Electricity generation capacity markets and the increasing advance of renewable generation in Western Europe will likely cause investors to pause for thought before making new investments. In particular, they will be challenged to reconsider how they have evaluated their existing renewable investments – especially wind. In our experience, few investors are focusing sufficient attention on capacity markets and renewable penetration issues and the fundamental changes they are creating.
The UK has now almost legislated for an electricity generation capacity market and has provided extensive detail on how capacity auctions will be administered. France is also preparing to implement an electricity generation capacity market using a slightly different approach which may well have similar consequences.
The need for electricity generation capacity markets is actually a consequence of the increased penetration of renewable generation. The UK currently has 15.5 gigawatts (GW) of installed renewables, of which 8.9GW is wind. With installed wind due to total approximately 23GW by 2020, the UK expects wind to provide approximately 18 percent of required generation on average within a year.
However, the absolute size of the wind fleet means that, when combined with nuclear and other renewables, the wind fleet could be meeting average demand requirements in 2020 when wind load factors are in the range of 40 percent to 45 percent.
Difficult to forecast
With so much wind generation on the system, existing conventional fossil fuel generators will find it very difficult to forecast day-to-day running profiles, load factors and corresponding profitability. This difficulty is expected to be a major deterrent to investment in new conventional generating capacity, which will be required for generation in future when the instantaneous output from renewables is low.
A capacity market addresses this by paying eligible generators for the capacity they are providing, rather than the electricity they are producing, thereby providing a less variable income stream which should assist investment decisions. One benefit is that older, less efficient generating plants, which will be running less and less, will be able to recoup a proportion of their fixed costs from capacity payments, thereby ensuring that the capacity benefits they provide (i.e. system security) are maintained while it remains economic to do so.
The proposed capacity market for Great Britain (GB) is a market-wide mechanism. Generators receiving Renewable Obligation Certificates (ROCs), feed-in tariffs (FiTs) or the proposed Contracts for Difference (CfD) payments will be ineligible to participate. Gas, coal, oil and existing nuclear generators (i.e. those not receiving renewable subsidies) are the eligible generators able to earn the capacity payments from 2018 to 2019 when the first capacity payments are due to be made.
The proposed GB capacity market is likely to have a significant negative long-term impact on GB wholesale electricity prices as compared with a scenario where we have no GB capacity market. This impact arises since eligible generators will be receiving capacity payments paid by electricity supply companies through a payment mechanism outside of the existing wholesale electricity price settlement arrangements.
This means those generators will need to charge less for the electricity they sell into the wholesale market in order to recover their fixed costs i.e. cost and return of capital, and fixed operations and maintenance costs. Since the GB electricity market comprises both a bilateral trading market and exchange-traded wholesale electricity, most renewable generators should expect lower revenues from the sale of electricity where sale prices reference wholesale electricity market indices.
Clearly the downside impact of the capacity market on lenders may be mitigated by any price floors in existing power purchase agreements (PPAs). However, the central case projections on which investors have based their investment decisions during PPA periods will most likely be impacted by the GB capacity market, as will the revenue projections beyond the expiry date of any PPAs.
In our experience, investors place significant importance on these post-PPA revenues as they arise after construction debt has been repaid and, as a consequence, they can be one of the principal valuation drivers in levered renewable investments.
As mentioned above, the increasing penetration of renewable generation in our electricity sectors is driving the need for capacity markets. The variability in production of wind generators not only impacts on the production volumes of other generators in the market, but is expected to have a significant impact on the day-to-day pricing of wholesale electricity in the future.
Wholesale price drop
In the future, when there is expected to be a significant volume of renewable generation in the GB electricity system with very low short-run marginal costs (i.e. wind and solar), we expect to see and observe increasingly variable instantaneous renewables output having a significant potential downward impact on GB wholesale electricity prices at times when renewable load factors are high. As renewable energy production increases, it is likely there will be an increasing number of periods when GB wholesale electricity prices drop to zero or close to zero, as has been observed in Germany this year.
Even though wholesale electricity prices are expected to rise when instantaneous renewable load factors decrease (i.e. non-windy days), the rate of increase in wholesale electricityprices is not enough to compensate for the periods when prices fall. Increasing levels of installed wind therefore lead to the result that the average electricity price that a wind farm will achieve in any year will be below or at a discount to the ‘time weighted average price’ of electricity observed on the system, since wind farm revenues are mostly earned on windier days when prices will tend to be lower.
The ‘time weighted average price’ basis is often the price basis utilised in published projections of future electricity prices and the necessary adjustment for the captured price of a wind farm is not always understood.
The extent of the discount observed, or the difference between the ‘time weighted average price’ and the ‘wind captured price’, is driven by many factors including the amount of installed wind capacity, gas and carbon prices, and the nature of the rest of the electricity generating system (i.e. gas, coal, renewables etc.)
Importantly the impact can be observed from the early 2020s in the GB market, and its impact is significant in the context of investment decisions. Our experience with the investment community is that not all investors are currently analysing these issues sufficiently. Some are prepared to over-simplify or, worse still, overlook these challenging analytical issues.
Utilities throughout Europe, which are already experiencing problems with the profitability of gas plants due to high renewable penetration and low coal prices, are – by contrast – very familiar with these issues and are also aware that the investor community is not focussing on them with the necessary rigour. As a consequence, utilities are keen and able to sell renewable assets at prices which – with closer scrutiny and analysis – may lead to long-term performance below the return expectations of the investor community.
Simon Monk is head of funds at IPA Energy + Water Economics, a London-based economics advisory practice focused on infrastructure.