Capacity withholding (market manipulation practice)
Capacity withholding can sometimes be qualified as manipulative practice to artificially cause prices to be at a level not justified by market forces of supply and demand (including actual availability of production, storage or transportation capacity).
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Irrational bidding behaviour of a market participants artificially inflating (or dampening) prices to uncompetitive high (or low) levels could also be considered predatory pricing under competition law - even if not prohibited under REMIT.
The questions arising in this context belong to the fundamental ones and concern, for example, a delicate and subtle division between an optimising a portfolio of assets across timeframes as a legitimate commercial strategy, on the one hand and a market manipulation on the other hand.
Is a legitimate behaviour to restrain bidding in the forward market or day-ahead market - in expectation of higher returns in the intraday market or balancing market - a manipulative capacity withholding?
Wholesale electricity markets’ specificities play a role in this puzzle, where regulators seem to be aware of extreme complexity of potential factual circumstances.
ACER in its Guidance on the application of REMIT (4th edition, updated on 15 October 2019, pkt 6.4.1 (i), p. 38, 39) underlines the need to reflect “the difference between market outcomes that are the result of true market conditions, such as scarcity and those that are the result of market manipulation through withholding of capacity”.
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According to the ACER, manipulative capacity withholding occurs, for example, “when a market participant with the relative ability to influence the price or the interplay of supply and demand of a wholesale energy product, decides, without justification, not to offer or to economically withhold the available production, storage or transportation capacity on the market. This includes the unduly limiting of infrastructure or transmission capacities, resulting in prices that likely do not reflect the fair and competitive interplay of supply and demand.
In particular, electricity generation capacity withholding refers to the practice of keeping available generation capacity from being competitively offered on the wholesale electricity market, even though offering it competitively would lead to profitable transactions at the prevailing market prices”.
Two forms of electricity generation capacity withholding are differentiated by ACER, i.e.:
- physical withholding (not offering the available generation capacity at any price),
- economic withholding (actions undertaken to offer available generation capacity at prices which are above the market price and do not reflect the marginal cost (including opportunity cost) of the market participant’s asset, which results in the related wholesale energy product not being traded or related asset not being dispatched).
Electricity generation capacity withholding may be performed by one or more market participants (for example, producer or storage asset owners) acting independently or in collaboration.
ACER unequivocally underlines that REMIT applies to electricity generation capacity withholding irrespective of whether competition law (also) applies.
In case of intent, any action involving capacity withholding, even beyond the issuing of orders to trade or the entering into transactions, can amount to an attempt to manipulate the market.
However, the ACER acknowledges the fact that electricity generation capacity withholding does not always automatically amount to a breach of Article 5 of REMIT.
As the Agency underlines, “REMIT does not prohibit prices to be high, provided that they reflect a fair and competitive interplay between supply and demand”.
A case-by-case analysis of the circumstances and specificities of the market (like, for example, different timeframes and types of market places) is therefore needed.
The ACER proposes the following methodology, based on two concurrent elements, for assessments whether a behaviour involving electricity generation capacity withholding amounts to a breach of Article 5 of REMIT in view of the market manipulation criteria as defined in Article 2(2) of REMIT (e.g., and not limited to, setting prices at an artificial level).
In the first step it is necessary to assess whether the market participant at issue is able, in the case-specific circumstances, to influence the price or the interplay of supply and demand of a wholesale energy product by engaging in such behaviour (for example, being a ‘pivotal supplier’ i.e., a power supplier whose capacity must be used to meet peak demand and whose capacity exceeds the market’s supply margin).
The second stage, that appears to be more complex, is the assessment of legitimate justification for not offering available generation capacity or offering it above marginal cost.
The category of “legitimate justification” can, in principle, include technical, regulatory and/or economic determinants. On this ground the technical withdrawals and economic withdrawals are differentiated.
Technical withdrawals
Technical reasons seem to be, when it comes to "legitimate justifications” the most objective elements.
With respect to regulatory aspect market participant can be, for instance, in situation of force majeure or localised transmission constraints.
Routine maintenance and failures
Technical constraints influencing the extent to which a plant is operating to meet demand may be involved with equipment failures as well as routine maintenance necessary to ensure that the plant’s performance does not deteriorate.
Minimum up/down time
Power plants are technically prevented from being turned on and off repeatedly, in particular at short intervals. The ability to operate intermittently differs for different technologies like coal, gas or nuclear power plants.
This is also a derivative of the respective minimum up- and down-times, i.e.:
- once the operation of a power plant is started, it has to run for a minimum time horizon in any of the operational levels;
- once a power plant is shut down, it has to remain in an idle state for a certain time period.
All these technical features of a particular technology have a direct influence on an electricity generation pattern and the volumes of electricity produced at specific intervals.
Cogeneration
Cogeneration plants use heat emitted during electricity generation and provide it for heating or cooling purposes.
When a power plant simultaneously generates both electricity and useful heat (district heating) or for industrial process this also influences on the generation pattern and dispatch decisions.
