ICF Consulting, 3 August 2004 Back

113   http://ec.europa.eu/energy/climate_actions/doc/2008_res_directive_en.pdf Back

114   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


 
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