Constable, Supplementary Evidence 21.01.15                   9

Renewable Energy Foundation – Supplementary written evidence

Author: John Constable

Introduction

I gave oral evidence to the Select Committee on the 13th of January 2015. These notes are more complete answers to the draft questions proposed to the panellists. They include my further views in relation to questions that I answered orally, and also views in relation to questions and matters on which I did not have the opportunity to comment.

1. Are the government’s energy policies likely to achieve its aims of a resilient, affordable and low carbon electricity system?

There have been criticisms that policies such as Electricity Market Reform have brought back large-scale government intervention. Do you think these policies strike the right balance between a market-led approach and Government intervention?

The Secretary of State, Mr Davey, himself confirms that it is a dirigiste instrument. He wrote to the Guardian a few days back (09.01.15) responding to an editorial calling for more intervention saying:

“our reforms of electricity markets, both for clean energy and for securing supply, are significant state interventions in the free market.”[1]

Of course, Mr Davey is correct. Indeed, the EMR documentation actually uses the term “administrative pricing” in relation to FiTs CfDs, so there can be no real doubt that there really is substantial and growing coercion of the electricity supply industry. Since in my view the market was already excessively distorted by instruments such as the Renewables Obligation, and the Feed-in Tariff, and indeed the Climate Change Levy, the further extension under EMR is very unwelcome, and in effect transforms the sector into a government policy delivery instrument, largely a climate policy delivery instrument. Consequently, very many charges imposed on the consumer are now no longer visible to a competitive market, consequently the likelihood that the consumer will be needlessly disadvantaged is high. In view of this EMR and the associated interventions are clearly unsatisfactory and unlikely to be stable. If you want a prediction about the likely trend of future reform, I have a hunch that it may come through a recognition that competition can be best returned to the sector through competitive tenders for both capacity and energy.

The Institution of Engineering and Technology has called for further intervention through a new ‘systems architect’. Is such an architect required in your view?

Clearly something has to change, particularly with the role of National Grid, which is conflicted. However, reforms consistent with the spirit of the IET’s recommendation, or Professor Helm’s recommendation of an Energy or Electricity Commission, do not necessarily have to render the market less liberal; on the contrary.

For example, a not-for-profit Standing Commission might take over many of the roles currently undertaken by National Grid, for example the system design, the asset management and the System Operation, all features related to security of supply of course, while the Transmission Ownership could remain in private hands, indeed ownership could be removed from ‘price regulation’ and thus opened up to competition.

This would simultaneously address concerns at the lack of a responsible party to guarantee security of supply, but also resolve the worrying conflict of interest whereby National Grid not only designs the system but also earns a regulated income from that asset base, the grid lines and other equipment. More grid to connect wind farms is extremely positive news for National Grid and its shareholders.

I realise that is an elliptical answer, so, as an appendix to this evidence I am submitting a Discussion Paper prepared for REF by Mr Gibson, formerly Power Networks Director for National Grid.

2. Are sufficient steps being taken by the government, regulator and National Grid to ensure the resilience of the electricity system?

Are National Grid’s New Balancing Services likely to be sufficient to balance supply and demand over the next two winters?

National Grid are superb engineers and they are clearly under some considerable pressure to ensure that there is no problem in the short term, regardless of the cost, so I am less concerned about the risk of system fragility in the short term, and more concerned about the cumulative oncost of measures taken in the short term interest and of the precedent set.

Will the Capacity Market be effective at balancing supply and demand in the medium term? Is there a risk that too much capacity will be supported, and the costs to consumers will be too high?

The answer to the first question is probably yes, but there is considerable doubt over whether it will produce an optimal outcome. There clearly is a risk that costs to consumers will be high. This is, after all, distressed policy correction. That’s always expensive. Is it going to be still more expensive than it needs to be? From the consumer perspective, almost certainly so. The cost of maintaining security is a result of a trade-off between the cost of the necessary measures and the value of lost load. You have to ask whether the right security standard been chosen. It is quite conceivable that some consumers might prefer lower costs and a higher level of the risk. But of course the current measures are largely under political direction, and of all people politicians are probably the most sensitive to blackouts, and the most willing to see high indeed any costs in order to prevent them.

Of course, the cheapest method of limiting cost and improving system security is to address flaws in the policies, particularly the renewables policies, that are imposing the costs through their own inherent character and the fact that so large a subsidised sector has destroyed investment signals in the rest of the market.

Does the Capacity Market provide sufficient promotion for measures such as Demand Side Response and interconnectors? If not, how could this be addressed?

Covered in oral evidence.

