Commission européenne, DG COMP MERGER REGISTRY, 1049 Bruxelles, BELGIQUE  
Europese Commissie, DG COMP MERGER REGISTRY, 1049 Brussel,   BELGIË  
 
Tel: +32 229 -91111. Fax: +32 229 -64301. E -mail: COMP -MERGER -REGISTRY@ec.europa.eu .  EUROPEAN COMMISSION  
Brussels, 21.12.2022  
C(2022 ) 10031 final   
PUBLIC VERSION  
RWE AG  
RWE Platz 1  
45141 Essen  
Germany  
Subject : Case M. 10713 – RWE / NEWCO EEMSHAVEN  
Commission decision  pursuant to Article 6(1)(b) of Council Regulation 
No 139/20041 and Article 57 of the Agreement on the European Economic 
Area2 
Dear Sir or Madam,  
(1) On 17 November 2022 , the European Commission received notification of a 
proposed concentration pursuant to Article 4 of the Merger Regulation by which 
RWE AG (‘RWE’ , Germany ) will acquire within the meaning of Article 3(1)(b) of 
the Merger Regulation  sole control over NewCo Eemshaven B.V. (the ‘Target’ , the 
Netherlands ) by way of purchase of shares (the ‘Transaction’).3 RWE  is designated 
hereinafter as the ‘Notifying Party’ and together with the Target as the ‘P arties’.  
1. THE PARTIES  
(2) RWE, a German public company, focusses on: ( i) electricity generation from 
renewable and conventional energy sources (in particular, wind offshore and 
onshore, solar, hydro, gas, coal, lignite and nuclear), and (ii) energy trading, 
including energy -related raw materials in both their physical and/or  derivative 
form. Within the EU, RWE is mainly active in Germany, Denmark, Luxembourg, 
France, the Netherlands, Italy, Belgium, Poland, Spain, Czechia, Sweden and 
Ireland.  
                                                 
1  OJ L 24, 29.1.2004, p. 1 (the ‘Merger Regulation’). With effect from 1 December 2009,  the Treaty on 
the Functioning of the European Union (‘TFEU’) has introduced certain changes, such as the 
replacement of ‘Community’ by ‘Union’ and ‘common market’ by ‘internal market’. The 
terminology of the TFEU will be used throughout this decision.  
2  OJ L 1, 3.1.1994, p. 3 (the ‘EEA Agreement’).  
3  Publication in th e Official Journal of the European Union No C 446 , 24.11.2022, p. 35.  

 
 
2 (3) The Target is an energy company newly established for the purposes of this 
Transacti on and headquartered in Amsterdam. The Target operates a gas -fired 
power plant (‘Magnum’), whose production c apacity is composed of three 
combined cycle gas  turbines  (‘CCGT’ ) with a total capacity of 1,410 megawatts 
(MW), and an adjacent solar park consist ing of around 17,000 solar panels  with a 
production capacity of 5.6  MW, at Eemshaven, in the north of the Netherlands.  The 
Target  consists of assets  previously owned by Vattenfall N.V. (‘Vattenfall’ ). 
2. THE TRANSACTION   
(4) The Transaction consists of the acquisition of sole control by RWE over the Target 
through the acquisition by RWE of 100% of the share capital and voting rights of 
the Target from its current  sole shareholder Vattenfall . The Transaction will be 
implemented by way of a share and purchase agreement signed on  13 June 2022. It 
follows that the Transaction  is a concentration within the meaning of Article 
3(1)(b) of the Merger Regulation.  
3. UNION  DIMENSION  
(5) The undertakings concerned have a combined aggregate world -wide turnover of 
more than EUR 5 000 million  (RWE: EUR 24  526 m illion; Target: EUR […] 
million)4. Each of them has a  Union -wide turnover in excess of EUR 250 million  
(RWE: EUR […] million; Target: EUR […] million) , but they do not both achieve 
more than two -thirds of their aggregate U nion-wide turnover within one and the 
same Member State. The notified operation therefore has a U nion dimension  
pursuant to Article 1(2) of the Merger Regulation .  
4. MARKET DEFINITION  
4.1. Introduction  
(6) The Transaction consists of the acquisition of a single gas -fired power plant  and a 
solar park.5 The main area of overlap between the Parties consists in activities in 
the generation and wholesale supply of electricity . Both RWE and the Target also 
overlap in the supply of balancing and ancillary services and in co ngestion 
management. The Commission’s assessment has therefore focussed on these three 
areas of overlap: generation and wholesale supply of electricity; balancing and 
ancillary services; and congestion management  in the Netherlands .6 
                                                 
4  Turnover calculated in accordance with Article 5 of the Merger Regulation.  
5  The solar park generates very small amounts of energy (5.6 MW) and the electricity generated is 
included in the overall generation and wholesale supply of electricity. If one were to look at a 
generation and wholesale supply of electricity generated only from renewables, there would be no 
affected market (Form CO, Table 39). Due to the very limited overlap be tween the Parties in 
renewables, this will therefore not be discussed further.  
6  The Transaction also gives rise to two vertical links, due to RWE’s downstream activities in the retail 
supply of electricity to large industrial customers. These are the ve rtical relationships (i) between the 
generation and wholesale supply of electricity of the Parties (upstream), on the one hand, and the 
retail supply of electricity to large industrial customers of RWE (downstream), on the other hand, as 
well as (ii)  the b alancing and ancillary services of the Parties (upstream), on the one hand, and the 
retail supply of electricity to large industrial customers of RWE (downstream), on the other hand. In 
the downstream market (i.e. retail supply of electricity to large indu strial customers, see, e.g., cases 
 
 
 
3 (7) These markets are depi cted in Figure 1 below. The generation and wholesale 
supply of electricity is the largest market at almost 120 terawatt -hours  (TWh ). In 
the Netherlands, electricity is traded either on power exchanges or through bilateral 
trading ( over-the-counter, ‘OTC ’). The power exchanges operating in the 
Netherlands are: EPEX SPOT (for the day -ahead and intraday market, where most 
volumes are traded); the  EEX (futures market) and ICE Endex (futures market).7  
(8) TenneT, as t he Transmission System Operator (‘TSO’ ) for the Netherlands, is the 
grid operator. As part of its responsibilities , and as explained further below in 
Section 4.3, it maintains the frequency of the electricity grid at 50  Hertz ( Hz) at all 
times, through its balancing activities. Finally, as explained further below in 
Section 4.4, TenneT has the statutory task of safeguarding the grid security of the 
entire electricity system in the Netherlands, which includes resolving congestion . 
Figure 1 – Electricity markets in the Netherlands , organi sed by time and function   
 
Source: TenneT  website,  “What kind of markets are there and how do they work?”8 
4.2. Generation and wholesale supply of electricity  
4.2.1.  Product market  
4.2.1.1.  The Commission’s decisional practice  
(9) The Commission has a consolidated case practice of defining the product market 
for the generation and wholesale supply of electricity as encompassing both (i) the 
                                                                                                                                                      
M.9587 – ENGIE / EDP RENOVAVEIS/EDPR OFFSHORE ESPANA , paragraphs 23 -24; M.8660 – 
FORTUM / UNIPER , paragraph 102; M.8855 – OTARY / ENECO / ELECTRABEL / JV , paragraphs 
27-28; left open in M.10212 – ANDEL / ENERGI DANMARK , paragraph 20), the Target is not active 
and RWE has a market share of less than 10% (Form CO, paragraph 100). In light of the Parties’ 
market shares set out at Tables 1, 6, 7 and 8 below, these vertical relationships do not give rise to 
affected markets and  will not therefore be discussed further in this decision.  
7  Form CO, paragraph 582.  
8  TenneT website: https://netztransparenz.tennet.eu/electricity -market/about -the-electricity -
market/what -kind-of-markets -are-there -and-how-do-they-work/ .  

 
 
4 trading on the wholesale market of the generated electri city within a certain 
geographic market9 and (ii) the electricity that is physically imported into this 
geographic market via interconnectors, irrespective of the source of generated 
electricity (such as nuclear, lignite, wind, solar, etc.).10  
4.2.1.2.  The Notifyin g Party’s view  
(10) The Notifying Party agrees with this product market definition, and submits that 
the product market should not be segmented further such as  on the basis of (i)  peak 
and off -peak hours11 and/or (ii) renewable -based and conventional generation.12 
(11) Regarding a potential segmentation on the basis of hours of the day (i.e. peak and 
off-peak hours), t he Notifying Party submits that the historical differentiation 
between peak and off -peak hours has become less relevant with the increasing 
penetration o f intermittent electricity from renewable sources  (wind and solar 
photovoltaic ). 
(12) Regarding a potential segmentation on the basis of the source of electricity 
production (i.e. conventional and renewable sources), the Notifying Party submits 
that reduction s in the cost of renewables due to technological and policy changes 
over time , and, consequently, the fact that certain renewables  nowadays are no 
longer subsidised , have brought renewable and conventional sources of electricity 
closer together and made rene wables more competitive compared to conventional 
sources.13 From a demand -side perspective, electricity as a homogenous product 
does not allow for differentiation between renewable and conventional electricity at 
wholesale level. From a supply -side perspect ive, both renewable and conventional 
sources compete for the same total amount of electricity dispatched in order to 
meet demand at a given point in time, as explained at paragraphs (71) et seq. 
below .  
4.2.1.3.  The Commission’s assessment  
(13) The market investigation confirmed the Commission’s previous findings with 
respect to the existence of a separate market for the generation and who lesale 
                                                 
9  For the avoidance of doubt, the trading on the wholesale market of the generated electricity relates to 
the physica l trading of electricity for consumption. The trading on the wholesale market of the 
generated electricity is to be distinguished from financial trading, i.e. the trade in financial 
instruments relating to electricity, such as forwards, futures, options, c ontracts for differences (CfD), 
or other derivatives; see, e.g. M.8660 – FORTUM / UNIPER , paragraphs 37 et seq.  
10  See, e.g., cases M.10387 – MERIDIAM / ALLIANZ / NEUCONNECT , paragraph 29; M. 8871 – RWE 
/ E.ON ASSETS , paragraphs 13 et seq.; M.8870 – E.ON / INNOGY , paragraph 35; M.8660 – 
FORTUM / UNIPER , paragraphs 18 et seq.  
11 The Commission left open whether a distinction needed to be made between peak and off -peak hours 
in cases M.5467 – RWE / ESSENT and M.6225 – MOLARIS / COMMERZ REAL / RWE / AMPRION . 
12 Although the Bundeskartellamt  has considered a separate market for renewable -based generation in 
Germany (due to the German subsidy regime) (M.10387 – MERIDIAM / ALLIANZ / NEUCONNECT , 
paragraphs 30 et seq.), neither the Commission (M.5467 – RWE / ESSENT ) nor the Dutch 
Competition Authority (the ‘ACM’) has considered there to be a separate market for renewable -based 
generation in the Netherlands.  
13  Form CO, paragraphs 127 -129. 
 
