This five-part series dives deep into the economics of electricity markets and the role that markets can and must play in the decarbonisation journey. But in reality, do they? And what can be done about it?
In this third part, An elephant called Risk, we dive deep into the risks associated with the revenue streams typically renewable energy projects rely on to reach profitability. We explore a few key market developments that are increasing the risk perception of such projects.
Read previous parts: Part I, Part II
After having looked at the costs in Part II, let’s change our perspective now to look at the revenue side for the economics of renewable energy projects, more specifically, at the risk perception associated with those revenues.
Besides project costs and the delays in project execution potentially exacerbating those, a key determinant of the whether an investment decision regarding a project is successful is how stable the foreseen revenues are.
To illustrate, let’s do some roleplaying, shall we?
Imagine yourself walking into a bank seeking a loan.
You: “I would like to borrow a million euros for my favourite project.”
Bank: “How wonderful! We are here for you, exactly for that. We would love to lend you the money. But first, may we know how you intend to pay us back?”
You: “That’s great to hear, thank you. So…about paying back, I know that I “should be” able to earn money for the hours I work. But which hours I can work, in reality, depends on the weather; therefore, that is beyond my control. All I can tell you is that for any given hour in a year, there is a one-third probability that I would be able to focus on working.”
Bank: “I see. So you will be able to earn money for 33% of the hours in a year?”
You: “Ah, I wish that were so…but not really. If the conditions are really great for me to work, then, unfortunately I get paid much less for each hour that I work. Sometimes, I might even have to pay to work under such conditions. So it might be worthwhile in those periods to not work at all, so I can rest well to work in other periods.”
Bank: 😮
While the above interaction may sound oversimplified, unreal, and downright comical to many, it is unfortunately the meta-conversation in reality when renewable project developers approach financial institutions to raise capital.
To understand why, let’s break the conversation down.
First, naturally being weather-dependent, renewable energy sources, such as solar PV and wind, produce energy only when the sun shines or the wind blows.
This is measured by a generic, unit-less metric called capacity factor of a power plant which is the ratio of the actual electrical energy (MWh) generated to the total possible generation (MWh), given the size of the power plant in a given year. Typical values of capacity factors for renewable energy sources depend on site-specific conditions (e.g., how many hours of sunshine it receives, what is average wind speed, etc.) as well as the free transmission line capacity available to off-take the energy generated to sites of consumption. The number 33% mentioned above is just an example, but is not far-fetched for many sites.
Second, in a given market, as the share of renewable energy grows, there’s an effect called price cannibalisation that comes into play. This implies that as more renewables enter the market, the average price they receive in the market per unit of energy (MWh) produced by them reduces, i.e., renewable projects eat into their own profits. This is because renewables participate in energy markets offering their forecasted energy production at a zero price, since the are no fuel costs associated with actually producing that energy and there is no opportunity cost with not being asked to produce (i.e., when their bid gets rejected by the market).
If you would like to better understand the concept of price cannibalisation and more generally, the price formation dynamics in electricity markets, feel free to check out this short write-up, Price cannibalisation effect:
Lastly, not just the depression of average prices which reduces the expected revenues generated by renewable projects, it’s the variability of those prices (and consequently, the revenue) that especially troubles financial institutions.
Figure 1 below, sourced from a M.Sc. thesis report with author’s permission, shows the trends in hourly day-ahead electricity prices in one of the energy market regions in Denmark (DK2), which is surrounded by market zones typically having high share of renewable energy in the electricity mix. It’s hard to miss the recent intense increase in volatility of day-ahead prices in electricity markets. This can be explained by Russian invasion of Ukraine in the beginning of 2022 which led to sudden disruption of natural gas supply chain in Europe and consequently, price increases that shook Europe.
While some level of price stabilisation has been achieved since then as the supply chains have adjusted in response to the shock, price volatility still remains quite high, as observed in this very recent report on the electricity and gas market developments in Europe produced by the EU Agency for the Cooperation of Energy Regulators, ACER.
Figure 2 below, sourced from the same report highlights the seriousness of this development by showing the share of days in the recent years when the day-ahead electricity prices in the hours of the day varied larger than 50 EUR/MWh. To put this number into perspective, consider that the average wholesale electricity price itself was less than 50 EUR/MWh up until early 2021 in most European energy exchanges, see here.
Volatility in electricity market prices is expected to increase as more renewables become a part of the generation mix. In fact, it will be structural and fundamental to the electricity markets in the near-term. This can be partly explained, adopting some simplifications, by recalling the price formation process discussed in the example in the write-up on price cannibalisation effect, as illustrated in the following.
In the hours when sun shines and the wind blows, prices will be very low — in fact, hours with negative prices are growing year-on-year particularly during sunny midday hours as supply massively overshoots demand. Whereas in hours with reduced availability of these resources, prices shoot up as fossil-fuel based generators (mostly gas-fired power plants) with high fuel costs have to ramp up their production to meet the demand. Moreover, as the grid becomes “cleaner”, the capacity factor for these generators reduces, which coupled with increasing gas prices, implies that they must bid at very high prices to maintain the same level of returns on investment promised to the asset owner(s).
Other factors include the increasing coupling among the markets, the lagging growth of flexibility providers in the system compared to the growing share of renewables, etc. (A detailed analysis on electricity market volatility will be the topic of a future article!)
As a result, electricity prices often swing wildly between very low and very high and become highly correlated with weather — which is notoriously difficult to predict accurately. Not to mention the extended periods of windless, cloudy days and nights — so-called periods of “Dunkelflaute” in German, which loosely translates to “dark-lull” — when reliance on expensive sources of energy becomes critical, given the current absence of long-term electricity storage options.
Due to such price dynamics, the risk associated with uncertain revenues — termed as merchant market risk, looms large over renewable projects.
Even typical PPAs written by electricity retailers (utility companies, for instance) to off-take the electricity from such projects are often a lagging indicator of this risk, i.e., they are marked-to-market. This implies that there is always some an exposure to wholesale electricity market prices of various degrees associated with such contracts.
Moreover, the underlying contract duration is trending towards the shorter end over the years to reflect the fast-changing trends in average prices — no utility wants to be locked-in for 10 years at a price of 60 $/MWh when forecasts put at least some probability mass on average market prices lingering around 42 $/MWh in 3 years time.
Current geopolitical conflicts around the world further exacerbate the risk woes of renewable projects. Financial support from states and political stability among countries appears shaky as the priority and focus of governments shifts from long-term climate change mitigation to short-term adaptations to the changing world order.
Do all of the above imply that buying and selling electricity will always be “risky business” going forward?
How does one reconcile this with the fact that electricity demand is projected to (and most likely will) increase significantly in all countries around the world?
If this were any other commodity, long-term contracts should ideally be the mechanism by which resellers should be looking to lock-in favourable prices at a time when global (and local) demand to hedge the long-term price risk.
Why is it not the same for energy? Is there something more fundamental at play here?
Let’s explore these questions in depth in the next part of this article series, “Part IV: Is the commodity wrong?”
Are electricity markets fit for purpose? Part IV: Is the commodity wrong?
<hr><p>Are electricity markets fit for purpose? Part III: An elephant called Risk was originally published in Clean Energy for Billions on Medium, where people are continuing the conversation by highlighting and responding to this story.</p>