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Policy statements and uncertainties
In its blueprint for a secure and sustainable energy future, the government has proposed an electricity market reform package, in which coal and gas are relegated to providing only a marginal support role for nuclear and wind up to 2020 with no role for fossil fuels at all after 2030.
The main wholesale market proposals so far announced are as follows:
(a) A carbon support price in 2013 of £16pt rising to £30pt by 2020 which impacts on coal and gas and feeds directly through to end-user prices;
(b) Some form of Feed-in Tariffs (FITs) to underpin revenues for renewable (primarily wind) generation but no detail yet on process or levels;
(c) Some form of targeted capacity payments to help finance the construction of flexible reserve plants and demand reduction measures;
(d) A new Emissions Performance Standard (EPS) aimed at limiting further CO2 emissions from existing coal plant; and
(e) From Ofgem a proposal to improve wholesale electricity market liquidity (hence better spot and forward price reliability for independent generators) by forcing the “Big Six” integrated utilities to sell 20% of their generation via the market.
As currently formulated, this strategy could have serious and unintended negative consequences for the UK economy in terms of delays in essential new power generation capacity, higher than expected energy costs and greater insecurity of energy supply.
Starting from an unrealistic CO2 emissions reduction target (80% by 2050) the government has devised a complex array of price disincentives and revenue subsidies, which, not suprisingly, according to the assumptions of its model deliver the desired result. There is a little or no “but what happens if” analysis, and the potential risks are significant.
Put briefly, these risks are
(a) Serious delays in planned new nuclear build now aggravated by the tragedy in Japan;
(b) Lack of essential new gas generation to provide power to meet future expansion in electricity demand and provide support to the grid when the wind does not blow;
(c) Premature closure of existing coal plant due to high CO2 price and tougher emissions controls;
(d) Delays in any CCS investment due to high CO2 price;
(e) Supply technical constraints on the construction of large scale wind projects and the variability of wind power; and
(f) The resulting (politically unacceptable) impact of all the proposed measures on industry and consumer energy bills.
Some unrealistic assumptions
In the Electricity Market Reform (EMR) document (published last December), the idea of stimulating and accelerating investment in nuclear and wind generation is presented as the preferred and only way of meeting the twin policy objectives of increasing available capacity and reducing greenhouse gas emissions in line with 2050 targets.
However there are four key assumptions that need to be challenged:
(a) The combination of a higher carbon price plus FITs and the level at which they are set will be sufficient to meet the low carbon generation investment target;
(b) The myriad of non-price factors e.g. equipment availability, planning permission etc will not delay the construction new nuclear and large-scale wind generation;
(c) The investment in new low carbon generation will, despite variable load factors, deliver adequate supply to meet expected electricity demand; and
(d) If the wind does not blow, price signals in the market will be sufficient to ensure that there is adequate investment in existing and new gas plant to ensure that gas power can fill any gaps in base and peak supply up to and beyond 2020.
If one or more of these assumptions is not met or only partially satisfied then there are serious risks that the EMR will fall short, bringing with it higher than expected costs and short term price volatility.
Below we look briefly at the potential imbalance in capacity and supply and likely load requirements on existing and new gas capacity.
Adequacy of Generation Capacity
One of the key assumptions in the EMR document is that planned renewable generation and gas capacity will be built as planned and on schedule and the package of price disincentives and revenue subsidies it is hoped will deliver the desired decarbonisation target (ie no fossil fuel generation after 2030).
However, there are a number of factors which could undermine this forecast such as
(a) Political and non price constraints causing delays in the construction of new nuclear and wind power. These include financial constraints, problems with new technology, equipment shortages and planning permission delays;
(b) Delays in resolving exactly what the structure, level and duration of FITs and capacity payments will be (including implementation of measures to improve electricity market liquidity) which could result in investment decisions and construction being delayed;
(c) Negative impact of higher than expected CO2 support price on operation of existing coal plant and the relative cost of UK gas; and
(d) General uncertainty over the long term future of UK gas.
Figure 1 (download full article) shows the current forward expectation on total available generation by fuel type as devised by the NGC.
It assumed that 1.5GW of nuclear comes offline in 2011 and 8.4GW of coal and 3.6GW of oil capacity comes offline in 2016 as part of the LCPD. The chart paints an optimistic picture of total capacity relative to forecast electricity demand.
Figure 2 (download full article) indicates the relative total average capacity and demand balance, assuming the impact of delays in new construction, the early retirement of ageing fossil fuel plant and applying some historical load factors..