 
5 supply of electricity, including trading on the wholesale market in the Netherlands 
and imports of electricity produ ced outside of the Netherlands.14 
(14) The market investigation also confirmed that a further segmentation (i) by hours of 
the day or (ii) by the source of electricity generation was not warranted. Regarding 
a possible segmentation between peak - and off -peak hours, the Commission notes 
that such possible segmentation has not been retained in recent  decisions.15 Also 
none of the respondents sub mitted arguments or evidence supporting such 
segmentation.16 Regarding a possible segmentation by generation source, i.e. 
renewable and conventional sources, the large majority of respondents submitted 
that the market includes both renewable and conventiona l generation .17 
Respondents  noted  that “ both markets would not function individually ” and that  
electricity from both renewable and conventional sources “ are competing with each 
other on the same market at the wholesale level ”.18  
(15) For the purposes of this decision, and in light of the above, the Commission finds  
no reason to deviate from its consolidated case practice. The Commission therefore 
considers that the overall market for generation and wholesale supply of electricity 
const itutes a separate market encompassing both the trading on the wholesale 
market of the generated electricity within a certain geographic market and the 
electricity that is physically imported into this geographic market via 
interconnectors , irrespective of the source of generated electricity (such as nuclear, 
lignite, wind, solar, etc.) . In any event,  the Transaction does not raise serious 
doubts as to its compatibility with the internal market or the functioning of the 
EEA Agreement regardless of the exact product market definition adopted .  
4.2.2.  Geographic market  
4.2.2.1.  The Commission’s decisional practice  
(16) The Commission has previously defined  the geographic market for the generation  
and wholesale supply of electricity as national in scope .19 However, the 
Commission  has also recognised  that the presence of a sufficiently large 
                                                 
14  See responses to question B.A.1 of the electronic Request for Information sen t to market participants 
as part of the formal market investigation (‘eRFI’). The large majority of respondents agreed that this 
definition continues to properly reflect the market conditions and noted, for instance, that they “ see 
no material difference i n [their] perception of the market for generation and wholesale supply of 
electricity and the definition of the market [retained] by the Commission ” (responses to question 
B.A.2 of eRFI).  
15  The Commission considered a possible segmentation between peak - and off -peak hours in older cases 
but ultimately left the definition open due to an inconclusive market investigation in that regard. See, 
e.g., cases M.5979 – KGHM / TAURON WYTWARZANIE / JV , paragraphs 17 et seq.; M.5467 – 
RWE  / ESSENT , paragraph 25; and M.4370 – EBN / COGAS ENERGY , paragraph  15. In more recent 
cases, the Commission no longer discussed the possible segmentation between peak - and off -peak 
hours. See, e.g., cases M.10387 – MERIDIAM / ALLIANZ / NEUCONNECT , paragraphs 29 et seq.; 
M. 8871 – RWE  / E.ON ASSETS , paragraphs 13 et seq.; M.8870 – E.ON / INNOGY , paragraphs 35, 
451 et seq., 621 et seq.; M.8660 – FORTUM / UNIPER , paragraphs 18 et seq.  
16  See responses to question B.A.2 of eRFI.  
17  See responses to question B.A.3 of eRFI.  
18  See responses to question B.A.4 of eRFI.  
19  See e.g. cases M.10387 – MERIDIAN / ALLIANZ / NEUCONNECT , paragraph 35; M.5979 – 
KGHM  / TAURON WYTWARZANIE / JV , paragraph 24; M.5711 – RWE / ENSYS , paragraph 21;  and 
M.4180 – GDF / SUEZ , paragraph 726.  
 
 
6 interconnection capacity between Member States may justify a broader 
geographical scope.20 This could also be the case if two  or more Member States 
belong to the same bidding zone.21 
4.2.2.2.  The Notifying Party’s view  
(17) The Notifying Party does not contest  the Commission’s previous practice . Indeed , 
the Notifying Party has conducted a price -equality analysis for the Netherlands and 
the bidding zones that it is coupled with and submits that the result of the a nalysis 
provides no indication that the relevant geographic market is wider than national in 
scope.22  
(18) The Notifying Party further submits that a potential review of the existing  bidding 
zones23 would have no impact on the scope of the relevant geographic ma rket in 
the present case.24 In the Notifying Party’s view, a potential bidding zone split in 
the Netherlands into a n orthern and a southern bidding zone is highly unlikely, will 
take at least until 2027 to complete and would have only a transitory impact on  
market concentration given the decommissioning of coal plants in the Netherlands 
by 2030. Moreover, the bidding zone review is supposed to take into account 
liquidity and competition concerns and should, therefore, solve rather than 
reinforce them, if any .25 
4.2.2.3.  The Commission’s assessment  
(19) In line with  the Commission’s findings in previous cases and the  Target’s location 
in and connection with the Dutch electricity transmission system which forms a 
single bidding zone, the Commission started its assessment on a  national basis and 
investigated whether current market conditions indicate a wider -than-national or a 
narrower -than-national delineation of the electricity generation and wholesale 
supply market concerning the Netherlands.  
(20) The majority of respondents to the market investigation consider the geographic 
scope of the market to be wider than national, including the Netherlands and at 
least parts of neighbouring countries,26 primarily due to the interconnection of the 
Dutch bidding zone with neighbouring bidding zones.27 In contrast , the Dutch 
electricity market regulator , the Authority for Consumers and Markets (‘ ACM ’) 
                                                 
20  See e.g. c ase M.10387 – MERIDIAM / ALLIANZ / NEUCONNECT , paragraph 35.  
21  See e.g. case M.8871 – RWE / E.ON ASSETS , paragraph 17.  In the case of the Netherlands, the 
relevant bidding zone corresponds to the national territory of the Netherlands.  
22  Form CO, paragra phs 149 et seq.  
23  The European Union Agency for the Cooperation of Energy Regulators (‘ACER’) has advised TSOs 
to conduct a review of existing bidding zones and to recommend whether to keep or amend the 
existing bidding zones. For the Netherlands, ACER h as proposed to consider an alternative 
configuration consisting of a Northern and a Southern bidding zone within the Netherlands. The 
recommendations are expected in August 2023, followed by a joint decision of the Member States 
within six months following  the recommendations on whether or not to change the bidding zones 
accordingly . See, e.g., https://www.acer.europa.eu /events -and-engagement/news/acer -has-decided -
alternative -electricity -bidding -zone -configurations .  
24  Form CO, paragraphs 132 et seq.  
25  Form CO, paragraphs 133 -134. 
26  See responses to question C.A.2 of eRFI.  
27  See responses to question C.A.3 of eRFI.  
 
 
7 (which is also the Dutch competition authority) , consider s the market to be 
national.28  
(21) Indeed, the Netherlands has cross -border electrical  interconnections with Germany, 
Belgium, Denmark, Norway and Great Britain.  In 2021, total Dutch electricity 
imports relative to domestic electricity consumption amounted to 18.4%, while the 
total Dutch electricity exports amounted to 18.2% relative to ele ctricity 
consumption in the Netherlands,29 which represents a non -insignificant share of the 
total domestic consumption and generation .30 Interconnector capacity is determined 
by the TSO as a total figure for all interconnectors between two bidding zones and  
not individually for each physical interconnection. This is because the available 
interconnector capacity is a function, not only of the capacities on the tie lines, i.e. 
the physical circuit connecting two bidding zones , but also determined by 
restrictions elsewhere in the grid.31 On this basis, the total available import capacity 
across the four interconnectors between the Netherlands and Germany is 4.3 GW in 
2022.32 Belgium is connected to the Netherlands via two interconnectors with a 
total imp ort capacity of 2.4 GW. Denmark, Norway, and Great Britain  are each 
connected via one interconnector with respective import capacities of 0.7 GW for 
Norway33 and Denmark34 each and 1.0  GW for Great Britain .35 In theory, therefore, 
the Netherlands’ cross -borde r electrical interconnections with neighbouring 
bidding zones should allow it to react quickly to domestic price changes , which 
could indicate a wider -than-national market concerning the Netherlands.  
(22) However , differences in electricity spot prices between  two neighbouring bidding 
zones can be  indicative of differences in  competitive conditions, for instance due to 
transmission congestion between those bidding zones. A price -equality analysis 
carried out by the Notifying Party on the basis of 2021 day -ahead prices shows that 
of the four bidding zones that the Netherlands  is coupled with,36 the share of (close 
to) equal prices does not exceed 56%, i.e. in almost half of all hours of a year 
prices are different,  indicating non -homo genous conditions of competition in the 
different coupled bidding zones .37 The results and conclusions of the analysis of the 
Notifying Party are in line with those of a similar price -equality analysi s carried out 
by the German Federal Cartel Office (‘FCO’ ) for 2021. Like the Notifying Party  
for the Dutch market and its coupled neighbouring bidding zones , the FCO found 
significant price differences throughout the year between Germany and its coupled 
                                                 
28  Email from ACM to DG COMP on 09/11/2022.  
29  Form CO, Tables 14 and 15.  
30  Form CO, paragraphs 114 -115 and Tables 14 and 15.  
31  Restrictions elsewhere in the grid limit the volumes which can arrive at or be forwarded from the 
interconnection point.  
32  Interconnection capacity with Germany is e xpected to increase to 5.0 GW by 2025; see Form CO, 
paragraph 118, with reference to TenneT NL (2021), Monitoring Leveringszekerheid  2021, Tables 3 -
4.  
33  Norway is currently split into five bidding zones. The Neth erlands is connected to the South 
Norwegian bidding zone “NO2”.  
34  Denmark is currently split into two bidding zones. The Netherlands is connected to the West Danish 
bidding zone “DK1”.  
35  Form CO, paragraph 118.  
36  Despite the interconnector between the  Netherlands and the UK, the Dutch bidding zone is no longer 
coupled with the British bidding zone since the UK’s exit from the market couple in 2021.  
37  Form CO, paragraph 152. Results do not change materially between peak and off -peak periods.  
 
 
8 neighbouring bidding zones and concluded that Germany38 and its neighbours 
(including the Netherlands) should be considered separate geographic markets.39  
(23) The Commission notes that while interconnection capacity between the 
Netherlands and neighbouring bidding zones is planned to increase in the coming 
years,40 its impact on the geographic scope of the market for generation and 
wholesale supply of electricity in the Netherlands remains uncertain at this point in 
time.  
(24) The Commission therefore considers that the relevant geographic market is 
currently not wider than  national with regard to the Netherlands.  
(25) In relation to a potential narrower  market, the large majority of respondents to the 
market investigation as well as the ACM do not consider the market to be narrower 
than national.41 
(26) This is not contradicted by the current review of bidding zones in Europe as 
recommended by  the Agency for the Cooperation of Energy Regulators 
(‘ACER ’).42 Indeed, TenneT currently conducts a review  of the Dutch bidding zone 
to establish whether  the Netherlands should be split into a northern and a southern 
bidding zone. A potential bidding zone split of the Netherlands is however highly 
uncertain, as an amendment of the current bidding zone configuration requires 
unanimous vote by all affected Member States. Germany, one of the affect ed 
Member States, has been consistently vocal in its opposition against a split of the 
German bidding zone and the position of the Dutch government regarding a 
potential split of the Dutch zone is currently uncertain.43 In any case, even if such a 
split is found appropriate, a  potential bidding zone split of the Netherlands would 
take at least until 2027 to complete (if at all) , as stakeholders in the energy sector 
require time to prepare and adapt their systems to the change.   
(27) The Commission therefore consi ders that there is currently no justification for a 
narrower -than-national geographic market  in the Netherlands.  
(28) In light of the foregoing, the Commission considers that the appropriate scope of 
the market for the generation and wholesale supply of electricity regarding the 
Netherlands is national, corresponding to the Dutch bidding zone, while 
acknowledging the real ity of flows from neighbouring bidding zones.  
                                                 
38  The re levant bidding zone for Germany includes Luxembourg.  
39  Bundeskartellamt, “ Wettbewerbsverhältnisse im Bereich der Erzeugung elektrischer Energie 2021 ”, 
Marktmachtbericht  (February 2022), paragraphs 37 -43. Dutch TSO TenneT found from a similar 
price -equali ty analysis that the day -ahead market price in the Netherlands and in Germany was 
convergent in 53% of the time in 2021. For the remaining time, prices were higher in Germany more 
often (27% overall) than in the Netherlands (20% overall); see TenneT, “ Annu al Market Update 
2021 ” (April 2022), slide 34.  
40  Form CO, paragraph 122, with reference to TenneT’s “ Ontwerpinvesteringsplan – Net op land 2022 -
2031 ”, section 4.2.3.  
41  See responses to question C.A.2 of eRFI, and email from ACM to DG COMP on 09/11/2022 . 
42  ACER, Decision No. 11/2022 of 8 August 2022 on the alternative bidding zone configurations to be 
considered in the bidding zone review process , available at https://www.acer.europa.eu/events -and-
engagement/news/acer -has-decided -alternative -electricity -bidding -zone -configurations.  
43  Form CO, paragraph 132.  
 