3. How much is decarbonisation of electricity generation likely to cost? How do you respond to the argument that these costs are likely to be too high?

How do the costs of onshore and offshore wind compare to those of other low carbon generation technologies, including CCS and nuclear power?

As is well known the levelised cost of onshore wind is roughly double that of conventional generation, without CCS, at about £100/MWh, and Offshore wind rather more at about £150/MWh. One of the better studies on this subject in recent years suggested costs of about £100/MWh for nuclear, and about £145 for coal, and about £110/MWh for gas with CCS. Those are approximate figures; the precise numbers can be checked.

But it is now very well known that the levelised cost methodology does not permit proper comparison of despatchable and non-despatchable plant. Some Total System Cost estimates taking into account all the extra cost imposed by uncontrollable intermittent generation, have suggested that onshore wind is around three times the cost of CCGT at current gas prices, and offshore wind about four times the cost. That’s a very expensive CO2 saving route, and extremely unlikely to be economically compelling or to stimulate spontaneous adoption.

How do you expect these costs to change in future? Will the gap between the costs of low carbon generation and those of conventional fossil generation close?

With falling international oil and perhaps gas prices there is every reason to suppose that renewables might become cheaper, since fossil fuels are a significant part of their construction and installation costs. However, the cost of fossil fuel electricity generation will fall as fast if not faster, so the relative cost gap will remain the same or widen. The entire renewables policy, in this country and the EU, was a gamble on the future price of gas increasing significantly, and that gamble has failed. Even if that effect is only temporary, five or ten years say, the current policies look ludicrously premature.

Some say that wind imposes particularly high additional costs on the electricity system to pay for grid integration and backup generation. How significant are these costs, and how will they change if the contribution of renewables continues to grow?

There can be no reasonable doubt that the system management costs are high. I refer the Inquiry to the work of Colin Gibson, a former Power Networks Director for National Grid, for IESIS. Gibson’s central estimates for 2020 of wind’s additional cost of system management, over and above that conventional generation, is about £75/MWh for onshore wind, and £64/MWh, the difference being accounted for by the higher load factor of offshore wind.

Thus: the total cost to consumers of onshore wind would be about £170/MWh, and offshore wind about £209/MWh.

In 2011 we at REF calculated that for the 2020 plant mix then predicted, the subsidies would be about £8bn a year, and the system costs another £5bn a year, almost as much again as the subsidy.

Gibson’s estimates include a) The cost of short term reserve, to address errors in the wind forecast; b) additional grid and grid reinforcement; and c) the cost of guaranteeing security of supply at current levels by retaining sufficient conventional plant equal to peak load, plus a margin, but running that portfolio at necessarily lower load factors.

4. What are the options for overcoming the challenges of intermittency? What would the most cost effective approach for achieving this be?

How much of a contribution can – or should - different technologies such as flexible generation, interconnection, electricity storage and demand side response make?

The most cost effective approach is to avoid incurring the problem in the first place. None of the means of addressing the problems caused by uncontrollable variability are affordable at the large scale that would be required in 2020, assuming that the EU RE Directive levels of renewables are met by the current expected mix of wind, solar and other technologies.

I can illustrate this point in relation to constraint payments. As the committee will know wind power makes negative bids in the Balancing Mechanism, which are unusual, indicating that it requires to be paid to stop generating, and that has resulted in direct costs for wind farm compensation alone of about £50m in payments within the Balancing Mechanism alone. At just over £70/MWh these bids are in fact well in excess of the lost income of about £45/MWh. It is true that the prices have fallen; when REF first publicised this abuse of market power the top negative bid was £999/MWh, and the mean was £178/MWh.

              On top of the cost of those negative bids is the cost of paying conventional generation to come on to make up for the now missing wind. It is not quite straightforward to assign constrained on payments south of the constraints to these wind export constraints, but it will be substantial.

Now, you might think that the obvious solution to this is to reinforce the grid between Scotland and the centres of load in England. But that too is very expensive for the consumer. The cost of extra grid must be recovered from consumer bills at the rate of about 10% of the capital cost per annum for the life of the asset. So one single billion pound bootstrap subsea interconnector would be adding about £100 million a year to consumer bills, for thirty years or so.

There really are no cheap solutions to these problems. Indeed constraining wind power off the system, though not at current prices, might be a comparatively cheap option.

Further details on constraints:

1. Projected BSUOS cost for the year ending Mar 15  (where real costs exist up to Nov 14) is approx. £1bn of which constraints is roughly a quarter £250 million. Last year the out-turn was also approx. £1 bn of which constraints were £340 m – so a third. (They may be being optimistic for this year – we shall see).

