Regulatory Policy Institute: Discussion held at Oxford University on Renewable Energy and the Regulation of Electricity Generation
Graham Boyd Monday, May 28, 2012 at 10:47AM The following is a note of a seminar I attended at St Hilda’s College, Oxford, on Friday 11 May, to discuss the energy market in the context of renewable energy . The discussion was held under Chatham House rules, in which the contents of discussion may be reported but the speakers may not be named. This is taken from my personal note of the meeting – any errors of interpretation are my own. It is also worth stating a caveat that certain of the figures reported are arrived at on a different basis, for cogent reasons, from the levelised cost comparisons favoured by bodies such as the IPCC for instance, and which cast wind power in a more favourable light. Nevertheless, all the participants in the discussion were clearly experts on the topic. The discussion is reported for information and to further debate and discussion. I do not therefore necessary share all the conclusions reported here.
The discussion was very topical as it preceded the unveiling by government of the draft energy bill on Tuesday 22 May. The thrust of the bill is that growing energy demand and the retiring of older generators means that merely supplying the increase in energy demand is projected to cost £110bn in investment in new capacity over the upcoming decade. In contrast to countries such as Germany and Japan, which have scaled back on nuclear, the intention expressed in the draft bill is that the investment will tilt the capacity on the grid towards nuclear and renewables. Much debate will doubtless ensure.
The debate around renewable energy had its antecedents in the first oil crisis. This prompted the first round of major market liberalisations. The result was that what was promised didn’t occur, and what was promised wouldn’t happen did occur. Energy crises arose in Brazil and Chile, where hydropower was adopted as the main solution. Hydropower and renewables have much in common:
- High capital costs
- Low operating costs
- The plant must be kept running in the context of low marginal costs
A combination of factors conspired against hydropower. Demand for power can spike dramatically during hot dry years. These are the worst factors for hydro, and can be exacerbated if a sequence of dry years occurs which are not foreseen at the outset. Storage becomes a real issue, just as it is with renewables.
Under these conditions a real energy market does not exist. True market pricing of the resource does not take place, and it is not a spot market in that contracts protect consumers from fluctuations in market prices. At the end of the dry spell instead of the “market” clearing, very dramatic rationing took place in which power cuts were prevalent. This period endured for about six months. Policy responses, also to similar crisis, not only in Brazil and Chile but at different times such as precipitated by an ice-storm in Montreal and also supply rationing in Auckland tended to be of the headless chicken variety.
While the problems can be seen to be down to acts of God, underlying it all is a single issue – spare capacity in the generating system is well-nigh essential. The key to smoothing out load and supply variations is storage, in which context pumped-storage hydroelectricity is a very important facility.
Britain faces considerable challenges with respect to the supply of energy and adherence to carbon budgets. Its luck is running out. Retiring coal plant, nuclear, and gas will need to be replaced. Prospects for early generation combined cycle gas turbine plants (CCGTs) are uncertain. Presently wind capacity is 6 GW, but on plausible assumptions this could rise to 36 GW by 2020, in terms of Britain’s commitments to the EU to increase the overall share of electricity supplied through renewable technologies. A further 60 GW of wind capacity is mooted for the following decade. Because of the intermittency of wind, this capacity will need to be backed by 13 GW of open cycle gas plants by 2020 as well as large complementary investments in transmission capacity. While open cycle gas plants are suitable for playing this load-smoothing role, they have the demerit that they emit quite high carbon emissions, higher than CCGTs, which although more efficient overall are not suited to the on/off back-up role. The costliness of the wind-grounded approach to renewables can be seen from a comparison which shows that the same electricity demand could be met from 21.5 GW of CCGT plants with a capital cost of £13 billion, which is the cheapest of the alternatives. The comparable cost for the wind grounded approach to renewables would be about £120 billion! The investment in wind power does buy savings in the form of lower maintenance, operating, and fuel costs. These savings total about £500m per annum relative to gas. The data are Prof Gordon Hughes’ estimates (April 2012); a link to the full paper can be found below.