 
9 4.3. Balancing and ancillary services  
(29) TenneT  has the responsibility of  maintain ing the frequency of the electricity grid 
within a very narrow bandwidth (at a frequency of 50  Hz).44 In order to do so, 
TenneT procures  balancing and ancillary services from generators such as the 
Parties, by ensuring there is always a balance between electricity production and 
consumption.45  
(30) Upward (positive) reserve (i.e. increase of power output) is required if there is not 
enough elec tricity in the grid and the frequency drops below 50 Hz , and downward 
(negative) reserve (i.e. decrease of power) is required if there is too much 
electricity in the grid and the frequency exceeds the target frequency of 50 Hz.46 
(31) If an imbalance occurs in t he Netherlands, TenneT sends  a signal  to th ose 
generators who have decided to act as balance service providers  (‘BSP’) who then 
activate balancing energy in order to reinstate the system balance.  BSPs are 
required to prequalify to provide  balancing services to TenneT.47 In addition, to 
avoid imbalances, each supplier or buyer with a connection to the grid carries a 
balance responsibility and must be connected to a Balance Responsible Party 
(‘BRP’). A BRP is financially responsible for any i mbalances that occur in their 
portfolio grid allocation points.  
(32) There are three main products for balancing  and that are provided by BSPs .48 These 
are:  
a. Frequency Containment Reserves (‘FCR’ ): The aim of FCR is to stabilise 
frequency disturbances and it  is activated automatically when the frequency  
deviates . In order to fulfil its international balancing obligation, TenneT 
procures the amount of FCR established by EU Regulation49;  
b. automatic Frequency Restoration Reserve (‘aFRR’): this is one of the two 
main balancing products used in the Netherlands. BSPs make two bids in a 
two-step process : (i) a capacity bid for reserved capacity, based on which  the 
BSP is paid to reserve capacity and , if called upon, the BSP will be obliged 
to make an energy bid; (ii) an e nergy bid which is a payment to the BSP  for 
activation of reserved capacity and is activated based on the merit order50 of 
sorted aFRR energy bids ( which includ es “free bids”  from BSPs without a 
prior capacity contract  from the first step ); and  
c. manual Frequency Restoration Reserve (‘mFRR’): this is the other of the two 
main balancing products used in the Netherlands. Market participants need to 
have the capacity available and , when needed, TenneT activates the amount  
manually , without the use of a  merit order list.  
                                                 
44  Form CO, paragraph 415.  
45  TenneT website: https://www.tennet.eu/balancing -markets.  
46  Form CO, paragraph 416.  
47  TenneT website: https://www.tennet.eu/balancing -service -providers -bsp. 
48  TenneT  website: https://www.tennet.eu/balancing -markets.  
49  Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity 
balancing.  
50  The merit order is a ranking method for electricity generation where the bids are ranked by  price.  
 
 
10 (33) As noted above, to avoid imbalances, each supplier or buyer with a connection to 
the grid carries a balance responsibility BRP.51 BRPs  are able to  correct their own 
imbalance before the imbalance settlement period ends (‘ISP’ ), without f acing 
financial consequences. This can be done, for example, by increasing or decreasing  
production or by making a trade with another BRP. TenneT also publishes real -
time imbalance prices. With this information, BRPs can decide to increase or 
decrease the imbalance, if it helps the overall system balance. TenneT settles the 
BRP for this imbalance, according to the imbalance price.  
(34) The Transaction only gives rise to an overlap in aFRR52, which is the focus of the 
Commission’s assessment regarding balancing and ancillary services.   
4.3.1.  Product market  
4.3.1.1.  The Commission’s decisional practice  
(35) The Commission has previously taken the view that the provision of balancing and 
ancillary services is distinct from the market for the generation and wholesale 
supply of electric ity.53 
(36) The Commission has previously considered whether balancing and ancillary 
services should be divided into submarkets for (i)  FCR, (ii) aFRR, and (iii) mFRR, 
based on the order of activation and the magnitude of frequency deviation.54  
(37) The Parties’ acti vities only overlap in aFRR. Within aFRR, the Commission has 
considered the upwards (i.e. increase of power output)  and downwards (i.e. 
decrease of power output) regulation of aFRR.55 
4.3.1.2.  The Notifying Party’s view  
(38) The Notifying Party considers that the relevant product market is the market for 
balancing and ancillary services (without any further segmentations).56 
4.3.1.3.  The Commission’s assessment  
(39) All respondents  to the Commission’s market investigation that expressed a vi ew 
considered that the provision of balancing and ancillary services is a distinct 
market from the market for the generation and wholesale supply of electricity . As 
noted by market participants, the TSO, TenneT is the sole purchaser of balancing 
and ancill ary services in the Netherlands .57 The market for the generation and 
                                                 
51  Pursuant to the Electricity Act and underlying regulations, power plant operators have to appoint a 
BRP (and a BSP) which have to be recognised as such and registered by TenneT (Form CO 
paragraph 659). A BRP can be a generator, a large user, an energy supplier or an energy trader, 
whereas a BSP is a generator.  
52  Form CO, paragraph 460.  
53  See e.g. cases M.9626 – PKN ORLEN / ENERGA , paragraph 21 and M.8660 – FORTUM / UNIPER , 
paragraphs 19, 69 et seq.  
54  See e.g. cases M.9626 – PKN ORLEN / ENERGA , paragraph 22 and M.8660 – FORTUM / UNIPER , 
paragraph 54, 78.  
55  See e.g. case M. M.8660 – FORTUM / UNIPER , paragraph 311.  
56  Form CO, paragraph 454.  
57  See responses to question B.B.1 of eRFI and response  to question B.A.1 of Request for Information 1 
to TenneT.  
 
 
11 wholesale supply of electricity does not have a single purchaser but rather many 
purchasers (see Section 4.1). 
(40) The vast majority of respondents also indicated that within balancing and ancillary 
services, there should be separate markets for FCR, aFRR and mFRR.58 As one 
participant noted: “ FCR, aFRR and mFRR are distinctly different  products for 
which different types of (production) assets are suited .”59 Similarly, TenneT 
indicated that “ these markets have very distinct technical requirements and are not 
a substitute for one another .”60 
(41) The market inves tigation was inconclusive as to whether separate markets exist for 
(a) upwards regulation of aFRR and (b) downwards regulation of aFRR. In 2021, 
TenneT started to procure upwards and downwards aFRR capacity separately.61 In 
response to the market investigat ion, a  slight majority of respondents indicated that 
separate markets  exist for upwards and downwards regulation , with some 
indicating that more providers were now active in aFRR since they were able to 
provide either upwards or downwards regulation (and were not obliged to provide 
both) .62 Another market participant noted that “ different asset types can deliver 
upward and downward capacity to Tenne T, these assets do not need to be 
dispatched by the same company. Separating these products leads to a lower n et 
cost of energy .”63 On the other hand, a significant minority of mar ket participants 
noted that the same assets could provide both upwards and downwards regulation 
of aFRR, although the costs of providing the service may differ according to the 
asset used , and which may influence the direction of aFRR regulation offered. As 
explained further by TenneT, “ technical requirements for both are the same, and 
assets providing aFRR in one direction should also be capable of providing aFRR 
in the opposite direction , even while, depending on used assets (e.g. power plant, 
battery, demand side response), different (opportunity) costs could lead to different 
(cost)  prices for provision of balancing capacity in either direction .”64  
(42) In light of the above, the Commission considers tha t balancing and ancillary 
services are in a separate product market to the generation and wholesale supply of 
electricity. Within balancing and ancillary services, the Commission considers that 
there are separate product markets for the provis ion of FCR, aFRR and mFRR. The 
question of whether the  product market  for the provision of aFRR should be further 
segmented between upwards and downwards regulation can be left open as the 
Transaction does not raise serious doubts as to its compatibility w ith the internal 
market or the functioning of the EEA Agreement  regardless of the exact product 
market definition adopted .  
                                                 
58  See responses to question B.B.3 of eRFI . 
59  Response to question B.B.4 of eRFI . 
60  Response to B.A.2 of Request for Information 1 to TenneT.  
61  This follows from Article 32(3) of Commission Regulation (EU) 2017/2195 of 23 November 2017, 
respo nse to question B.A.3 of Request for Information 1 to TenneT.  
62  See responses to question B.B.5 of eRFI . 
63  Response to question B.B.6 of eRFI.  
64  Response to question B.A.3 of Request for Information 1 to TenneT.  
 
 
12 4.3.2.  Geographic market  
4.3.2.1.  The Commission’s decisional practice  
(43) The Commission has previously considered the geographic scope of the market for 
the provision of balancing and ancillary services to be national in scope65, and 
potentially even limited to the relevant TSO’s control area or a bidding zone.66 The 
Commission has previously considered the geographic scope of aFRR to be 
national.67 
4.3.2.2.  The N otifying Party’s view  
(44) The Notifying Party agrees with the Commission’s previous practice.68  
4.3.2.3.  The Commission’s assessment  
(45) A majority of respondents to the Commission’s market investigation considered 
that the scope of the geographic market was national.69 This was in particular  due 
to the national scope of the bidding market. As noted by one market participant: 
“Offering aFRR to TenneT is possible as long as you are based in the Netherlands 
and connected to the TenneT grid .”70 TenneT noted that while BSPs could  be 
accredited by TSOs in different countries, in order to provide balancing services, 
and in particular aFRR, it was necessary for pre -qualified assets and grid 
connections to be located in the Netherlands.71 
(46) In light of the above, the Commission will for the purpose of this decision conduct 
the competitive assessment for the provision of aFRR (and for upwards and 
downwards regulation) at the national  level . 
4.4. Congestion management  
(47) Congestion refers to a situation where after the failure of a single network elem ent 
(such as a transmission line,  transformer or generating unit) the network elements 
remaining in operation would not be capable of accommodating the change of 
flows in the network caused by that single failure, i.e. there is insufficient 
redundancy in the network to withstand the failure of a single network element.72 
                                                 
65  M.5467 – RWE / ESSENT , paragraph 21. I n this case concerning the Netherlands, the Commission 
noted that the balancing market was national but, given that there were no overlaps between the 
Parties in balancing, did not consider the issue in detail.  
66  See e.g. cases M.9626 – PKN ORLEN / ENERGA , paragraph 26 and M.8660 – FORTUM / UNIPER, 
paragraph 98 . 
67  M.8660 – FORTUM / UNIPER, paragraph 98.  
68  Form CO, paragraph 454.  
69  See responses to question C.B.3 of eRFI.  Response to question C.A.2.2 of Request for Information 1 
to TenneT.  
70  Response to question C.B.4 of eRFI.  
71  Response to question C.A.1.1 of Request for Information 1 to TenneT.  
72  The Notifying Party’s response of 21/11/2022 to Request for Information 13 of 16/11/2022. In 
relation to congestion, the European Network of Tra nsmission Operators for Electricity (ENTSO -E) 
refers to the N -1 criterion, which it defines as “ … a rule according to which elements remaining in 
operation after failure of a single network element (such as transmission line / transformer or 
generating uni t, or in certain instances a busbar) must be capable of accommodating the change of 
flows in the network caused by that single failure”  (UCTE Operation Handbook – Glossary (final 
 
 
 
13 (48) The TSO, TenneT , has the statutory task of safeguarding the grid security of the 
entire electricity system in the Netherlands, which includes resolving congestion.  
Congestion can be reso lved in the short term through a number of different 
measures:73 
a. Switching operations: Switching different network elements (e.g. 
transmission lines or phase shifting transformers) on or off can change the 
load of network elements and resolve congestion . This congestion 
management option relates to the grid assets controlled by the TSO (i.e. it is 
an operational grid -related measure) and does not concern a market service 
provided by third parties (such as the Parties), and therefore it will no t be 
discussed further in this d ecision.  
b. Countertrading: The TSO buys and sells electricity on the wholesale market 
to change the flow of electricity between bidding zones  to resolve 
congestion . In the Netherlands, TenneT does not actively use countertrading  
(it has not used it in the past three years  and it has not indicated that it is 
likely to use it in the coming years )74 and therefore it will no t be discussed 
further in this d ecision.  
c. Redispatch: The TSO asks , using a constant bidding process,  consumers and 
producers to increase/decrease consumption/production compared to their 
original schedule to change dispatch and load flow patterns to resolve 
congestion. For TenneT, redispatch always consists of two inter-related  
transactions – the first with a counterpart that op erates an asset  (e.g. a power 
plant)  in the congested area, the second in the opposite direction with a 
counterpart that operates an asset  outside of the congested area  (which could, 
but does not have to be, the same counterpart as in the first transaction ). 
d. Capacity restriction  agreements : a generator is  paid by the TSO  for not using 
(part of) its  contracted capacity . TenneT uses bilateral capacity restriction 
agreements mainly for when it foresees congestion,  in particular when  
maintenance and upgrading projects on specific lines  are planned .75 
(49) In the medium/long term, congestion can be mitigated against  by upgrading or 
building new transmission lines and transformers.76 
(50) In the Netherlands, TenneT uses r edispatching more than  capacity restriction 
agreements  as part of its congestion management .77 The differences between these 
two measures are outlined in paragraphs (51) – (54). 
(51) TenneT organises redispatching by purchasing a regulated product called Re serve 
Power Other Purposes ( Reservevermogen Overige Doeleinden or ‘ROD ’) from 
                                                                                                                                                      
v2.2 E, 24.06.2004)). Congestion can be defined as a situation in which N -1 safety of network 
elements is no longer guaranteed (Form CO, paragraph 498).  
73  Form CO, paragraph 500.  
74  Response from TenneT to Request for Information 1 of 23/11/2022 and Response from the Notifying 
Party to RFI 13.  
75  Response from TenneT to Request fo r Information 1 of 23/11/2022.  
76  Form CO, paragraph 501.  
77  Minutes of call between DG COMP and TenneT on 12/12/2022.  
 