2. The £250 million includes export and import constraints – but export constraints represent over 90% of the total and the two Scottish constraint boundaries 82% of the total. So it is reasonable to assume that Scottish wind is the major problem.

3. What proportion of the total cost is attributable to wind is impossible for outsiders such as REF to calculate. Direct costs payable to wind generators was approx. £50 million (BM and forward trades) for year ending Mar 2014 – so one could jump to the conclusion that wind is 20% of the whole but that ignores the replacement costs. If we had to guess, we would say that the extra indirect costs are probably the same again i.e the replacement and reserve replacement is about £60-£70/MWh – so perhaps total cost of the Scottish overbuild of wind is £100 million so, a conservative estimate, 40% of the current constraint costs are attributable to wind power.

To what extent are the Government’s current policies likely to deliver the most cost-effective solutions for managing intermittency?

The current approach, well represented by the Connect and Manage scheme is simply to write a blank cheque on the consumer. This is very unlikely to deliver a cost effective result. The simplest and cleanest solution in the short term would be stop building intermittent renewables, of which we already have more than is economically or technically prudent, and build CCGTs.

Does increased reliance on renewables inevitably reduce the resilience of the electricity system?

Yes, if we are talking about uncontrollable renewables, since these renewables increase the system costs of providing a given level of security, and thus it is inevitable that consumers will be compelled by economic necessity to settle for a new equilibrium with lower levels of security. The current levels of intermittent renewables are already dangerously high; we should stop making the problem worse and without delay build gas turbines for support purposes.

5. In an earlier evidence session, Professor Dieter Helm argued that current renewables cannot solve the problem of climate change. In his view, we should stop subsidising current renewables, invest in R&D for improved future renewables and in the meantime rely on gas to reduce carbon emissions. To what extent do you agree with this argument?

I agree in almost every regard. The current renewables policies will be so expensive, as much as £13 billion a year in additional consumer costs in 2020 as I have already noted, that consumer rebellion is all but inevitable. Professor Helm’s suggestion is much less likely to stimulate public resistance, and stands a much better chance of delivering clean technologies that are spontaneously attractive without subsidies.

Furthermore, it is more likely to deliver more significant and cheaper carbon emission reductions. His views have been neglected for far too long. That said, the track record of state sponsored R&D is poor, and it seems rather likely that the tradition of picking losers would continue. A technology neutral carbon tax to encourage private R&D would be obviously be preferable, or perhaps tax breaks for private R&D.

In your view, is the government’s current approach the most cost effective way to support the deployment of renewables? If not, what would a better approach be?

It is hard to imagine anything more wasteful than the current mixture of the ETS, the RO, the FiT, the FiTs CfDs. I appreciate the legal difficulties, but the sooner these instruments are terminated, retrospectively if possible, the better. If we must have an instrument, then there must be only one, and it must be a technology neutral carbon tax.

To what extent can an increased role for gas provide an alternative way to meet our emissions targets? What are the resilience implications of this?

It’s the wrong question. The 2050 emissions targets cannot be met by the renewables policies any more than by a switch to gas. Gas will deliver what emissions reductions are affordable, that may not perhaps be at the absurd scale demanded by our (2050 aspirational) targets but quite sufficient to constitute a reasonable insurance policy against climate change, and at an entirely reasonable price. Furthermore, national wealth and societal sophistication will be maintained, putting us in a better position to invent and innovate our way towards a fundamentally economic low carbon energy supply, as well as adapting to climate change and helping others to adapt.

Are there any game changing technologies which would help to improve resilience, and on what timeframe might these be market ready?

No comment.

21 January 2015

Appendix 1: Mr Colin Gibson on an alternative to nationalisation for the Electricity Supply Industry

The following discussion paper has been drafted for Renewable Energy Foundation by one of the foundation’s advisors, Mr Colin Gibson, a former Power Networks Director of National Grid.

An Alternative to Nationalization or Privatization

of the Electricity Supply Industry in Great Britain

1. Introduction

1.1 A recent poll (The Times, 02.12.14[2]) has shown that a majority of people in GB would prefer a return to a nationalized Electricity Supply Industry. This paper offers, for the Generation and Transmission sectors, an alternative to either staying as a fully privatized industry or a return to a nationalized one.

1.2 There are a number of weaknesses in the present arrangements.

• There is no body responsible for ensuring Security of Supply
• NETA and BETTA did not recognise ‘power capacity’ as a separate commodity, and although the recent capacity auction for 2018 is a step forward, it does not provide an overall optimisation.
• There could be a conflict of interest in the different roles of National Grid

1.3 The arrangement suggested in the current study endeavours to retain competition in as many as possible of the functions involved and to reduce the number of functions requiring ‘price regulation’. It introduces a central planning body to make effective long-term decisions in areas where the current energy market has failed to deliver a secure and economic supply.