Impact of variable wind power
One of the biggest risks implicit in the EMR strategy is the reliance on wind power generation. The share of renewable in the fuel mix is predicted to rise from its current 7% to 30% by 2020. This is a major construction target but there is growing evidence to demonstrate that in the case of wind available capacity and supply are not the same.
Gas generators are faced with operating in more volatile environment and managing short term variations in supply and demand will become increasingly difficult. The fact that wind power can vary significantly year on year aggravates revenue uncertainty over the both the short and longer term. (See figure 3)
Potential peak load gas requirement
Figure 4 (download full article) indicates that at times of peak electricity demand, gas utiliisation could vary as much as 50% assuming that new nuclear plant is late in coming on stream and the wind does not blow.
Assumptions and scenarios
If the EMR assumptions are met, then CCGT peak output as a percentage of capacity falls from 80% now to 19%. This percentage however could rise to 72% if one took a less optimistic view that nuclear is delayed and that wind power only contributes 3% at times of peak demand - as it does now- and that for environmental reasons gas is preferred to coal as a source of peak supply.
This chart shows that all the planned 17GW of new CCGT capacity is likely to be required and that further new investment in CCGT plant will be required. This is because of the continued growth in the proportion of variable wind power in the desired fuel mix, and the need to enable existing CCGT capacity (especially that commissioned pre 2000) to be able to operate more flexibly and build new plant to meet the predicted expansion in expanding electricity demand.
Some 45% of CCGT capacity will be at least 20 years old by 2015, and 71% will be 20 years old by 2020. Given variable load factors, the absence of a reliable forward price curve for electricity and the competition for scarce investment capital then financing for new investment in CCGT will be extremely difficult if not impossible to obtain without some form of revenue under-pinning in the form of long term capacity/flexibility payments.
An overview of potential risks
Consider this checklist of the risks where the likelihood and impact on energy costs and security of supply need further evaluation by government:
Reduced effectiveness and efficiency of wholesale markets arising from creation of more centralized regulation and administered prices;
Regular review and expanding subsidy regime as investors seek more robust state guarantees with consequent negative impact on energy costs;
Delays in essential new capacity investment due to uncertainties over timing and level of price incentives and the threat of regular “political” reviews;
Failure of available electricity supply to meet actual demand due to delays in low carbon investment and intermittent nature of wind power;
Failure of UK market to attract sufficient long term supplies of gas and increased risk to security of supply;
Rising volatility in power prices as short notice and variable wind power translates in to a more volatile balancing gas price;
Lack of financing for new gas power investment because of continued absence of a robust forward price curve for electricity combined with unpredictable load factor;
Possibility of legal challenges from existing independent gas generators adversely affected by new market rules which favour new generation;
Negative impact on indigenous gas production, network and storage investment and industrial supply of gas brought on by the higher environmental cost of UK gas and the government signaling a long term decline in UK gas demand.
Reducing implementation risks
In recent months there has been growing concern across the EU about the costs associated with pursuing 2050 CHG targets by relying almost exclusively on new low carbon technologies.
In February this year, the European Gas Advocacy Forum produced a series of optimised pathways for 2010 -2030 which demonstrated that a gradualist approach which allowed for a central role for gas would produce a number of significant potential benefits (see figure 5).
Some Policy Recommendations from Clive Moffatt
In conclusion, it is hoped that the government will:
Re-think the proposed level of CO2 support price in the light of its likely negative short and medium term impact on existing coal fired generation (essential supply in the transition to a low carbon economy), the future of CCS and the impact on consumer prices;
Re-think whether the option of a single, realistic and predictable carbon price without any additional revenue subsidies for renewable would be preferable (ie allow the market to provide investment signals) to a complex system of price controls subject to regular political intervention;
Consider (ie detailed capacity or flexibility payment structure) which would positively encourage gas as a clean, efficient and cost–effective fuel with a critical role to play in smoothing the transition to a low carbon economy;
Seek out to preserve the value of a liquid functioning gas market and compare that with any costs of the delay in achieving its renewable goals;
Show that it has considered, given the existence of a strong global market for gas, how gas supply can continue to be available to the UK and if not what implications this might have for power consumers.
To avoid damaging markets and new investment it is essential that we have clarity on the direction and content of UK energy policy as soon as possible.
 download full article.
Clive Moffatt
Clive is a former Treasury economist, merchant banker and business editor of the Financial Times.
He has over 25 years experience in analysing the impact of regulatory change on wholesale gas and electricity markets including acting as adviser to Enron on the original “dash for gas”, the Electricity Pool on the creation of NETA and more recently the European Commission on the efficiency and liquidity of EU wholesale gas and electricity markets and the implementation of the 3rd Energy Directive.
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