 
14 market participants , where they state the conditions (minimum duration and price 
for a specified volume of capacity, whether for an upward or downward adjustment 
to their product ion or consumption) under which they are willing to transact with 
TenneT . As described in the Netcode Elektriciteit  (Dutch Grid Code), consumers 
and producers with a connection capacity of over 60 MW are obligated to submit 
ROD bids to TenneT.  Parties with connection capacities below 60 MW can submit 
bids on a voluntary basis . 
(52) Prices for RODs are determined throug h a competitive bidding process, and bids 
are only activated by TenneT in case of congestion. ROD bids are submitted at  
plant level ( or generator level  where a plant has more than one generator block 
feeding into different grid connection points)  as the activations largely depend on 
the location of the power  plant in relation to the congestion at hand.  Redispatch is 
temporally organised  in quarter hours, i.e. bids are submitted for each of the 96 15 -
minute blocks per day  and when needed TenneT activates redispatch for one 15 -
minute block or a consecutive block of several 15 -minute periods.  
(53) The total redispatch volumes  activated  amounted  to approximately 1.3 TWh in 
2021, corresponding to approximately 1% of total power demand in the 
Netherlands.78 
(54) For c apacity restriction agreements , TenneT contacts either one or more  generator s 
who TenneT considers can resolve the specific foreseen conges tion and requests 
either a capacity restriction of a certain unit or that they have to generate  power 
between a certain minimum and maximum range ( a ‘must-run’) from a certain unit  
for a period that can be for several hours, or one or more days. The generator 
typically has 2 – 4 days to send their offer to TenneT. In some instances, TenneT 
provides a reason for the request (e.g. grid maintenance).79 
4.4.1.  Product market   
4.4.1.1.  The Commission’s d ecisional practice  
(55) The Commission has not defined a separate product market for congestion 
management services, nor has the ACM done so for the Netherlands.80 However, i n 
a previous decision, and with reference to the legal situation in Belgium, the 
Commiss ion referred to congestion management in the context of balancing and 
ancillary services  but, in that decision, it did not define  congestion management as 
being a different market  from balancing and ancillary services .81  
4.4.1.2.  The Notifying Party’s view  
(56) The Noti fying Party submits that it does not consider congestion management 
services to be a separate market from the market for balancing and ancillary 
services.82 But if considered to be a separate product market, the market for 
congestion management should at least include both redispatching services and 
                                                 
78  Form CO, paragraph 502.  
79  Response dated 13/12/2022 from the Notifying Party to Request for Information 19.  
80  Form CO, paragraph 497 . 
81  Case M.4180 – GAZ DE FRANCE / SUEZ , paragraph 684.  
82  Form CO, paragraphs 497 and 516.  
 
 
15 capacity restriction agreements .83 This view is based on  the perception that  the 
services are regarded by TenneT as inte rchangeable ways to resolve congestion, 
and on the facts that: (i)  TenneT reports the cost for congestion management by 
combining both redispatch and capacity restriction agreements; (ii) the services are  
only offered to the same customer , namely TenneT; a nd (iii) the services are likely 
offered by the same suppliers.  
4.4.1.3.  The Commission’s assessment  
(57) Although TenneT recognises that generation assets are often capable of providing 
both congestion management and balancing services, TenneT confirmed that it 
conside rs congestion management to be distinct from balancing and ancillary 
services, noting that  from its perspective  “[a]n imbalance problem cannot be 
solved using congestion management services and vice versa ”, i.e. congestion 
management services and balancing  and ancillary services serve different 
purposes .84 
(58) The majority of respondents to the market investigation also consider the provision 
of congestion management services to be a distinct market from the provision of 
balancing and ancillary services.85 Respon dents commented that “ [t]he allocation 
of demand and supply of congestion management services is organised in a 
separate segmented market compared to the market for balancing and ancillary 
services ” and “ [c]ongestion services do not aim to balance the grid  but to solve 
congestion. This is a scheduled activity (unlike ancillary) and also has no indirect 
impact on imbalance prices ”.86 
(59) The Commission considers the market for the provision of congestion management 
services to be a distinct market, separate from the market for the provision of 
balancing and ancillary services . Potential congestion and imbalance in the network 
are different problems for which TenneT  is responsible and from the demand -side 
perspective of TenneT the provision of such services are for  different purposes. 
From a supply -side perspective, there are different bidding processes for each of 
imbalance and congestion (see above paragraphs (32) and (51) respectively). 
Furthermore , unlike the situation for imbalances described in paragraph (33) where 
a BRP is financially responsible for any imbalances that occur in their portfolio 
grid allocation points, generators are not financially responsible for congestion.  
(60) It can be left open whether the product market for the provision of congest ion 
management services should be segmented between redispatching and the use of 
capacity restriction agreements  as the Transaction does not raise  serious doubts as 
to its compatibility with the internal market and the functioning of the EEA 
Agreement, reg ardless of the exact product market definition adopted.  
                                                 
83  Response dated 13/12/2022 from the Notifying Party to Request for Information 19.  
84  Response from TenneT to Request for Information 1 of 23/11/2022.  
85  See responses to question B.C.5 of eRFI.  
86  See responses to question B.C.6 of eRFI.  
 
 
16 4.4.2.  Geographic market  
4.4.2.1.  The Commission’s decisional practice  
(61) As noted in  paragraph  (55) the Commission has not  defined a separate product 
market for congestion management services  before , and therefore it has not 
previously defined its appropriate geographic scope.  
4.4.2.2.  The Notifying  Party’s view  
(62) The Notifying Party submits that providing a general  delineation of the geographic 
market for the provision of  congestion management services  is not feasible 
considering the characteristics of this market, noting  that the geographic scope of 
the market may vary depending on the specific  congestion.87 However, the 
Notifying Party notes that, from a technical perspective, congestion is not normally 
solved on a zonal basis (e.g. the zone of the northern Netherlands) but applies to 
the entire area operated by TenneT, i.e. the Netherlands, or even beyond (in case of 
cross -border redispatch).88 
4.4.2.3.  The Commission’s assessment  
(63) TenneT agrees that the geographic scope for a given congestion event “ is highly 
dependent on the constraint [because]  only relevant connections in the right 
location can usefully contribute to mitigating congestion on a specific grid 
element .”89 In general, however, TenneT confirms that for redispatching, which 
always consists of two transactions, the geographic scope relates to both th e 
congested area (where generation  must be curtailed) and another area (where 
generation  must be ramped up)  – and indeed the other, non -congested area could 
under some circumstances be a cross -border area in a neighbouring country. 90  
(64) A majority of the res pondents to the market investigation consider the geographic 
scope of the market for congestion management services to be national.91 However, 
comments also pointed towards a more local element, relating to the particular type 
of congestion. For example, one respondent commented that “ [t]here is a national 
market place for the provision of congestion management services, on which bids 
in relation to the Netherlands are put.  That said, bids may concern very specific 
locations. As a consequence, the demand can  be on a narrower basis than national. 
It should also be noted that the solution for a local issue may come from abroad 
the Netherlands .”92 
(65) The Commission considers that the geographic scope of the market for congestion 
management services in relation to the Netherlands is at least national. While each 
specific congestion event relates to a specific location, in general generation assets 
                                                 
87  Form CO, paragraph 517.  
88  Form CO, paragraph 499. The Notifying Party points to Article 13, sub 1 of the Electricity Regulation 
(No. 2019/943) which states “ The redispatch ing of generation and redispatching of demand response 
shall be … open to all generation technologies, all energy storage and all demand response, 
including those located in other Member States unless technically not feasible”.  
89  Response from TenneT to R equest for Information 1 of 23/11/2022.  
90  Form CO, paragraph 517.  
91  See responses to questions CC1 – CC4 of eRFI.  
92  See response to question CC2 of eRFI.  
 
 
17 throu ghout the Netherlands are active  on the supply side  of congestion 
management services.  TenneT, the only purchaser on the demand side, is also 
active on a national level.  It can be left open whether the geographic scope is wider 
than national as , based on t he conservative assumption of a national market,  the 
Transaction does not lead to serious doubts as to its compatibility with the internal 
market  and the functioning of the EEA Agreement .  
4.5. Conclusion on market d efinition  
(66) In light of the above, and for the purposes of this decision, the competitive 
assessment will be based on the following market definitions:   
a. the market for generation and wholesale supply of electricity  in the 
Netherlands ;  
b. the market for aFRR (and its possible sub -segments for upwards and 
downwards regulation of aFRR) in the Netherlands; and  
c. congestion management  (and its possible sub -segments of redispatching and 
capacity restriction agreements)  in the Netherlands . 
5. COMPETITIVE ASSESSMEN T  
5.1. Analytical framework  
(67) The legal test for the assess ment of horizontal effects of a merger is set out in the 
Merger Regulation and in the Guidelines on the assessment of horizontal mergers 
under the Council Regulation on the control of concentrations between 
undertakings (‘Horizontal Merger Guidelines’ ).93 
(68) Horizontal effects are those deriving from a concentration where the undertakings 
concerned are actual or potential competitors of each other in one or more of the 
relevant markets concerned. The Horizontal Merger Guidelines distinguish 
between two main wa ys in which mergers between actual or potential competitors 
on the same relevant market may significantly impede effective competition, 
namely non -coordinated and coordinated effects.94 
(69) Non-coordinated effects may significantly impede effective competition through 
the creation or strengthening of the dominant position of a single firm, or through 
the elimination of important competitive constraints on one or more firms, which 
consequently would allow those firms to have increased market power without 
resorti ng to coordinated behaviour. In that regard, the Horizontal Merger 
Guidelines consider not only the direct loss of competition between the merging 
firms, but also the reduction in competitive pressure on non -merging firms in the 
same market that could be b rought about by the merger.95 
(70) The Horizontal Merger Guidelines list a number of factors to be taken into 
consideration when assessing whether significant non -coordinated effects are likely 
                                                 
93  OJ C 31, 05.02.2004.  
94  Horizontal Merger Guidelines, paragraph 22.  
95  Horizontal Merger Guidelines, paragraphs 23 -24. 
 
 
18 to result from a merger, such as large market shares of the merging firms, the fact 
that the merging firms are close competitors, the limited possibilities for customers 
to switch suppliers, or the fact that the merger would eliminate an important 
competitive force. Not all of these factors need to be present to make non -
coordinated effects likely, nor does this constitute  an exhaustive list.96 
5.2. Generation and wholesale supply of electricity  
5.2.1.  Introduction  
(71) In wholesale electricity markets, spot market prices97 are set according to the  short -
run marginal cost  (‘SRMC ’) of the different generation asset s in the merit orde r.98 
Capacity is sold in the order of the production units’ SRMC (starting from the 
lowest) and the overall market price is set by the production unit with the highest 
SRMC that is required to serve demand. This is  the so -called “marginal” unit.99 
Whether a plant is marginal or not can change frequently, depending on the 
demand and supply of electricity at any given point  in time.  
(72) Renewable  sources  have the lowest SRMC and are prioritised in meeting demand, 
which mea ns these generation assets are situated to the left of the merit order  (so-
called “infra -marginal” units ).100 Flexible generation assets , i.e. controllable assets 
that can be ramped up or down on demand (such as gas -fired, coal -fired, and 
hydropower plants) , have higher SRMC and are situated on the right of  renewables 
in the merit order  and can be infra -marginal, marginal or outside of the merit order  
needed to meet demand , depending on the load of demand . Figure 2 below shows 
an illustrative  merit order for the Netherlands.  
Figure 2 - Illustrative merit order for the Netherlands   
 
Source: Form CO, Figure 30.  
                                                 
96  Horizontal Merger Guidelines, paragraphs 26 -38. 
97  At wholesale level, electricity can also be sold via bilateral contracts (also called over -the-counter 
sales, or ‘OTC’) between electricity generators and customers. OTC co ntracts can stipulate fixed 
prices or index their price on the spot market price. Spot market sales via power exchanges and OTC 
sales are typically linked by arbitrage, which means that no significant price differences are expected 
between the two sales ch annels (Form CO, paragraph 583).  
98  The merit order is a ranking method for electricity generation based on the SRMC of each generation 
asset.  
99  Production units with SRMC below the marginal unit’s SRMC, which are therefore dispatched to 
meet demand, ar e called “infra -marginal” units.  
100  Infra -marginal production units have been historically referred to as “baseload” capacity.  