Hence, salvation from escalating costs, should we choose to take it, may be available in the form of CCGT (combined cycle gas turbine technology). Overall, there will need to be a response to a projected significant increase in energy dependence over GDP.
Nuclear and hydro both have the characteristics of facilitating very flat generation. By contrast, wind capacity fluctuates wildly. Over a period as short as 24 hours variations of 50 percent have been recorded. This means if you get to a target of wind providing 50 GW of capacity, then with this kind of variability the overall system is in deep trouble.
Load variations can be met by cycling CCGTs, assuming the capacity is in place. However, turning CCGTs on and off to counteract fluctuations in wind capacity hastens their deterioration (shortens their life). What is needed for smooth and efficient generation characteristics overall is negative correlation between the availability of different generation technologies.
In order to investigate the nature of a solution, start with the idea of perfect central planning. There is an extensive literature on the integration of coal and wind. Supplies would be despatched in order of operating costs, which would give rise to a series of marginal prices in the system. Given the low marginal costs of wind, this solution implies that if the wind is blowing, use wind power as the first port of call. Otherwise use something else. This entails the problem of ramping up and ramping down generation elsewhere in the system.
More fundamentally, you have to find a way to compensate people to invest in plant that might run only infrequently (not very often). The central planner would have to pay substantially for this. What this implies is that the existence of one dominant buyer is the best model for renewables.
By 2020 for example, wind capacity will exceed nuclear generation for 60 percent of the time. Hence for 60 percent of the time nuclear is not required at all. But nuclear plants are not built to run at 40 percent of capacity. This implies that nuclear and wind power don’t work well together. To facilitate an effective combination of the two, wind would need to run at load factors of 27 to 35 percent.
Large price spikes at levels of peak demand can be shown to be needed to make the economics work, to pay the owners of wind power a sufficient return on investment. The returns to generators are grounded in variations in market prices by time of day and season.
Wind is characterised by very high capital costs, and very low operating costs (marginal costs). By contrast gas has lower capital costs, but higher operating costs. This implies that wind power will displace other sources of base load generation, such as nuclear and coal with CCS. Wind will supply base load demand because it has the lowest marginal costs of supply. Neither coal nor nuclear can be run on the basis of being turned on or off depending on whether the wind is blowing. Moreover, as wind generation increases because wind generators can live with low prices, prices are depressed when the wind is blowing. Wind power will receive a lower price per KW hour than other sources of generation. Because this implies the high capital costs are not being recaptured, wind generation will require subsidies from policy makers to fund the high upfront capital costs.
The problem of intermittency of wind power cannot be dodged by geographically dispersed windfarms. The idea of having geographically dispersed windfarms is called pooling, the idea being that while there may be insufficient wind at any single wind farm, on average spread across the country there will be sufficient wind for substantial generation. In the UK, when at times in winter it is possible to have an arctic high covering most of the country, pooling won’t always be successful.
The central, single buyer will need to bid for capacity many years ahead, because of the time horizons involved in constructing new capacity. However, a market for capacity is the wrong solution. The kernel of the problem is storage. Single buyers, governments, as a rule don’t pay for storage, except on occasion for the pump-storage arrangement.
The efficient order of despatch of different technologies under a single-buyer regime as the load level fluctuates is important: Typically, it will run from low to high marginal costs. Since wind and solar power have the lowest marginal costs, these will always be used to supply power when the wind is blowing and or the sun is shining. Then, the order would run from geothermal, nuclear, and hydro, then advanced coal, conventional coal, through to biomass, gas combined cycle, gas open cycle, and lastly pumped storage hydro. The greater the share of renewables in total installed capacity, the greater the intermittency of overall supply capacity and the greater the volatility of prices, since prices fall to low levels when renewables are operating.
