Examining the Department’s Emerging Thinking on REFIT in I-SEM

    The REFIT Options paper published just over a week ago by the Department of Communications, Climate Action & Environment set out their emerging thinking on how the REFIT support scheme should work in I-SEM. The proposed approach is to reference REFIT top-up payments to the Day Ahead market price with no compensation for the costs of trading. In effect this could mean that the REFIT Floor Price guarantee is no-longer a guarantee due to the exposure to trading & balancing costs. REFIT generators will therefore have to decide how to best manage this exposure, either by actively trading themselves or outsourcing the management of this imbalance risk to a trusted counterparty or service provider. This decision has been driven by a desire to ensure wind actively trades in the day ahead market, so in today’s Insight we explore at the impact of actively traded wind (or the lack thereof) could have in I-SEM and how the potential implications may have influenced the Department.

Encourage active trading

REFIT supported generation represents a significant portion of what is a very small Irish electricity market (about 2.7 GW based on the 2016 PSO Order). Expectations are that liquidity will be low in I-SEM given its small nature, therefore it is important that all participants are incentivised to trade and contribute to a liquid market with robust, stable pricing. However, an efficiently traded I-SEM is unlikely to be top of the Department’s agenda, so why are they so interested in the trading strategy of REFIT wind generators? To explore the answer, we have used our in-house I-SEM model to compare a scenario where all REFIT wind avoids active trading and instead spill all power into the Balancing Market with a scenario where wind actively traded in the Day Ahead Market. We found that that if all REFIT wind spilled in to the balancing market this resulted in an average Day Ahead market price of €62.25/MWh for the year modelled. By comparison, in our scenario where wind actively trades in the Day Ahead market the average Day Ahead price was €54.27/MWh. The reason for this increase of nearly €8/MWh in average Day Ahead market price is the absence of large volumes of zero-marginal cost REFIT wind from the Day Ahead auction with more expensive conventional plant scheduled in its absence, leading to higher Day Ahead clearing prices. It is likely that most suppliers will purchase their power from the Day Ahead market in order to limit exposure to the volatile Balancing Market and to physically back out their forward CfD trades, therefore this increased cost of Day Ahead power would likely appear on consumer’s bills. Clearly this would not be a desirable outcome for the Department, the CER or the Irish consumer and will likely have been a key driver in the Department’s desire to encourage active trading of wind.

Capacity Conundrum

The Department will be very keen to do anything within their power to limit any upwards pressure the I-SEM creates on the PSO pot, particularly because the new Capacity Remuneration Mechanism (“CRM”) is likely to increase PSO costs regardless of what decision they make on energy payment reference market. Under the existing SEM CRM, wind farms received a risk-free capacity payment for every megawatt-hour generated. This payment has a monthly and daily profile but works out on average at €5-6/MWh over the course of the year for wind. This payment is counted into the REFIT generator’s total market revenue calculation onto which the REFIT Top-Up is applied, so while it does not represent an upside or additional payment while market prices are lower than the REFIT Floor Price, it does reduce the amount of PSO payments required to top REFIT generators up to the REFIT Reference Price. In the I-SEM, the new CRM design will involve a competitive auction which rewards an instrument called a Reliability Option (“RO”) which pays a €/MW fee to successful participants. ROs are designed to incentivise participants to be available at times of system stress and penalise them with large charges if they are not, which is a greater risk for wind generators who cannot guarantee availability due to their intermittent nature. While clarification is required from the Department, it is expected that capacity payments will continue to not count as additional revenue for REFIT generators, as described earlier. Therefore, there is no incentive for them to participate in the mechanism as it would only represent a downside risk with no upside. The likely outcome therefore is that no REFIT wind generators will participate in the new I-SEM CRM. This gap in revenue must be made up by the PSO, which could increase by around €40 million based on today’s volumes as a result. The new capacity mechanism is due to significantly decrease in cost in I-SEM due to its new competitive nature and a reduction in capacity procured, a reduction which should be seen on consumer’s bills. So while the net result of I-SEM should be a more cost effective CRM for the consumer, the effective transfer of REFIT wind’s compensation from the CRM to the PSO could lead to negative perceptions even though this has not been caused by wind.

Protecting the PSO

Where the Department can control the PSO pot is through the energy payments component, which is why they have recommended a Day Ahead reference for REFIT in I-SEM. The reason for the Department’s decision becomes clear if you consider the alternatives, where balancing costs are covered by the PSO, be it through a cost recovery mechanism or if the REFIT top up was referenced to the Balancing Market. In such a situation, wind generators would receive the full REFIT Reference price regardless of trading activity or market participation. A project owner may therefore justifiably ask themselves: “why incur the costs and operational burden of active forecasting and trading, when spilling all my generated volumes to into the Balancing Market costs nothing and I still get full REFIT?” We’ve already seen that if all REFIT generators chose to spill all their generated volume into the balancing market, it would have adverse effects on the cost of electricity to the wider market and consumers. But what about the impacts on REFIT generator’s own energy revenues, and by extension the PSO pot? We found that with all REFIT wind spilling into the balancing market, the average captured energy price earned by these generators was just €31.57/MWh as large volumes of low cost wind flooded into the less liquid Balancing Market, thereby significantly cannibalising its own captured price. By comparison in the active Day Ahead trading scenario, REFIT wind generators captured an average Day Ahead price of €52.49/MWh. That’s a deficit of just over €20/MWh if all wind spilled into the Balancing Market, a deficit which works out at around €140 million per annum based on today’s volumes which would be a direct additional cost to the PSO. It is of course worth mentioning that even if balancing costs were underwritten by REFIT, it is possible that some REFIT wind generators would still actively forecast and trade, for example to ensure they receive compensation for constraints (I-SEM rules state generators will only qualify constraint compensation if they trade in the day ahead or intraday markets). The spill scenario examined above therefore could be considered a “worst-case” outcome of balancing costs being completely underwritten by REFIT. One option which was not considered by the Department which could strike a fair balance could have been to underwrite balancing costs for generators who can demonstrate they forecasted and traded actively within certain parameters.   The “Trasitioning to I-SEM Options paper” can be found at the following here: