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Welfare analysis of increased interconnection between France and Ireland


The all-island electricity market in Ireland has been in operation since 2007. Existing electricity interconnection between the Republic of Ireland, Northern Ireland and the United Kingdom is small but plays an important role in current electricity market operation in the region. A 700 MW Electricity interconnector between Ireland and France was proposed in 2009. In June 2016, the UK voted to leave the European Union and this has refocused political attention on Ireland’s limited interconnection capacity and the need for geographic diversification of interconnector options. We provide the first publically available detailed welfare impact of a new interconnector from Ireland to France and use an EU wide power system model (PLEXOS-EU) to simulate one vision of the 2030 EU electricity market based on European Commission analysis under varying fuel price assumptions. We demonstrate, that varying fuel prices has limited impact on welfare for the scenarios examined and the project has the potential for a positive impact on welfare in Ireland if low project interest rates are achieved. Our results show that the investment in interconnection reduces wholesale electricity prices in France and Ireland as well as the net revenues of thermal generators. The owners of the new interconnector between France and Ireland see positive net revenues. France is only marginally affected by the new interconnector. Renewable generators see a modest increase in net revenues. Great Britain may see welfare losses associated with the additional interconnection primarily driven by lower net revenues from existing Irish-British transmission line and higher costs of electricity generation.

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  5. For WTO members the EU has no tariff on electricity or gas imports.



  8. The Irish Single Electricity Market (SEM) is dispatched considering the two jurisdictions together (the all-island system). More information on the Irish SEM can be found here:

  9. Maximum capacity, minimum stable factors, ramp rates, maintenance rates, forced outage rates, start costs etc.

  10. The full model and data used are available via

  11. The EU Reference Scenario Is generated using PRIMES. PRIMES is a partial equilibrium model that provides “projections of detailed energy balances, both for demand and supply, CO2 emissions, investment in demand and supply, energy technology penetration, prices and costs”. The projections are set up in order to meet the EU targets on emissions for 2030://

  12. The generation mixes of Switzerland and Norway were developed based on ENTSOE [9] and Energiewende (2015).

  13. On the absence of market power in the Irish SEM see Walsh et al. [18].

  14. Production costs for power plant type i, inclusive of CO2, are calculated as: \( ProdCost\_i = FuelPrice\_i*HeatRate\_i + ETS*(HeatRate\_i*CO2EmissRate\_i) \)


  16. Some transmission lines have different export and import capacity. The full data set is available as supplementary information.

  17. Prices are calculated as load weighted averages: \( p_{{\left\{ {year} \right\}}} = \frac{{p_{h} *L_{h} }}{{\mathop \sum \nolimits_{h = 1}^{8760} L_{h} }} \) where h is the hour and L is the load. In the Tables, the delta between “With IC” and “Without IC” is shown.

  18. For simplicity, Moyle and EWIC interconnectors between Ireland and Great Britain are considered together. As a result, we split evenly also the net revenues of these interconnectors between the Irish and the British TSOs. This is a lower bound estimates of the net revenues of the Irish TSO, which owns 100% of the EWIC interconnector.

  19. The report was accessed on 14 June 2017 at: system-development-reports/tyndp/Pages/default.aspx. We also checked the published reports of the 2016 network plan but in the published works available for 2016 the numbers for 2014 are confirmed.

  20. See pg. 149.

  21. The data can be found here:

  22. PLEXOS Help Files.



Generation unit


Total number of generators


Interconnector line


Total number of interconnector lines


Time period


Optimisation time horizon


Index related specifically to pumped storage unit

RESup :

Upper storage reservoir

RESlow :

Lower storage reservoir

Vjt :

Integer on/off decision variable for unit j at period t

Xjt :

Integer on/off decision variable for pumped storage pumping unit j at period t

Ujt :

Variable that = 1 at period t if unit j has started in previous period else

Pjt :

Power output of unit j at period t (MW)

Hjt :

Pump load for unit j at period t (MW)

Flt :

Power flow on interconnector line l at interval t between market nodes (MW)

Wint :

Flow into reservoir at time t (MWh)

Woutt :

Flow out of reservoir at time t (MWh)

Wt :

Volume of storage at a time t (MWh


Penalty for loss of load (€/MWh)


Penalty for reserve not met


Unserved energy (MWh)


Reserve not met (MWh)


Demand (MW)


Objective function

njt :

No load cost unit j in period t (€)

cjt :

Start cost unit j in period t (€)

mjt :

Production cost unit j in period t (€)

estor :

Efficiency of pumping unit (%)

pmaxj :

Max power output of a unit j (MW)

pminj :

Min stable generation of unit j (MW)

pmpmaxstor :

Max pumping capacity of pumping unit

Jj :

Available units in each generator

Jstor :

Number of pumping units

MRUj :

Maximum ramp up rate (MW/min)

MRDj :

Maximum ramp down rate (MW/min)

MUTj :

Minimum up time (hrs)

Ap :

Number of hours a unit must initially be online due to its MUT constraint (hrs)


Wheeling charge on interconnector line (€/MWh)


Maximum power flow on interconnector line (MW)

eline :

Efficiency of interconnector line (%)


Initial volume of reservoir (GWh)


Maximum volume of storage (GWh)


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Valeria Di Cosmo acknowledges support from the European Union’s Horizon 2020 research and innovation programme under the Marie Skłodowska-Curie Grant agreement no. 703382. We thank the participants to 2016 FSR Climate Conference, Laura Malaguzzi Valeri, John Fitzgerald, Valentin Bertsch, Muireann Lynch and John Curtis for helpful comments and suggestion. The authors are responsible for all remaining errors.

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Appendix 1: Generation

Table 10 show generation from thermal and renewable sources for Ireland, Great Britain and France.