Storage can be provided for in two ways: Through hydro plants with reservoirs, flows can be taken out of reservoirs when the wind is not blowing. Tidal power, as it is uncorrelated with wind power, is the other alternative. Any storage system is likely to have substantial economic value in a generation system involving large degrees of intermittency and significant price fluctuations between base load generation and peak demand levels, and investors who choose to invest in storage systems are likely to be rewarded for their risk appetites.
- Examining the situation in these terms indicates that a number of obstacles associated with renewables have to be overcome.
- In essence, wind operators have to be made to pay for the variability they impose on the system.
- Wind, through its variability is imposing an externality on the rest of the system, and it is economically efficient for the operator of the wind turbines to be made to pay for those costs imposed elsewhere in the system. If wind generating capacity is doubled, then potential supply peaks rise dramatically, but the troughs remain the same (when the wind is not blowing).
It’s hard to see how retail competition can be sustained if retailers have to sign contracts to supply electricity very far into the future. Moreover retailers have a very hard message to impart if this involves a doubling of the price of meeting demand.
Ultimately, the whole system is a complete shambles. There is no single price, no true competition; a pure energy market is dead. A competitive energy market cannot be made to work, but instead there can only be bidding for entry. A single buyer of electricity is needed; as it stands the system is imposing absurd transaction costs.
A route has to be found to provide generators with an incentive to invest in smoothing technologies. Private investors won’t take the risks of constructing this capacity without some sort of insurance, or guarantee for the single buyer. Governments will need to assume some of the risks of investors by paying upfront for some installed capacity.
The longer-term carbon budgets are perplexing. Is the 80 percent reduction in carbon emissions by 2050 intended as a serious target? Attaining the 2020 target for renewables with a heavy reliance on wind power, as in the scenario outlined above, and making some assumptions very favourable to wind versus gas, would entail a saving of 23 million tons of CO2 , which would imply a cost per ton of CO2 saved of £270. This is considerably higher than the projected floor price of carbon within EU ETS. The effect would be a ratcheting up of prices throughout the system. Government, and the discussion overall, needs to be more transparent and better informed about the costs involved and what we would be willing to pay. Transparency about costs is a necessary condition for efficiency in policy design and to secure public acquiescence to measures ultimately adopted.
When wind power displaces other sources of generation such as gas, gas operates differently to how it would when it is supplying base load. In particular, the thermal efficiency is lower. In other words, wind saves CO2 emissions when it is supplying power, but other generators in the system that must serve as back-up then run less efficiently, and emit higher CO2 emissions compared to when they are functioning at optimal thermal efficiency.
The higher the capital costs of generating capacity, the more important the rate of return to generators. The problem they face is whether the single-buyer can be considered trustworthy. From a generator’s perspective the worry they face is if circumstances unfold in such a way as to render the contract to the advantage of the generator, then the single buyer may want the contract renegotiated. Conversely, if it goes wrong for the generator, no sympathy can be certain to be forthcoming; there is a risk of the adverse outcome simply being viewed as the generator’s bad luck!
There was some scepticism expressed about the role of innovation in renewable energy. One lead discussant, with substantial involvement in World Bank funded renewable energy projects, found that none of them turned out to be anywhere near competitive. He found that innovation has always been supposed to make projects much cheaper and hence competitive in some ten years time. Even in the case of solar, with prices of solar panels tumbling, his contention was that the prices of solar modules are not the driving factor behind the costs of solar installations; it is the transformers and all the associated paraphernalia that establishes the cost base. In this context, feed-in-tariffs in order to foster the uptake of renewable energy and spur innovation may succeed to the desired extent.
Energy markets cannot be deployed as an instrument of industrial policy. Recovering the cost of storage is hard; the big step-up from pump-storage is hydrogen, but this concept is not easy to sell to stakeholders!
It needs to be noted that renewable energy should not have the status of the answer to a problem which has yet to be determined. The fundamental issues at stake are how to generate electricity in a reliable and efficient manner, and (b) to reduce greenhouse gas emissions at a reasonable marginal cost per tonne of CO2 saved.
The Link to Prof Gordon Hughes’ important paper, which provided a basis for much of the discussion, can be found here.