 
 
19 (73) In electricity markets, the withholding (either physically or economically)101 of 
electricity can shift the merit order curve to the left and trigger a price increase if 
the newly marginal power plant has higher SRMC than the plant that was marginal 
prior to the withholdin g. 
(74) In previous electricity cases, the Commission has typically considered whether the 
combination of flexible (in this case gas -fired) and non -flexible “baseload” (e.g. 
nuclear or renewables) electricity production assets was prone to give rise to 
horizont al non -coordinated effects in the market for generation and wholesale 
supply of electricity.102 In particular, the Commission assessed whether the 
concentration in question was likely to give the combined entity the ability and 
incentive to physically or eco nomically withhold flexible generation capacity in 
order to increase the market price of electricity applicable to all production units, 
thus including baseload production.  
(75) The premise of such a theory of harm is that a n increase in  flexible generation  
capacity , i.e. generation assets that can be ramped up or down on demand,  may 
give the combined entity additional “ opportunities to withdraw flexible capacity ”, 
while a sufficiently large baseload production , i.e. those generation assets that 
remain in opera tion to address demand, may enable it to benefit from the resulting 
higher price with its infra -marginal production units.103 
5.2.2.  Market shares  
(76) Whereas market shares provide useful first indications of the market structure and 
of the competitive importance of the parties to a transaction and their competitors, 
the Commission notes at the outset that in the market for generation and wholesale 
supply of electricity, where generators and wholesalers offer electricity on a 
quarter -hourly basis, market shares  are of  limited informative value , especially 
since they are based on an annual average. The Commission has nevertheless taken 
the Parties’ market share estimates into account for its overall assessment of the 
Transaction.  
(77) Based on historical generation data, the  Parties’ combined market share in the 
Dutch market for generation and wholesale supply of electricity overall amounts to 
[20-30]% in 2021 , with [10-20]% for RWE and [0-5]% for the Target  (and a 
combined share of around [20-30]% in previous years), as show n in Table 1 below. 
The market for the generation and wholesale supply of electricity in the 
Netherlands  is therefore horizontally affected by the Tra nsaction.   
                                                 
101  Physical withholding entails a reduction in generation output offered in the market, whereas 
economic withholding entails an  increase in unit bid prices while keeping output constant. The 
outcome is essentially the same, namely that less production is available at the pre -merger 
competitive price level. Thus, in a situation where generators bid supply functions, i.e. entire sup ply 
curves with different prices for different quantities to account for the uncertainty of demand at the 
time of bidding, physical and economic withholding converge. Hence, the remainder of this Decision 
refers to withholding in general as encompassing bo th types of strategies . 
102  See cases M.8871 – RWE / E.ON ASSETS ; M.8660 – FORTUM / UNIPER ; M.5224 – EDF / 
BRITISH ENERGY ; M.3268 – SYDKRAFT / GRANINGE .  
103  See cases M.8871 – RWE / E.ON ASSETS , paragraphs 49 et seq.; M.8660 – FORTUM / UNIPER , 
paragraph  173; M.5224 – EDF / BRITISH ENERGY , paragraph 25; M.3268 – SYDKRAFT / 
GRANINGE , paragraph  37. 



 
 
23 particular in light of the foreseen phase -out of coal -fired power plants by 2030 . 
That phase -out will primarily  impact RWE and Uniper  who together account for 
more than [80-90]% of the  coal-fired generation capacity in the Netherlands 
today,111 while the continuing increase in renewable capacity is expected to benefit 
RWE less than its main competitors .112 In addition, the Notifying Party analysed 
the residual supply index (‘RSI’ ), which qu antifies whether an electricity provider 
is pivotal, i.e. indispensable to meet demand. According to its RSI analysis, RWE 
would be pivotal in less than […]% of hours even under the most conservative  
import  scenario  (assuming a 50% available import capacit y), and pivotal in less 
than […]% of the hours in any of the scenarios considered as more realistic by the 
Notifying Party .113 
(84) With respect to it lacking the ability and incentive to engag e in a hypothetical 
withholding strategy, the Notifying Party contends , first,  that it would have no 
ability to withhold significant production capacity due to the low market 
concentration level, its limited market share and its lack of pivotality in the market. 
In addition, the Dutch generation and wholesale supply market is highly 
interconnected and is part of the flow -based market coupling of day -ahead and 
intra-day trading markets .114 This would trigger an automatic increase of imports 
from neighbouring countries in the event of a short -term price increase and, hence, 
thwart any attempt to withhold dome stic capacity.  
(85) Second, the Notifying Party submits that it would lack any incentive  to engage in a 
hypothetical withholding strategy because the  Target is an efficient , mid-merit 
CCGT power plant . The withholding of this plant  would lead to a significant loss in 
margins  from foregone income that the plant would have earned absent the 
withholding , in particular during hours  of scarce supply which are the times when  
RWE could presumably influence the price . Such loss in margins  would make 
withholding particu larly costly.  RWE would also have only a limited number of 
generation assets that would typically remain infra -marginal. Therefore, RWE 
would not have  sufficient baseload capacity to benefit from higher prices resulting 
from such a capacity withdrawal .  
(86) The Notifying Party further argues that , in any event, the  simple SRMC -based 
merit -order approach described in the previous paragraph  overstates incentives to 
withhold, for the following reasons .115  
(87) First , the market is characterised by uncertainty and mark et players cannot with 
certainty know when and how much capacity to withdraw in order to maximize 
their profits (a “wrong” amount of withdrawal at the “wrong” time might lead to 
losses) .  
                                                 
111  Form CO, paragraph 227 and Table 44.  
112  Form CO, paragraph 227 and Table 45.  
113  Form CO, paragraphs 228 et seq. and Annex 7 (Report prepared by Frontier Economics).  
114  The “flow -based” approach describes how a change in the  net position (import or export) of each 
bidding zone changes the power flow at each critical branch. The Netherlands is part of European 
coupling of day -ahead and intraday trading markets which  creates a cross -zonal market for short -term 
trading of electr icity (Form CO, paragraph 292).  
115  Form CO, paragraphs 317 et seq. and 368 et seq .  
 
 
24 (88) Second , the merit order curve is smoother  (i.e. with less pronounced  increases in 
SRMC from one production unit to the next along the curve ) in reality than can be 
modelled in theory . As a  result , any given  capacity withdrawal might lead to 
significant gains in a model framework (because of significantly higher SRMC for 
the next generation asset to the right in the theoretical merit order), while in reality  
differences in SRMC between subsequent generation assets are likely to be smaller.  
(89) Third , due to the interconnection with neighbouring bidding zones, demand and 
supply react more elastically  to price changes than a merit order model for a single 
country would suggest .  
(90) Fourth,  in reality plants might have longer cycles with fewer starts and minimum 
up and down times  compared to the basis of a profit maximising strategy th at a 
simple merit order approach might predict with a high number of starts for a 
plant ,116 which can make withdrawal less attractive in practice . 
(91) Fifth,  existing forward trading117 and non -spot market sales positions may 
significantly affect and reduce (short -term) incentives, in particular in rising 
markets when the buy -back price118 is significantly above the settlement119 of 
forward sales120.  
(92) Sixth , the Regulation on  wholesale energy market integrity and transparency 
(REMIT )121 prohibits RWE from manipulating the market and withholding an 
important capacity , which  would be easily detectable  and subject to significant 
fines.122 
(93) Finally, the Notifying Party submitted a forward -looking incentive analysis (the 
‘Incentives analysis ’) and considers  that the results of this analysis demonstrate that 
the Transaction does not give rise to competition concerns, because (i)  the 
Transaction leads only to a moderate  number of  hours in which a hypothetical 
withholding strategy would be profitable  (up to […] hours in 2025 , out of a 
maximum of 8,760 hours in a year ), which by itself does not raise competition 
concerns, (ii)  the base price increase (reflecting a potential harm to consumers) 
from the additional incentives to withhold capacity due to the Transact ion is 
limited and reaches only up to EUR  […]/MWh (or […]% of the base price before 
withholding), and (iii)  the increase in profits for RWE from withholding capacity is 
limited (less than EUR  […] million per year in 2025, i.e. less than […]% of total 
                                                 
116  The start of a power plant causes additional variable costs (e.g. energy cost for start -up and increased 
wear and tear). Start -up costs depend on the operating state of the power plant, i.e. whether it makes a 
cold, warm or hot start and the duration of operation until the next ramp -down. Revision cycles, 
which are very costly for CCGTs, are also triggered by the number of full starts/ stops . 
117  Forward sales are a form of  financial trading in electricity derivatives that take place more than one 
day ahead of the physical delivery of the traded electricity. See also fn. 9 above.  
118  I.e. the price RWE would have to pay in order to buy back the amount of electricity sold in advance.  
119  I.e. the price at which RWE sold the relevant electricity in advance.  
120  This is because where the wholesaler has sold a given genera tion capacity in advance, he would have 
to buy back the withheld generation that he is no longer producing (and, hence, cannot use to honour 
the forward trade) at a higher wholesale (spot) price, but cannot raise the settlement price in the 
forward deal.  
121 Regulation (EU) No 1227/2011.  
122  Form CO, paragraphs 320 et seq.  
 
 
25 gross  profits before withholding), which needs to be weighed against a high 
probability of detection when withholding two large CCGT power plant s.  
5.2.4.  The Commission’s assessment  
(94) The Transaction would add to RWE’s portfolio of electricity generation assets in 
the Netherlands one of the largest modern CCGT power plants in the country. 
CCGT power plants are flexible generation assets and [information concerning 
CCGT power plants] .123 This leads to the potential concern that RWE would have 
post-Transaction the ability a nd incentives to withdraw flexible capacity in order to 
increase the market price that it receives on its remaining infra -marginal production 
units.  
(95) It is true that RWE’s market share for generation and wholesale supply of 
electricity post-Transaction would remain limited, based on both historical 
generation data ( [20-30]% in 2021, and less in previous years) as well as forward -
looking capacity data ( [10-20]% in 2022, and less in subsequent years).  
(96) However, due to the functioning of the electricity gen eration and wholesale supply 
market, market shares do not necessarily provide an indication of a company’s 
ability to engage in a withholding strategy and to impact prices. E ven companies 
with a moderate  market share may be able to influence the wholesale price under 
some circumstances. In line with Commission precedents in the electricity sector 
set out in paragraph (74) above, the Commission has the refore assessed whether, 
despite the Parties’ limited market share, the Transaction could affect RWE’s 
ability and incentives to influence market prices in a profitable manner by 
withholding part of its flexible production.  
5.2.4.1.  Analysis of RWE’s ability to wit hhold post -Transaction  
(97) As set out in paragraphs (71) et seq. above, w ithholding strategies usually require 
the combination of flexible generation as sets (the withheld assets) and “baseload” 
generation assets (the benefitting assets, which would remain operational and 
therefore would benefit from the resulting higher price).124 A starting point for the 
Commission’s assessment is therefore to look at the entire portfolio of power 
generation assets in the relevant market controlled (also pro rata ) by the Notifying 
Party.  
(98) RWE’s pre-Transaction generation portfolio in the Netherlands consists of 
562 MW installed capacity in nuclear, onshore wind, solar and hydro power plants 
and about 4,180 MW installed capacity in gas -fired and hard coal/biomass co -firing 
plants.125 Of these, approximately  3,400 MW installed capacity relates to 
“baseload” generation as sets (either due to low SRMC or must -run obligations).126 
At least 1,300 MW installed capacity constitute s flexible generation assets that 
could theoretically be withheld. In light of this, the Commission considers that 
RWE might at least theoretically be ab le to engage in a withholding strategy 
already pre -Transaction. RWE’s theoretical ability to withhold already pre -
                                                 
123  Form CO, Annex 05w, RWE internal document.  
124  See, e.g., case M.8871 – RWE / E.ON ASSETS , paragraphs 49 et seq.  
125  Form CO, Table 44.  
126  Form CO, paragraph 349 and Table 65.  
 
