Understanding the long-term trajectory of the wholesale market is critical to new generation assets and their investment viability. Here at Cornwall Insight, we support market participants in assessing the potential outlook for wholesale power markets through our long-term market Benchmark Power Curve service.
We’ve just updated our latest curves out to 2045, incorporating the impacts of near term black swan events like COVID-19 on prices, and further in-depth assessments on the impacts of long term dragon events, like the mandated net zero target.
In this blog, the first in a series of articles, podcasts and webinars covering our forecasts, we take a look at the results and highlight some of the opportunities and challenges for new build assets arising in an environment of dynamic change and no little uncertainty.
The net zero market
Firstly, it is worth highlighting just how fundamental net zero targets are in defining the shape of the future power market in terms of absolute value and volatility. This is certainly true in the period to the 2030’s before we see material changes in power demand from widespread electrification in heat and transport.
We have integrated the net zero goal into our central, high and low forecasts since binding legislation was passed in 2019. The first thing that leapt out when we did so was the difference in necessary outcomes to the prior “80% reduction by 2050” world view. For example, the electricity sector will need to be completely emissions free by 2050 to meet this target and given the continued reliance from other sectors on fossil fuels (such as aviation in transport) the power sector will therefore need to provide negative emissions. This will prove a technological challenge. The current front-runners to provide this negative emissions aspect are likely to be Bio-energy Carbon Capture and Storage (BECCS) and Direct Air Capture with Carbon Storage (DACCS). We account for in our modelling, but performance, costs, scalability and delivery are still relatively uncertain.
The requirement to meet carbon targets is an obvious opportunity for low carbon generation, where our modelling suggests up to ~12GW of new build onshore wind, ~10GW of new solar and ~21GW of new build offshore wind on top of existing CfD committed projects could be built by 2030. This rapid growth has knock on effects on the wholesale electricity market, especially the wholesale power price. Put simply, we see the large-scale deployment of very low/zero marginal cost wind and solar technologies, as well as increasing interconnection in the 2020s, having a depressive impact on wholesale power prices out to 2030. This has been exacerbated recently by the sharp falls in commodity and power prices in the wake of the COVID-19 pandemic. Although we forecast electricity demand to recover over the coming year, current forecasts suggest a slower recovery for oil and gas prices.
With high intermittent generation levels, our modelling also shows a corresponding increase in price volatility. When measured as the standard deviation of hourly prices for each period, volatility for the power price in 2019 was valued at £13/MWh. Between 2020 and 2024 there is an increase in volatility in all scenarios between £18.2/MWh and £23.1/MWh and this could rise to well over £50/MWh by the 2030s.
With these sorts of forecasts, the prospect of lower and more volatile prices is not a solid premise for investing in “subsidy-free” or merchant capacity if you need to attract risk averse, lower cost of capital investors.
Too much of a good thing?
The COVID-19 lockdown period has perhaps already shown a window to 2030, with low demand and high renewables generation creating up to 15% discount rates for solar and wind technologies against average day-ahead prices over April and May 2020. Our latest modelling shows that similar discount levels could be the norm in the 2020s, especially as more offshore wind comes onto the system, and before we see power demand climb significantly from electrification of heat and transport.
Lower wholesale power prices and capture rates in our modelling suggest a reduction in the ability of the wholesale market to successfully underwrite investment in the development of new generation capacity. This is both for low marginal cost capacity and low running hours peaking capacity in the 2020s. Although the Contracts for Difference (CfD) will route substantial power volumes to the wholesale markets, it is not as simple as arguing that forecast cannibalisation won’t happen because forecasts of lower captured prices will then deter build-out, therefore leading to a real-world correction in terms actual power prices being far higher. The CfD will continue to bring renewable power into the wholesale market and depress prices regardless, and the scale of possible capacity to be delivered by the CfD is expected be incredibly high for technologies such as wind.
The upcoming CfD AR4 round will be particularly interesting in terms of how new generators compete, as the support scheme offers obvious protections against the risks highlighted around lower wholesale prices – at least until prices go negative – and falling capture rates. However, strike prices are likely to be low, and won’t appeal to everyone, and unless capacity caps are very generous there will still be a substantial need for “merchant” or non-CfD supported new renewables assets to ensure the deployment rates needed for net zero are met. This is particularly true in onshore renewables.
We have already seen new merchant business models emerge in recent years to support long-term investment and mitigate against these risks. This may mean looking at alternative revenue streams to boost earnings, such as through the Capacity Market, co-location and balancing services. It will also mean looking at Corporate Power Purchase Agreements (PPAs) and fixed or floor price PPAs with large offtakers. It is clear from recent financial close activity that generators are utilising these options already.
But pricing PPA fixes or floors against the wholesale market at levels that make projects viable is still difficult as we model that falling forecast captured prices are currently out stripping falling technology costs. The prices set in these merchant PPA arrangements are done so in recognition of prevailing wholesale market prices and forecasts. In short, everyone is looking at the same curves and trying to figure out how best to price the inherent risks, before asking others to consider taking an “out-of-market” price and wondering why they refuse.
A bigger question
In our conversations with subscribers to our forecast and the wider developer community, similar views are emerging to our own around the competing tensions of a high renewables system, the impacts of this on wholesale market prices and the expected returns from new investments resulting from this.
One solution to the cannibalisation issue in a net zero world is to reform the wholesale markets so prices are no longer set by short run costs. This would be a courageous initiative, but nothing should be off the table given the scale of the challenge. A programme to consider such reforms and which are desirable for net zero should, we think, be considered. Currently, other priorities remain ahead of this, but we believe these are important questions which we will return to in later pieces.
In the meantime, developers will continue to look at novel ways of mitigating against merchant risks with highly competitive CfD auctions, PPAs, co-location and hybrid sites all continuing to be progressed. Outside of the CfD we are already seeing some selective and commendable success. Longer term, unless there are extremely generous CfD allocations to new or repowering plants to insulate against falling captured prices, the merchant puzzle arising from wholesale power market design still needs solving if we are to scale up the build rates to meet net zero.
These questions and the wider take on future wholesale power prices, is something we will explore in upcoming events:
- Our Financing Net Zero forum on 28 July will cover key drivers in our forecasts and debate the impacts on asset investment models.
- Our upcoming podcast will discuss our Benchmark Power Curve outputs with our modellers Tom Musker and Tom Edwards.
For more information on our Benchmark Power Curve and wider market services, please contact James Brabben: firstname.lastname@example.org