Part 2: New revenue opportunities for flexible power generators – is now the right time to turn your run-of-river into a storage plant?
Changes in the Norwegian Power Market
In part 1 of this series, HYDROGRID identified a number of European power market trends, e.g.
- Build-out of renewables, especially wind power
- Decrease of average spot market prices
- Increase in volatility in the power markets (including balancing energy prices)
We showed how these trends are now slowly coming to the Nordic markets and are affecting the revenue potential for small hydro producers, and argued that as a result of this development, there will be an increased need for flexibility and short-term trading for all power producers in Norway who do not want to miss any revenue opportunities.
In part 2 of this series of articles, we will now examine with a concrete example power plant:
- How the market changes of the last few years have affected sales revenue
- How flexible producers can capture more value from their generation in this new environment
- Whether – under these new market conditions and with NVE’s recent greater openness to such projects – now perhaps is the right time to turn your run-of-river plant into a storage by building a reservoir and which factors should affect your investment decision.
Effects of market changes on a typical Run-of-River Power Plant
For this exercise, we will consider a hydro power plant near Trondheim (price zone NO3) with annual mean production of 32 GWh and a maximum generation capacity of 6.67 MW (at maximum throughput of 5.5 m³/sec).
Actuals inflows in any given year vary quite bit from day to day – the following graph shows actual inflows in the year 2015 – but on average the inflows follow a typical seasonal profile, with the strongest inflow (due to snowmelt) in April and a wet season from October to December.
As detailed in the last part of this article series, average power market prices have been decreasing – for the seasonal production profile relevant to this power plant this has lead to a drop in revenue of over 350k € in the time period from 2014 to 2016:
Does having storage & flexibility offset the negative market developments?
Now let us assume the owner of this plant had the possibility to build a dam and create a reservoir with a total storage capacity of 44 hm³ – the following sketch shows the new topology:
The reservoir allows to capture and store the inflow as it occurs and to dispatch the power plant when prices are highest – in other words, the total annual production will remain the same at an average of 32 GWh, but the revenue per MWh can be increased, leading to a higher overall revenue. Of course, there will be some ecological flow requirements imposed by NVE which limit the flexibility of the dispatch – in this case, we will assume that 0.22 m³/sec must be discharged from the reservoir at all times.
But how should the reservoir be dispatched to achieve the greatest revenue?
In the simplest case, we can assume that the owner / operator will dispatch the plant according to a fixed reservoir guide curve (which has been calculated as the best average strategy). Using this strategy, the water content in the reservoir would follow the average seasonal profile shown in the graph below:
By lowering the reservoir before snow-melt in April and storing water for winter, even this simple strategy allows to increase revenues by about 10k € per year on average (although for some years, a fixed reservoir guide curve may even lead to a decrease in revenue compared to simple run-of-river production):
This of course is not nearly enough to offset the negative impact of the decreasing general price level.
But what about dispatching the plant in a more intelligent way?
If we knew in advance exactly when prices would be the highest and when we will have a lot of inflow, it would be possible to pick exactly the best hours to produce energy in advance (of course taking into account the ecological flow requirements and the maximum storage content of the reservoir) – this would result in a reservoir guide curve that is completely flexible each year depending on the inflow and prices. The following graph shows the optimal reservoir guide curve for the years 2014 to 2016:
With such a ‘perfect’ dispatch, revenues could in theory be increased by around 140k per year (or about 19%) on average. However, this would require the owner / operator to have perfect foresight regarding the development of spot market prices and the hydrological situation, which is of course not possible.
How much of the flexibility revenue potential can be captured in practice?
In practice, the amount of ‘value / revenue added’ by the use of storage will depend on a number of factors –
some of these depend on the quality of price & hydrological forecasts as well as the optimization methods applied by the owner / operator of the plant. For the above-mentioned example plant, HYDROGRID’s backtesting results show that at least half of the total potential (i.e. around 60k € per year on average in the test period) can be captured by applying sufficiently sophisticated forecasting & optimization methods.
The following graph compares the increase in revenue due to the storage (depending on the dispatch strategy):
This means that unfortunately – even with the best-possible optimization methods – the negative impact of the general price decrease over the last few years can of course not be completely neutralized.
However, depending on the cost of construction (and on whether or not it is possible to obtain a permit from NVE), the construction of a dam may still be a good investment decision.
In this context it is important to note that the difference in revenue potential (in €/MWh) is increasing over time as a result of the recent increase in market volatility and this trend is expected to continue on due to increased market integration (see part 1 of this series).
The figures given for this specific example power plant can of course not be generalized – the potential revenue increase (and how much of this potential can be realized) will vary greatly depending on the specific properties of the power plant in question, such as:
- The total storage volume in relation to annual inflow and specification of the turbine
- The location of the plant, which dictates the hydrological situation as well as the market area
- The existence of ecological flow requirements or other factors limiting dispatch flexibility
As a consequence, the decision to invest in the construction of a dam must be carefully assessed on an individual basis depending on the physical properties of the plant, the optimization & dispatch strategy and of course based on the available financing conditions. In any case, NVE’s recent increased openness to grant permits for the construction of reservoirs should be seen as a very positive signal, giving plant owners an additional investment option to consider based on their individual short- and long-term financial goals.
In part 3 of this series, we will focus on those power plants where the construction of a dam is either not technically possible or not financially sensible and the challenges regarding proper forecasting and imbalance management they face under the new market environment.