 
26 Transaction was confirmed by the large majority of respondents to the market 
investigation , many of which noted however that they have not exp erienced any 
strategic withholding by RWE to date.127  
(99) The addition  of the Target’s 1.4 GW installed capacity , which  also constitute s 
flexible generation , could potentially increase  RWE ’s ability to withhold post -
Transaction. RWE’s post -Transaction portfolio  may thus be suited for withholding 
strategies.  
(100)  The Commission has analysed the RSI analysis provided by the Notifying Party. 
Energy regulators and competition agencies typically use RSI analyses as a 
preliminary indication of market power in electricity wholesale markets. The 
Commission considers that while RSI is a useful screening tool to monitor the 
functioning of the electricity wholesale market and to identify possible problematic 
areas, it suffers from a number of limitations that should be taken in to account 
when reviewing the impact of mergers. For example, a company may have the 
ability (e.g. by withholding capacity) to influence the wholesale price even when it 
is not pivotal. Likewise, a company may have limited incentives to exercise market 
power even when it is pivotal, if the residual demand that cannot be met by 
competitors is small. For these reasons, the Commission considers that the RSI 
analysis submitted by the Notifying Party is alone insufficient to dispel concerns on 
the generation mar ket, and that further  analysis of RWE’s ability and incentives to 
withhold is necessary in this case.  
(101)  To assess RWE’s ability to withhold capacity, the Commission investigated the 
marginality of the flexible generation plants Clauscentrale C (operated  by RWE 
pre-Transaction ) and Magnum  (operated  by the Target pre -Transaction ) that were 
potentially well suited for withholding strategies , due to their flexibility ( i.e. ability 
to ramp -up or down the whole plant within an hour), and [information about 
costs].128. The marginality analysis consists in counting the hours during which a 
plant is marginal in the merit order curve, i.e. when the plant is producing and its 
SRMC are very close to the market price. The more often certain plants are 
marginal, the less cost ly it is to pursue a strategy of withholding these plants , as the 
margin on these plants is limited .129 In 2019, Magnum was producing and marginal 
at […]% (i.e. its SRMC were […]% or more  of the day -ahead market price) for 
[…]% of hours in 2019, […]% of hours in 2020, and […]% of hours in 2021 . 
Clauscentrale C was marginal at […]% for  […][…] % of hours in 2019, […]% in 
2020 and […]% in 2021. These results show  a non-insignificant number of hours 
over 2019 -2021 where Clauscentrale C and Magnum could ha ve been withheld at a 
contained cost , as the lost margin on these plants would  have been at most […]% 
of the day-ahead market price . 
                                                 
127  See responses to questions D.A.2 and D.A.3 of eRFI.  
128  When plants with high SRMC are marginal, RWE’s low SRMC plants are likely to be producing, and 
hence the price increase triggered by withholding a high SRMC plant can generate additional profits 
on th e “baseload” production units with lower SRMC. The latter are therefore less well suited for a 
withholding strategy . 
129  The overall spot market price is defined based on the SRMC of the “marginal” unit (see 
paragraph  (71) above). The spot market price therefore allows a “marginal” unit only to cover its 
SRMC, whereas infra -marginal units gain a higher profit the larger the difference is between their  
own SRMC and the spot market price.  
 
 
27 (102)  As noted at paragraph (98) above, i n respons e to the market investigation, the large 
majority of respondents who expressed a view consider ed it possible, at least in 
theory, that RWE already pre -Transaction would be ab le to withhold flexible plants 
in the Netherlands to increase the wholesale power price in order to earn higher 
margins on its remaining operating Dutch power plants .130 Respondents noted for 
instance that “ with a fossil/biomass power plant capacity of almost 4.4 GW (Amer 
power plant 600 MW, Claus C 1275 MW, Eemshaven coal  power plant 1560  MW, 
Moerdijk Gas power plant 700 MW and Swentibold cogen Geleen 230 MW), RWE 
can theoretically already influence the market price. 4.4 GW is almost 20% of the 
peak con sumption of all consumers in the Netherlands together ”131 and that for 
RWE it would be  “possible to strategically withhold capacity to trigger different 
marginal units with higher marginal prices. The main competition in the infra -
marginal sphere (especially  the level before marginal) is interconnection and/or 
less efficient CCGTs .”132 The majority of respondents who expressed a view further 
consider that RWE’s ability to withhold would increase post -Transaction.133  
(103)  On the other hand , the Dutch electricity marke t regulator, the ACM, voiced no 
concerns that RWE would structurally withhold capacity to increase the wholesale 
market price , in particular due to the share of RWE’s conventional generation 
portfolio in relation to its low installed renewables  capacity, a s apparent also from 
Table 5 above . As set out at paragraph (72) above, conventional generation assets 
can be in fra-marginal , marginal  or out -of-merit depending on the load of demand at 
a given point in time. Therefore , a limited portfolio of renewables capacity would 
limit RWE’s ability to recoup losses from the capacity withheld with higher prices 
on baseload prod uction .134 
(104)  Against this background, the Commission has noted in previous cases135 that an 
ability to withhold output does not necessarily imply an ability to raise prices (in 
other words, withholding output does not necessarily translate into a general price 
increase). Indeed, depending on the elasticity of supply in the market, withhe ld 
units may be absorbed by countervailing production from other suppliers, including 
imports, thus preventing prices from increasing in the first place. Absent any price 
increase from withholding production, a withholding strategy cannot be profitably 
implemented. The Commission has therefore assessed the existence  and likelihood 
of price increases and, hence, incentives of the merged entity to withhold.  
5.2.4.2.  Analysis of RWE’s incentives to withhold post -Transaction  
(105)  The market investigation provided feedback o n RWE’s theoretical incentives to 
engage in a withholding strategy in the future with the aim to increase wholesale 
market prices . The majority of respondents consider it possible that RWE would 
have such incentives, noting for instance that “ the phase -out of conventional 
capacity always makes the ownership of gas -fired power plants more interesting on 
the market and increases the moments that they are the price setting assets ”, and 
that “ [w]ith a higher share of renewables in the future more power plants w ill be 
                                                 
130  See responses to question D.A.4 of eRFI.  
131  See responses to question D.A.3 of eRFI.  
132  See responses to question D.A.10 of eRFI.  
133  See responses to question D.A.4 of eRFI.  
134  Email from ACM to DG COMP on 09/11/20 22.  
135  See case M.8660 – FORTUM / UNIPER , paragraphs 181 -182. 
 
 
28 priced out of the market for certain periods […] There will therefore be a need for 
the power plant owners in general to raise the prices in the remaining periods in 
order to make their power plants economical ly profitable ”.136 Other respondents 
point ed to theoretically different incentives between the Target’s current owner, 
Vattenfall, and RWE, due to the fact that RWE has no activities in the retail 
markets and, hence, would not be constrained by considerations of retail price 
impacts that a withhol ding on the wholesale level might have.137 
(106)  However, the results of the market investigation also confirmed a number of 
elements put forward by the Notifying Party which are generally likely to reduce 
RWE’s incentives to withhold. In this respect, all respond ents who expressed a 
view considered that uncertainty in the market prevents generators from knowing 
when and how much to profitably withdraw, noting for instance that 
“[u]ncertainties in the market make it very difficult to estimate future clean -dark 
and clean -spark spreads138 [which] makes it difficult to estimate future operating 
hours ”.139 A large majority of respondents who expressed a view also considered 
that existing (long -term) forward and futures trading reduce (short -term) incentives 
to withhold elec tricity due to possibly unfavourable spot market prices for its buy 
back, i.e. the price RWE would have to pay in order to buy back the amount of 
electricity sold in advance .140 All respondents who expressed a view further 
indicated that the existing day -ahead and intra -day market coupling between the 
Netherlands and neighbouring bidding zones decreases RWE’s incentives to carry 
out a successful withholding strategy, as “ market power across the integrated 
markets is lower and the uncertainty on the position i n the merit order is 
increased ”.141 Other respondents pointed to the “ regulatory exposure due to the 
size of the Magnum power plant ” that a withholding of the Target’s capacity could 
entail.142  
(107)  In order to determine the likelihood  of a withholding strategy to occur post-
Transaction , the Commission also sought to quantify potential price reactions due 
to withholding and the resulting incentives for RWE. For such a quantitative 
assessment , it is necessary to estimate whether RWE would ha ve a large enough  
incentive to withhold capacity  on the day -ahead market . This would only be the 
case if  the withholding strategy  would generate large enough price increases that 
would cover for both the loss of profit inherent to the reduction of volumes sold by 
the withheld plant and for the risks that are associated with withholding, such as the 
risk of the withholding being discovered by the regulator , as withholding is 
prohibited under the REMIT regulation  and can lead to sanctions ,143 or the risk of 
non-profitable withholding in certain hours.  
                                                 
136  See responses to question D.A.8 of eRFI.  
137  See responses to question D.A.9 of eRFI.  
138  Clean -dark and clean -spark spreads designate the difference between the input fuel costs and the 
wholesale power price. For electric power generation fuelled by natural gas, this difference is called 
the spark spread; for electric power generation fuelled by coal, the difference is called the dark 
spread.  
139  See responses to question D.A.11 and D.A.12 of eRFI.  
140  See responses to question D.A.13 of eRFI.  
141  See responses to questions D.A.15 and D.A.16 of eRFI.  
142  See responses to questions D.A.9 of eRFI.  
143  Articles 4 and 5 of REMIT, and Article 77(i)(1)(b) Dutch Electricity Act 1998.  
 
 
29 (108)  The Notifying Party conducted  an Incentive s analysis describing what would be the 
most plausible withholding strategies, and in which incentives they would result. 
Among all RWE plants post -Transaction , the Notifying Party considered only 
Magnum and Clauscentrale C  suitable for an opportunistic withholding strategy. 
The report did not consider it plausible to withhold other plants, because of either 
must-run clauses  (some RWE co-fired coal/biomass plants are also used for 
heating) , low controllability  (contrary to Magnum and Clauscentrale C , which can 
be fully ramped -up or down within an hour) , or low SRMC that would result in 
important lost margins. The analysis presents  two post -Transaction withholding 
scenarios: withholding one plant (Scenario A), i.e. Magnum or Clauscentrale C, 
depending on which plant is best placed for every hour, or  withholding both  
Magnum and Clauscentrale C jointly  (Scenario B) . These post -Transaction 
simulations were then compared  to a pre -merger withholding scenario in which 
only Clauscentrale C was withheld.  The Notifying Party consider s the withholding 
strategy described in Scenario B as being extreme and easily detectable since RWE 
would withhold up to […]% of its total Dutch gas -fired capacity in certain hours.  
(109)  The Commission agree s with the Notifying Party that Magnum and Clauscentrale 
C are the plants that are the most relevant to implement a withholding strategy . 
This is not only for the reasons submit ted by the Notifying Party  as set out  above , 
but also because of the high capacity of these plants and their high current level of 
marginality, which is expected to increase in the near future. Other RWE plants do 
not qualify for a withholding strategy, ei ther because of their must -run clauses, low 
controllability, or low SRMC  However, the Commission  does not agree that the 
withholding S cenario B is extreme as the market investigation revealed that it was 
very difficult to detect a withholding behaviour. Mo reover, if one were to assume 
that post -Transaction , in order not to be detected, RWE could withhold no more 
than a certain share of its gas capacity, this would also apply pre -Transaction , and 
therefore  the counterfactual scenario should be modified accor dingly , to account 
for less capacity withheld pre -Transaction .144 Considering the counterfactual 
scenario chosen by the Notifying Party in its model, the Commission  consider s it 
prima facie  plausible that RWE could apply the withholding strategy described 
under Scenario B , and therefore considers the assessment of both Scenario A and 
Scenario B as relevant . 
(110)  The simulation consisted in forward -looking market modelling for future years 
2023, 2025 and 2030. To determine the hourly wholesale prices for these ye ars 
under the non -withholding scenario and under the pre - and post -merger 
withholding scenarios , the Notifying Party used the European power market model 
‘Plexos’145, with assumptions on development of capacities, demand and 
commodity prices. Then, RWE used the dispatch model ‘ROM’146 to simulate the 
                                                 
144  Everything else equal, reducing the capacities that could be withheld pre -Transaction increases the 
Transaction -specific effect of withholding on prices.  
145  Plexos is a com mercial software developed by Energy Exemplar. It is a power market model which 
uses various inputs to match demand and supply at the lowest costs, i.e. the lowest power price. 
Plexos produces hourly price curves. Plexos is widely used in the energy sector  and is considered 
industry -standard.  
146  The Real Option Model (‘ROM’) is an optimisation tool developed in -house by RWE, which 
optimises the power station dispatch against given price curves (from Plexos) based on the detailed 
technical parameters of the respective power station. ROM produces generation volumes, margins, 
and running hours as main output.  
 