Table 10 Thermal and RES generation, GWh

Appendix 2: PLEXOS detailed equations

Operation Constraints on Interconnectors

This equation describes the basic operational constraint that limits power flow on interconnector lines:

$$ F_{lt} - F{ \hbox{max} }_{lt} \le 0 $$

Objective function

$$ OBJ = Min\sum {\mathop \sum \limits_{{\begin{array}{*{20}c} {\forall t \in T} \\ {\forall j \in J} \\ {\forall l \in L} \\ \end{array} }} c_{jt} \cdot U_{jt} + n_{jt} \cdot V_{jt} + m_{jt} \cdot P_{jt} + qf \cdot F_{lt} + vl \cdot use_{t} + vs \cdot usr_{t} } $$

The objective function in PLEXOS is to minimise the start-up cost of each unit (start cost (€)* number of starts of a unit) + the no load cost of each online unit + production costs of each online unit + cost of flow on interconnector lines + the penalty for unserved load + the penalty of unserved reserve.

The objective function is minimised within each simulation period. The simulation solution must also satisfy the constraints below:

Energy balance equation

$$ \sum {\mathop \sum \limits_{{\begin{array}{*{20}c} {\forall t \in T} \\ {\forall j \in J} \\ {\forall l \in L} \\ \end{array} }} P_{jt} - H_{jt} - F_{lt} \cdot (1 - e_{line} ) + use_{t} = D_{t} } $$

Energy balance equation states that the power output from each unit at each interval—pump load from pumped storage units for each interval—efficiency losses on interconnector lines + unserved energy must equal the demand for power at each interval. As the penalty for unserved energy is high and part of the objective function, the model will generally try to meet demand.

Operation constraints on units

Basic operational constraints that limit the operation and flexibility of units such as maximum generation, minimum stable generation, minimum up/down times and ramp rates.

$$ - V_{jt} + U_{jt} \ge - 1\forall t = 1 $$
$$ V_{jt} - V_{j,t + 1 } + U_{j,t + 1} \ge 0 $$

These two equations define the start definition of each unit and are used to track the on/off status of units.

$$ P_{jt} - P\max\nolimits_{j} \cdot V_{jt} \le 0 $$

Max export capacity A units power output cannot be greater than it maximum export capacity.

$$ P_{jt} - P\min\nolimits_{j} \cdot V_{jt} \ge 0 $$

Minimum stable generation A units output must be greater than it minimum stable generation when the unit is online.

$$ H_{jt} - Pmp\max\nolimits_{Stor} \cdot X_{jt} \le 0 $$

Pumping load must less than maximum pumping capacity for each pumping unit

$$ V_{jt} + X_{jt} \le 1 {\text{where }}j \in stor $$
$$ V_{j} \le J_{j} X_{j} \le J_{Stor} \quad j \in J $$

These constraints limit a pumped storage unit from pumping and generating at same time.

$$ A_{p,j} \ge V_{j,t} - V_{j,t - 1} \forall t \cdot t - MUT_{j} - 1 $$
$$ V_{j,t} \ge A_{p,j} - \mathop \sum \limits_{t}^{{t - MUT_{j} + 1}} V_{j,t} /MUT_{j} \forall t $$

Minimum up timesFootnote 22 (Note the following text is directly from the PLEXOS Help files). The variable Ap tracks if any starts have occurred on the unit inside the periods preceding p with a window equal to MUT. i.e. if no starts happen in the last MUT periods then Ap will be zero, but if one (or more) starts have occurred then Ap will equal unity. The MUT constraints then sets a lower bound on the unit commitment that is normally below zero, but when a unit is started, the bound rises above zero until the minimum up time has expired. This fractional lower bound when considered in an integer program forces the unit to stay on for its minimum up time.

$$ A_{p,j} \ge V_{j,t - 1} - V_{j,t} \forall t \cdot t - MDT_{j} + 1 $$
$$ V_{j,t} \le 1 + \mathop \sum \limits_{t}^{{t - MDT_{j} + 1}} V_{j,t} /MDT_{j} - A_{p,j} \forall t $$

Minimum down times The variable Ap tracks if any units have been shut down inside the periods preceding p with a window equal to MDT. i.e. if no units are shutdown in the last MDT periods then Ap will be zero, but if one (or more) shutdown then Ap will equal unity. The MDT constraints then set an upper bound on the unit commitment that is normally above unity, but when a unit is stopped, the bound falls below unity until the minimum down time has expired.

$$ P_{jt} - P_{j.t - 1} - MRU_{j} \cdot V_{jt} - P\min\nolimits_{j} \cdot U_{j} \le 0 $$
$$ P{ \hbox{min} }_{j} \cdot P_{jt} + P_{jt} - P_{j.t - 1} - P_{jt} \cdot (MRD_{j} - P{ \hbox{min} }_{j} ) \le 0 $$

Maximum ramp up and down constraints These constraints limit the change in power output from one time period to another.

Water balance equations

These equations track the passage of water from the lower reservoir to the upper reservoir. In this set-up there is no inflow and water volume is conserved.

$$ W_{tR} + W_{out.tR} - W_{in.tR} = W_{INT,R} \quad \forall t = 1,R \in RES_{Up,} RES_{low} $$
$$ W_{{t.RES^{up} }} + W_{{out,RES^{up} }} - W_{{in,RES^{up} }} = 0 $$
$$ e_{stor} .H_{{jt.RES^{up} }} - W_{{in.tRES^{up} }} = 0 $$
$$ P_{stor.t} - W_{{out.t.RES^{up} }} = 0 $$

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Di Cosmo, V., Collins, S. & Deane, P. Welfare analysis of increased interconnection between France and Ireland. Energy Syst 11, 1047–1073 (2020).

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