Over the past 15 years the question of blackouts has been asked many times by large UK consumers and whether this is a real risk to their business model in the UK. As we move towards 2020 there is shift in the generation dynamic given the closure of coal generation, the continued delays in nuclear build and the concern that low-carbon generation will not fill the gap given the lack of new gas-fired generation build to fill the void. However, with a myriad of support schemes, incentives and demand reduction initiatives there is strong policy support for keeping the lights on.
The answer to this question over many years has not been “will the lights go out”, but “how much will it cost to keep the lights on”. Clear statements from the UK Government are aligned to keeping the lights on and whilst outages are unlikely to occur in periods of peak demand, adverse natural conditions (a lack of solar or wind generation supporting the grid) may increase market volatility as back-up generation or demand reduction schemes will be required in greater quantities. Whilst there is an argument that renewables can fill the void due to their flexibility, a greater reliance on natural resources may prove costly without stable fuel-fired generation.
Given the consultation announcement that all unabated (coal without any clean technology such as carbon capture and storage) will be required to cease generation by 2025, a raft of announcements by generation companies to close their facilities occurred – as a consequence of Government legislation, the current low wholesale price and the difficulties in coal generators having a financially viable model in the current market. An initial 8.4GW of capacity was announced for closure which included Eggborough, Fiddlers Ferry, Longannet and Ferrybridge.
However, this development has been mitigated to some extent by the capacity market. For example, more recently the 3 turbines at Fiddlers Ferry (initially due for closure) are aiming to gain entry for 1 year into the recently proposed winter 2017/18 capacity market which ensures the short-term future of the plant (the 4th turbine at this facility is already contracted to provide services). The long term future of this generation asset still remains difficult given the previous 2 years of losses. It is also likely that Eggborough will remain active for back-up power for at least this winter coming.
Both Germany and Denmark have significantly higher renewable deployment yet are amongst the most reliable electricity systems in the world – therefore the model does work, which suggests the UK model can.
Whilst the capacity market is likely to be brought forward to secure generation prior to the original 2018 winter start, thus creating the perception that there is a real risk in meeting winter demand, there are evident signs that this scheme is popular with generators and is likely to be fulfilled – with 9GW of existing plant which applied for the 2018 winter not offered a contract due to over-supply.
In addition to the capacity mechanism (amongst other schemes), Carrington (900MW of gas fired plant) is being commissioned into 2017, Trafford Power (1656MW of gas fired plant) has received new-build permissions and will be available in late 2018. A further 5,813MW of gas fired plant was not successful in their bids. A further 740MW of smaller “peaking plant” has also received permission and should be available by late 2018 – with a further 1,361MW of peaking plant denied permission – thus proving that schemes do exist in favourable conditions.
More interestingly, recent announcements by National Grid are suggesting that summer peak demand will drop by almost 2% compared to last year (37.5GW to 35.7GW), potentially creating an over-supply of generation in some periods. For consumers, this illustrates the benefits of flexible demand management to reduce or correspondingly increase demand (through self-generation outages) to support balancing. A recently launched scheme called “Demand Turn Up” is trialling from May 1st and will run until the end of August – shifting the theory of demand response schemes from reduction to increase.
The National Grid forecast for demand on the coldest day (at the busiest time) in winter-2016 is perceived to be 54.2GW. National Grid’s crucial reserve margin forecast against this demand is 5.1% (57GW). This suggests that on the basis of current plant closures, and taking into consideration the future weather forecast, there is likely to be tighter margins – which in turn could increase market costs where the grid is forced to intervene through policy measures.
Organisations should continue to explore investment in energy efficiency and technology and where appropriate, look to invest in self-generation. Whilst the risk of blackouts is not significant, the issue of rising costs, increased volatility and higher levels of non-energy costs means that for organisations to truly succeed into the future they should look to reduce their exposure to the energy markets by reducing demand or looking to alternative sources. The increase in demand response schemes can also create a potential financial benefit to organisations who adapt their business model to suit market flexibility. The decision should be based on a sound financial basis with strong understanding of how this benefits the organisations business model as opposed to reacting to a fear over supply interruptions. The key decisions organisations need to start addressing are:
Beond has a wealth of experience in supporting our clients through the challenging nature of the energy markets. This support has over the years helped to advise our clients and prepare evidence and supporting strategies to help our clients make the right decisions – for the right reasons