Hence, cogeneration plants may for legitimate reasons produce electricity at a lower capacity level than expected.
Lacking emission allowances under the EU ETS
The rules of the European Union Emissions Trading System (EU ETS) may force the company to cease operations or to reduce output when there are no sufficient emission allowances.
Industrial Emissions Directive
Compliance with the Industrial Emissions Directive (IED) may affect power plant dispatch.
Under the so-called Limited Life Derogation operator of a large combustion plant had the possibility to opt-out from the IED, and thereby limit the running hours to 17,500 between 2016 and 2023 (these plants are forced to close when the hours are exhausted or by the end of 2023, whichever is reached first).
Hence, a coal plant operator whose plant has limited running hours under the Limited Life Derogation may decide or be forced to hold back on generation.
Transmission constraints
Moreover, transmission constraints and congestions may impact on the economic dispatch of the power plant.
Transmission System Operators may in such a case change the generation pattern, thus by running certain power plants in out-of-merit dispatch, using instruments like, for example, countertrading or redispatching.
Must-run status
In connection with the above Transmission System Operators’ competences some power plants have must-run status, i.e. their operation is mandatory at times to maintain the network stability parameters.
Economic withdrawals
The most contestable justifications will most likely be the economic ones.
ACER understands the “economic” justification as the opportunity costs, which represent the expected value of the most valuable choice that was not taken.
In wholesale electricity markets, this can, for example, represent producing at a different point in time for energy-limited generation assets, e.g. reservoir hydropower units, or producing in a different sequential market for capacity-limited generation assets.
ACER declares, finally, that the Agency intends to provide further clarifying guidance with respect to above justifications.
Also EFET Position paper of 31 January 2020 (Price formation and capacity withholding in light of Regulation (EU) 2019/943 and Regulation (EU) 1227/2011) recommends clarifying further the concept of “economic withholding” and “opportunity costs”.
In the EFET’s opinion the text of the ACER’ guidance “seems to indicate that opportunity costs should be considered alongside short-run marginal costs when assessing an asset owner’s or operator’s marginal costs. This should be stated more explicitly and should not be limited to “energy-limited generation assets” or “capacity-limited generation assets" but should be open to any generation asset.
Moreover, the ACER’s reference to the specificities of different timeframes and types of market places should, according to the EFET, be also expanded to include both an energy-only market and a combination of a capacity and energy market, as the ACER’s guidance should apply consistently to both of these types of market mechanisms.
EFET in the above document of 31 January 2020 refers to and supports the following principles laid out by the German regulators BKartA and BNetzA in their joint guideline concerning price spikes and their appropriateness (Leitfaden für die kartellrechtliche und energiegroßhandelsrechtliche Missbrauchsaufsicht im Bereich Stromerzeugung/-großhandel – Preisspitzen und ihre Zulässigkeit, Bundeskartellamt, Bundesnetzagentur):
1. price spikes based on free, competitive price formation (the interplay of supply and demand) are permissible;
2. there exists no general obligation under REMIT to offer power plants at certain prices to certain market segments, hence:
- optimising a portfolio of assets across timeframes should be seen as a legitimate commercial strategy,
- not bidding in the forward or day-ahead markets in expectation of higher returns in the intraday or balancing markets cannot be seen automatically as capacity withholding,
- speculation about higher prices in day-ahead and/ or intra-day markets does not constitute market manipulation.
Panagiotis Tsangaris in the publication “Capacity Withdrawals in the Electricity Wholesale Market, Between Competition Law and Regulation” (p. 18 - 21) analyses reasons where base load power plants should be allowed to price at a higher level than their marginal costs so as to get some contribution to their fixed costs:
„In the case of economic withdrawal, the starting point is the marginal cost pricing. As was discussed above, the wholesale price of electricity should be equal to the short-run marginal cost of the power plant which produces the last unit of electricity required to meet demand. One could expect that any pricing above the short-run marginal cost of the marginal power plant could, in principle, be considered excessive. This, however, is not the case, since there may be legitimate reasons for generators to offer electricity from their plants also at price levels other than short-run marginal cost.
To begin with, there is a ‘specific situation’ with regard to the peak power plants which are located on the far right of the merit order curve.
The peak load plants, as has been described above, have lower fixed costs but higher variable costs than the base load plants. Therefore, the latter, which have higher fixed costs but lower variable costs than the former, rely on the price set by the former to amortise their fixed costs. The peak plants located on the far right of the merit order curve, however, do not get contributions to their fixed costs since there are no more expensive power plants to set a market price which will be higher than their marginal costs.
In addition, these plants operate only during a limited number of hours during which they are able to amortise their fixed costs. Therefore, they should not be expected to offer electricity at a price strictly based on their marginal costs but should be allowed to price at a higher level than their marginal costs so as to get some contribution to their fixed costs”.
Given the complexity of the case further regulatory guidance inevitably is necessary.