 
30 dispatch of generation across all power stations under the price levels obtained as 
an output of the Plexos model . The ROM model  minimis es costs under commodity 
price assumptions. From the market price and plant ge neration outputs obtained 
respectively from Plexos and ROM, RWE was then able to compute the expected 
hourly profit (or loss) resulting from withholding under the different scenarios, and 
to calculate the merger -specific increment.  The Commission acknowled ges that  the 
Plexos and ROM models were not built for the purpose s of this investigation, but 
are used by RWE in its regular course of business.  Although the Commission did 
not review the algorithms underlying the models, the Commission  did verify  that 
the market predictions  obtained as an output of these models ( and in particular 
generation shares and  expected volumes) were consistent with market expectations 
for the future years  considered . 
(111)  The RWE simulation showed a substantial increase in the number of  hours where 
withholding would be profitable , ranging between […] hours in 2030 under 
Scenario A ( […]% of yearly hours), and […] hours in 2025 under Scenario B 
([…]% of yearly hours). However, the overall merger -specific impact of 
withholding when profitab le for RWE would be limited , with an overall price 
effect of at most (under scenario B) […]% in 2023, […]% in 2025 and […]% in 
2030. Looking more specifically at peak hours147 during weekdays, the effect 
would always remain below […]%. The Notifying Party ’s Incentive analysis  also 
estimated the impact on prices in Germany where RWE would also be able to 
benefit from the withholding  in the Netherlands. When prices are coupled between 
Germany and the Netherlands , an increase in prices in the Netherlands will al so 
impact prices in  Germany, where RWE is an important producer.  In Germany , the 
impact would be even more limited with a merger -specific price increase of […]% 
on average.  
(112)  Although relatively small price increases in electricity markets can typically  be 
considered problematic148, a price increase of [less than  1]% in the near future  
(2023) , and [less than 1] % in 8 years’ time  (2030)  appear s extremely limited149, 
especially with regards to the fact that uncertainty  on the supply and demand levels  
is not mo delled in to these results . Uncertainty implies that RWE may not have 
perfect foresight on when and how much capacity to withdraw in order to 
maximise its profits . Withholding capacity incurs lost revenues from the plant that 
is withheld, and the strategy c an only be profitable if it generates more additional 
revenues from the other plants that continue producing , than the revenues  lost on 
the withheld plant.  Therefore,  withholding when not optimal, or not withholding 
the optimal quantities , might lead to lo sses. The higher risks involved from 
withholding under uncertainty implies lower incentives to withhold.  
(113)  In light of the energy crisis, the Commission has  recently  proposed guidance to 
Member States as well as  adopted measures to alleviate the impact of increased gas 
                                                 
147  6:00 to 10:00 and 16:00 to 20:00.  
148  See case M.5224 – EDF / BRITISH ENERGY , paragraphs 31 -33. 
149  The Commission also asked EPEX to calculate what woul d have been the market price with the 
aforementioned withholding scenarios using past data from the Dutch day -ahead market on merit 
order curve and demand for years 2020 and 2021. However, the price reaction calculated by EPEX 
did not factor in the potenti al change in imports, which are likely to be substantial on the Dutch day -
ahead market. Therefore, the Commission did not rely on this data to analyse RWE incentives.  
 
 
31 prices on electricity prices.150 The application of a temporary cap on market 
revenues for certain technologies (wind, nuclear, etc.) directly affects incentives to 
withhold as it limits the potentia l gain from a withholding strategy for these 
technologies . In other words,  the temporary price cap  limits the possible price 
increase following withholding , which therefore might not apply to all of RWE’s 
production units. Moreover, the ongoing reform to d ecouple electricity from gas 
prices may potentially reduce the Parties’ ability and incentive to withhold 
stemming from flexible gas plants .151 While these regulatory interventions or 
potential changes to market design are only temporary, they may further re duce the 
already low incentives to withhold computed under the Notifying Party ’s model.  
(114)  The limited price impact of the withholding strategy in question was also 
confirmed by the market investigation. Overall, the large majority of respondents 
considered t hat the Transaction would likely have no significant impact on their 
company or on the market for the generation and wholesale supply of electricity in 
the Netherlands.152 
(115)  On the basis of the above, the Commission considers that while RWE may have the 
ability to engage in a withholding strategy, the incentives for RWE to withhold 
would  be limited , and it is even uncertain whether such a withholding strategy 
could be profitably implemented post -Transac tion considering market uncertainty . 
Even in case such a strategy could be viably implemented, it would result in a very 
limited impact  on prices . Therefore, the Commission considers that the Transaction 
does not raise serious doubts as to its compatibilit y with the internal market or the 
functioning of the EEA Agreement with respect to the market for  the generation 
and wholesale supply of electricity in the Netherlands.  
5.3. Balancing and ancillary services  
5.3.1.  Market shares  
(116)  The Parties’ combined market shares in regulation of aFRR at national level in the 
Netherlands were low in 2021 ( [10-20]% combined and [5-10]% upwards, [10-
20]% downwards) but higher in 2019 and 2020 ( [20-30]% and [20-30]% combined 
and [10-20]% and [20-30]% upwards and [20-30]% and [20-30]% dow nwards), as 
can be seen in Table 6 and Table 7 below.   
                                                 
150  Annex 2 to REPowerEU communication on the application of infra -marginal profit fiscal measures 
(https://eur -lex.europa.eu/legal -content/EN/TXT/HTML/?uri=CELEX:52022DC0108) and Council 
regulation on an emergency intervention to address high energy prices (st12999 -en22.pdf 
(europa.eu)).  
151  See State of the Union Address by Commission Preside nt von der Leyen, available at 
https://ec.europa.eu/commission/presscorner/detail/ov/SPEECH_22_5493, in which the Commission 
President presented the objective of decoupling gas and electricity prices.  
152  See responses to questions E.1 and E.3 of eRFI.  

 
 
33 5.3.2.  The Notifying Party’s view  
(118)  The Notifying Party argues that the Parties’ combined shares in the narrowest 
possible market of aFRR are negligible  in 2021 at [10-20]% and do not give rise to 
an affected market. Market shares would be even lower on a broader balancing and 
ancillary services market. For that reason, no competition concerns can arise, even 
if considering separate shares for upwards and downwards regulation  of aFRR.156  
(119)  Furthermore, only the 2021 market shares are a meaningful indicator of the Parties’ 
current position. The reason for the fall in market share in 2021 is due to structural 
reforms  of the market, which were d esigned to f oster liquidity and competition. 
These reforms consisted of a switch from weekly to daily aFRR tenders in 
September 2020 and the procurement of separate upwards and downwards 
regulation of aFRR in January 2021. The effect of these reforms is to allow more 
players to enter the market, as it is possible for other players, including for example 
wind farms, to provide aFRR for just one side of the market.157  
(120)  The Notifying Party also argues that the presence of “free bids” from BSPs does 
not allow RW E to exploit its position and that , furthermore, there are a sufficient 
number of competitors in the market.158  
(121)  In addition, the balancing market is very unpredictable and is opaque, whereas the 
sole purchaser, TenneT, has full transparency.159 The Dutch imbalance price 
system also incentivises BRPs to optimise against imbalance, which could reduce 
the need for aFRR activations.  Higher aFRR energy prices would lead to higher 
imbalance prices and therefore increase the incentive for BRPs to reduce any 
imbalance  (before the  activation of aFRR) .160  
(122)  Future market reforms i.e. the implementation of the Platform for the International 
Coordination of Automated Frequency Restoration and Stable System Operation 
(‘PICASSO’ ) in 2024 will also increase the competitiveness of the aFRR m arket in 
the Netherlands and allow for the activation of aFRR bids from outside of the 
Netherlands.161 
(123)  Finally, the balancing and ancillary services market, and the aFRR market, are very 
small compared to the generation and wholesale supply market. The size of the 
aFRR market was 723 MW in 2021, compared to an average load of 12,145 MW in 
the generation and wholesale supply market.162 The Notifying Party also adds that 
the national regulatory authority can intervene, in case of a lack of competition.163  
5.3.3.  The Commission’s assessment  
(124)  A majority of the respondents to the market investigation indicated that RWE could 
in theory carry out the  Activation S trategy (highlighted in paragraph (117)  
                                                 
156  Form CO, paragraphs 480 -487. 
157  Form CO, paragraph 469.  
158  Form CO, paragraphs 490 -491. 
159  Form CO, paragraph 492.  
160  Form CO, paragraph 494.  
161  Form CO, paragraph 493.  
162  Form CO, paragraph 495.  
163  Form CO, paragraph 496.  
 
 
34 above ).164 In addition, the Commission notes that  several market participants 
indicate d more generally  that the Transaction could have a negative impact on the 
balancing and ancillary services market.165 However, t he Commissi on finds that 
these comments are not supported by the remainder of the findings in the market 
investigation.  
(125)  First, despite the majority considering that it was theoretically possible for RWE to 
carry out the Activation S trategy, several  respondents  questioned the likelihood of 
RWE carrying out such a strategy . One participant added that: “ this could also be a 
strategy today. Of course the impact increases post -merge r, but RWE aims for a 
diverse portfolio with a lot renewable which might be impacted negatively with 
such a strategy .”166 Other participants considered that such behaviour would be 
detectable by market participants and indeed, “ RWE would be able to bid for the 
entire volume but it would be too obvious, a more subtle approach would benefit 
them more .”167 TenneT also considered that th e Activation Strategy  was unlikely, 
noting that first, the balancing energy market allowed for free, non -procured bids 
that could disrupt the strategy and second, that RWE, as a BRP, would be exposed 
to a high imbal ance price as an effect of high balancing energy prices and so would 
not benefit from such a strategy.168 
(126)  The replies to the market investigation also confirmed a number of the Notifying 
Party’s arguments. For example, t he va st majority of respondents indica ted that the 
aFRR market was easier to enter, following the recent market reforms  introduced in 
2021 . As noted by TenneT “ we see more renewables and decentral assets being 
prequalified in order to provide aFRR .”169 However, TenneT also confirmed that at 
present, it was mainly conventional power  plants that were delivering aFRR. Even 
so, the vast majority of market participants also agreed that the presence of “free 
bids”, namely BSPs without a prior capacity contract, could now compete with 
BSPs with a capaci ty contract and would disrupt the Activation Strategy.  
(127)  The aFRR market was also widely considered to be non -transparent, further 
complicating the Activation Strategy. As noted by TenneT: “ All that is published is 
the total contracted capacity (for FCR, aFRR and mFRRda) and the average 
contracted price. For aFRR balancing energy TenneT publishes the bid -prices at 
several points of the MOL in each direction (first and last bids and at 100, 300 and 
600 MW); both prior and after Balancing energy gate closure  time.”170 The ACM 
also agreed the market was “ hard to predict ”, that volumes were low and that 
consequently there would be no impact arising from the Transaction as regards 
aFRR.171 
(128)  TenneT, the sol e buyer  of aFRR services, noted that it tended to contract aFR R 
services from multiple operators  rather than just one,172 and that the Transaction 
                                                 
164  See responses to question D.B.5 of eRFI.  
165  Responses to questions E.1 and E.2 of eRFI.  
166  Response to question D.B.6 of eRFI.  
167  Response to question D.B.6 of eRFI.  
168  Response to question D.B.3 of Request for Information 1 to TenneT.  
169  Response to question D.B.1 of Request for Information 1 to TenneT.  
170  Response to question D.B.5 of Request for Information 1 to TenneT.  
171  Email from ACM to DG COMP on 09/11/2022.  
172  Minutes of a conference call with TenneT on 11 July 2022.  
 
 
35 would have a limited impact due to the fact that it was “ unlikely that RWE would 
be the pivotal party in the balancing market .”173  
(129)  Furthermore, the Parties currently have a v ery limited position in the provision of 
aFRR services and the Commission has seen no indication that this should increase 
post-Transaction.  As set out in  Table 6, competitors such as Vattenfall and Engie 
have historically provided more aFRR regulation than the Parties and even 
competitors with a  historically  lower market share in aFRR  such as Eneco an d 
PZEM had a more significant market position  in aFRR in 2021 than either of the 
Parties.  
(130)  Finally, the introduction of PICASSO in 2024 is expected by market participants to 
increase competition although only to a limited degree, as additional volumes 
woul d only be supplied in the future where there was available border capacity.174 
(131)  The Commission considers that the assessment below ** applies to both aFRR 
(overall) and upwards and downwards regulation of aFRR (separately).  
(132)  On the basis of the above, the Commission does not consider it likely that RWE 
could implement the Activation Strategy. The Commission therefore  considers that 
the Transaction does not raise serious doubts as to its compatibility with the 
internal market or the functioning of the EEA Ag reement with respect to the 
market for the provision of aFRR, nor in relation to the markets for upwards and 
downwards regulation of aFRR  in the Netherlands . 
5.4. Congestion management  
(133)  The relevant congestion management services in the Netherlands are redispatc hing 
and capacity restriction agreement s. In this decision the market shares are 
presented on the narrowest plausible markets, i.e. separately for each of 
redispatching and capacity restriction agreements . 
5.4.1.  Market shares  
(134)  For redispatch ing, as shown in Table 8 below  based on gigawatt hours (GWh) , the 
combined market shares of the Parties ranged between [20-30]% and [30-40]% for 
the period 2019 – 2021 , with their individual shares ranging between [0-5]% – [10-
20]% for RWE and [10-20]% – [30-40]% for the Target .  
                                                 
173  Response t o question E.1 of Request for Information 1 to TenneT.  
174  Responses to question D.B.10 and D.B.11 of eRFI.  
 