1.4 The current arrangement of a single market in energy will not deliver an optimal solution relying as it does on that market to deliver the optimum plant mix at the optimum time. This is because there are two commodities involved – energy [MWh], (the basis on which to the customer is billed), and power capacity [MW] to meet instantaneous demand, particularly at times of peak demand. Since these two commodities are to be delivered from the same items of capital plant - generation units – there is a need to find a plant mix that will satisfy both requirements at minimal cost. This paper offers a method of achieving an overall optimum solution.

2. Long-term Planning

2.1 In order to provide effective and optimal planning and delivery of the total GB system, it is proposed that a Standing Commission reporting to Parliament be set up with the following duties.

• It would propose a Standard of Security of Supply to be endorsed by Parliament. The Standard would be equivalent to that for other developed industrial countries and that used in GB prior to privatisation.

• It would commission study work on a total system cost basis to find the optimum ongoing plant mix to minimise cost and meet the Standard of Security of Supply. The costs would include all generation, transmission, losses, and system costs such as back-up for intermittent generation. The study work should be on a probabilistic basis to accommodate the range of input values over the long period of the studies.
• It would address the issue of long-term plant mix in order to have acceptable security for prime sources of energy.
• It would address other limitations such as CO2 emissions.

2.2 It would put out tenders for generation plant to meet the optimal ongoing plant mix. The tenders would be for a capital cost part that would be for power capacity to be delivered at times of system peak demands (triads?); and a revenue cost part for the delivery of energy including hot, cold and warm starts, run up heat rates, amongst other matters. The tenders would be assessed on a total system cost model using discounted costs.

3. Operating the System

3.1 The Commission would place contracts for the most attractive tenders. The System Operator (SO) would schedule and dispatch generating plant on the basis of the contracts using methodology similar to that formerly used in the POOL to achieve minimum cost. ‘Grandfathering’ would be required for existing generators. The generators would be compensated on the basis of the revenue part of their tender to the Commission which would be embedded in a long-term contract with suitable escalation clauses for fuel, salaries and other works costs.

3.2 The methodology used would take account of the costs of response and reserve plant, losses, and all system costs to control voltage and frequency. These would be delivered under ancillary services contracts between the SO and the individual generators.

3.3 The delivery of power capacity at the times of peak demand would be contractual and payments made on the basis of the capital cost part of the tender. If the contracted generator did not have sufficient capacity available to meet its contract it would have an obligation to purchase and supply to meet its contract. (This is the same as the CfDs in the POOL). Failing this, there would be compensation to be paid by the generator on the basis of Value of Lost Load specified in the contract.

4. Organizational Changes

4.1 Other than setting up the Commission, the main organizational change suggested would be within National Grid. National Grid carries out several functions for the GB ESI.

• The System Design function delivers plans for the extension, modification and replacement of plant on the basis of requests to connect new generation, load increases, and replacement of time expired plant in line with the Standard of Security of the Transmission System. But does NG really have Design Authority given that the Regulator decides whether a ‘need’ case exists? There is a potential conflict of interest here also since NG as the plant owner receives a return on its Regulatory Asset Base and thus has an interest in expanding it.

• NG has a responsibility for Asset Management of the transmission plant with regard to its specification, condition, maintenance routines etc.
• NG is also System Operator for GB.
• NG maintains the plant to the standard required by Asset Management, and project manages new construction work and is also the Transmission Plant Owner.

4.2 Some of these functions may sit more effectively with the Commission which would be structured as a ‘not for profit’ organization. In particular, the functions of System Design, Asset Management, and System Operation are together accountable for the security of the transmission system and should be kept together under one corporate body. They have a very small requirement for capital assets (mainly for SO) and could easily sit as a wholly owned subsidiary of the Commission itself. This removes the possibility of a conflict of interest between System Design and Transmission Ownership.

4.3 Transmission Ownership (TO) could then be open to competition for any new project since this is essentially a banking function – infrastructure companies tender to finance a project for new plant Existing transmission plant could be ‘grandfathered’ with National Grid and receive the Regulator’s Rate of Return. The TO could be made accountable for the maintenance of the plant to the standard required by the Asset Manager. The Transmission Ownership, by far the largest of the financial items within the Transmission function, is thus removed from ‘price regulation’ and opened to competition.

Colin Gibson

13 January 2015