*  Should read: ‘above’.  

 
 
37 Vattenfall (current owner of Magnum) and RWE (with its coal -fired power 
Eemshaven plant).  Post-Transaction, the merged entity would be one of only two 
such generators . Given that RWE also has generation plants in other parts of the 
Netherlands, t he market participants  who raised concerns therefore allege that 
RWE could  overproduce in the northern part of the Netherlands to create 
congestion , thereby trigger ing redispatch requests from TenneT that RWE could 
benefit from  for both negative redispatch (curtailment) in the north and positive 
redispatch (ramping up) in the south.   
5.4.2.  The Notifying Party’s view  
(140)  The Notifying Party submits that competition concerns in relation to congestion 
management services, and redispatching in particular,  can be excluded for the 
following reasons.  
(141)  First , TenneT has significant countervailing buyer power. TenneT, the only 
purchaser of congestion management se rvices in the Netherlands, is a large and 
sophisticated purchaser with full transparency of all bids submitted by the market 
participants.178 TenneT is financially  incentivised to keep the costs for 
redispatching services as low as possible  by the ACM’s “Met hod Decision” 
(Methodebesluit ).179 
(142)  Second , the practice of creating congestion (to benefit from redispatch payments) 
would be detectable by TenneT. In addition to TenneT having full knowledge of all 
offers for redispatching services, it will also have simula ted the future demand to 
evaluate grid reinforcements. A sudden increase i n the redispatch demand in the 
north, caused by RWE, would be immediately observable , in particular if it occurs 
simultaneously with increased redispatch bids from RWE.  If TenneT fin ds that 
RWE is engaging in  such conduct deliberately, it can withdraw RWE’s recognition 
as BRP. 180 
(143)  Third , the profitability from such a strategy is unclear given the lack of 
transparency. RWE has no certainty whether it would be called by TenneT to 
provide redispatch services and if so how much. There are several gas -fired power 
plants in the region , including Eemscentrale and Delesto,  that would be in 
competition with RWE  and all these plants have an obligation to supply 
redispatching services as the ir capacity exceeds 60 MW.  Given the significant 
uncertainty  in relation to when congestion could be created and about the level of 
competing bids, RWE would bear the significant risk of incurring negative margins  
                                                 
178  Form CO, paragraphs 550 -552.  
179  Form CO, paragraphs 553 – 555. The “Meth od Decision” states that “ The ACM considers it useful to 
give TenneT a financial incentive for the costs of congestion management. A financial incentive 
ensures that TenneT tries to solve transmission constraints as efficiently (i.e., as cheaply) as possib le. 
After all, TenneT does not have to use redispatch services, but can use other measures, such as 
cancelling scheduled unavailability. TenneT can also deal with structural congestion on the grid by 
increasing the capacity of the grid. It is therefore imp ortant that TenneT feels it has an incentive to 
minimize the use of redispatch services and to carry out redispatch as cheaply as possible”.  Pursuant 
to the Dutch Electricity Act, the ACM determines the tariffs for carrying out the legal tasks by 
TenneT (A rticle 41c of the Electricity Act). The tariffs are based, amongst other things, on the 
Method Decision, which is determined by the ACM. The current regulation period covers the years 
2022 -2026.  
180  Form CO, paragraph 556. See Article 10.35(1)(d) Dutch Elec tricity Grid Code.  
 
 
38 if RWE’s redispatch bid is not accepted by T enneT and RWE has to generate  in 
unprofitable hours/days with negative margins (which, under this hypothetical 
strategy, RWE would only have generated with the aim of triggering a curtailment 
request) .181 
(144)  Fourth , RWE has limited ability to create (additional ) congestion.  The two RWE 
conventional power plants in the n orth, Eemshaven A and B, [information about 
RWE plants’ utilisation rates] when the Target  is activated for negative redispatch. 
When producing at maximum capacity prior to the implementation of t he 
abovementioned hypothetical strategy, [information about RWE’s production 
capacity]  with the purpose of triggering requests for additional curtailment.182 
(145)  In addition, the upgrade of the Diemen -Lelystad tr ansmission line connecting the 
north and s outh of the Netherlands, discussed at paragraph (137)  above, should, by 
itself, reduce the likelihood of congestion in the future and therefore reduce future 
redispatch requirements. As such, it is unclear whether, after those grid 
reinforcement s, the two Eemshaven plants would be even large enough to produce 
congestion on the increased transport capacity.183 
(146)  Fifth , sufficiently credible competitors will continue to exert pressure on the 
merged entity. Those who are obliged to submit bids (as outli ned at paragraph  (51) 
above) includes the five largest generators (Engie, Eneco, RWE, Uniper and 
Vattenfall) and several of the medium -sized and sm aller generators (e.g. EPZ Akzo 
Nobel, Dow, Onyx Power, Air Liquide, Shell and EDF ). Additionally, parties with 
connection capacities below 60 MW can submit bids on a voluntary basis (and/or 
upon the request of TenneT ). As a result, TenneT has access to a number of 
credible alternatives to which it could switch easily and immediately (i.e. by simply 
selecting a bid or reaching out to suppliers).184 
(147)  Sixth , the redispatching bidding process is competitive and lacks transparency . The 
Parties and other redispatch  providers have no transparency over TenneT’s 
selection and decision process when submitting their bids and they submit their 
bids (for every quarter -hour for each available power plant) without knowing for 
what this capacity could be used. They have no in formation on the bids submitted 
by any of their competitors, the location or size of the congestion that is being 
resolved by the respective redispatch, or the leverage a specific power plant has in 
solving a specific congestion issue (which depends on whi ch gridlines can be used 
to resolve the connection and on the location of the plant in relation to the location 
of the congestion).185 
(148)  Seventh , TenneT’s increase of transport capacity will reduce the need for 
redispatching services.  To solve the transmission  bottlenecks in the Eemshaven 
area, TenneT is increasing the transport capacity between Eemshaven and Diemen 
via two main projects: (i) the construction of a new 380 kV connection between 
Eemshaven Oudeschip and Vierverlaten (to be operational by 2024); an d (ii) the 
extension of existing 380 kV connections to 2 x 2,635 megavolt -amperes ( MVA)  
                                                 
181  Form CO, paragraphs 557 -560. 
182  Form CO, paragraph 561.  
183  Form CO, paragraph 562.  
184  Form CO, paragraphs 563 -564. 
185  Form CO, paragraphs 565 -566. 
 
 
39 connections between Diemen and Lelystad, Lelys tad and Ens as well as Ens and 
Zwolle (to be operational between 2020 to 2024).  The outlined investments of 
TenneT in new and upgraded transmission infrastructure will increase the 
transmission capacity between north and south of the Netherlands and thereby 
reduce congestion on these lines. This will in turn lead to a reduction in th e demand 
for redispatch, and therefore the Parties’ activities in the redispatch market are 
expected to decrease.186 
(149)  Finally, the Notifying Party notes that redispatching volumes are very small. In 
2020, for example, the ratio of redispatch volumes as compar ed to total electricity 
generation in the Netherlands was only 0.5% and the ratio between both Parties 
(RWE + Target) redispatch volumes as compared to both Parties generation 
volumes was only […]%.187 
5.4.3.  The Commission’s assessment  
(150)  A majority of the respondent s to the market investigation consider s that RWE ’s 
ability to cause congestion would increase post -Transaction .188 
(151)  A majority also consider s that when a specific congestion event occurs, generators 
have a high level of certainty as to whether they are likely  to be called on by 
TenneT to provide redispatching services.189 One respondent commented that 
“Congestion in the Eemshaven area is well known, owning a n asset there makes it 
pretty likely that TenneT will call when this problem occurs ”. However, other 
respo ndents point to there being “ multiple solutions available to TenneT in order to 
resolve a congestion event ” (i.e. due to the re always being  two inter -related 
transactions for curtailment and ramping -up in and outside  the congested area as 
outlined in paragraph (48)) and that the “ market and the bid ladder determine who 
shall be called upon ”.190 Therefore, the Co mmission considers that , while 
genera tors may have some knowledge of the likelihood of being called on by 
TenneT to provide redispatching services , uncertainties relating to redispatching 
will always remain for generators.  
(152)  Although a majority of the respondents to the market investigation co nsidered that, 
in theory, it is likely that a generator with plants throughout the Netherlands would 
benefit overall from the behaviour outlined in paragraph (139) ,191 a majority also 
consider s it unlikely that, post -Transaction, RWE would deliberately cause 
congestion in order to trigger redispatch requirements .192 One respondent who 
considered it “ highly unlikely ” that RWE would deliberately cause congestion 
explained that “ [d]ue to the size of the assets held by RWE, we consider that any 
unexpected behaviour would be detectable ”.193  
                                                 
186  Form CO, paragraphs 568 -576. 
187  Form CO, paragraph 577.  
188  See responses to question  DC11 of the eRFI and the response to question D.C.6 of Request for 
Information 1 to TenneT.  
189  See responses to question DC3 of the eRFI.  
190  See responses to question D.C.4 of the eRFI. The “bid ladder” lists information (e.g. price and 
capacity) for all the bids for each 15 -minute period.  
191  See responses to question D.C.5 of the eRFI.  
192  See responses to question D.C.13 of the eRFI.  
193  See responses to question D.C.14 of the eRFI.  
 
 
40 (153)  Furthermore, no respondents substantiated any suggestion that there have b een 
instances where a generator in the Netherlands caused congestion in order to 
trigger redispatch requirements.194 TenneT confirmed that it has no evidence that 
such conduct has ever occurred.195 
(154)  The ACM does “ not think that RWE could create congestion in the north to benefit 
from that ” due to the “ grid configuration in the near future ” and “ the upgrade to 
the north/west connection”.196 Indeed, t he replies to the market investigation 
confirmed the Notifying Party’s argument that the recent upgrade of the Diemen -
Lelystad transmission line has reduced  congestion in the n orth and the need for 
redispatching.197 
(155)  The Commission considers that, based on the conditions prevailing prior to the 
recent upgrades (including to the Diemen -Lelysta d transmission line),  there 
appears to have been a theoretical likelihood that, post -Transaction, RWE could 
create congestion and would have had some certainty as to whether it would be 
called by TenneT to provide redispatching services. However, with the upgrades,  
the Commission notes that in the future there will likely be less  congestion and less 
demand from TenneT  for redispatching.  
(156)  The fact that there is no evidence that a generator in the Netherlands has ever 
deliberately caused congestion, taken tog ether with the risks inherent in attempting 
to benefit from causing congestion  (the risks of detection by TenneT and/or the 
ACM , with the subsequent risk of a fine and having its recognition as BRP 
withdrawn pursuant to Article 10.35 of the Dutch Electrici ty Grid Code , and the 
risk of losing money through producing  at unprofitable times where RWE would 
incur  negative margins , as outlined in paragraph (143) ), leads the Commission to 
conclude that the Transaction will not lead to a situation where RWE would engage 
in the anti -competitive behaviour of creating congestion to benefit from 
redispatch ing payments . 
(157)  On the basis of the above, the Commission considers that the Transaction does not 
raise serious doubts as to its compatibility with the internal market or the 
functioning of the EEA Agreement with respect to the overall market for  the 
provisi on of congestion management services , or its possible  sub-segments for 
capacity restriction agreements or redispatching , in the Netherlands.  
  
                                                 
194  See responses to questions D.C.1 and D.C.2 of the eRFI.  
195  Response to question D.C.1 of Request for Information 1 to TenneT.  
196  Email from ACM to DG COMP on 09/11/2022.  
197  See responses to question D.C.17 of the eRFI and the response to question D.C.8 of Request for 
Information 1 to TenneT.  
 
 
41 6. CONCLUSION  
(158)  For the above reasons, the European Commission has decided not to oppose the 
notified operation and to d eclare it compatible with the internal market and with the 
EEA Agreement. This decision is adopted in application of Article 6(1)(b) of the 
Merger Regulation and Article 57 of the EEA Agreement.   
 
For the Commission  
 
 
(Signed)  
Margrethe VESTAGER  
Executive Vice-President