(a)

the incremental physical power flows resulting from the acceptance of this request imply that secure operation of the power system may no longer be guaranteed, and

(b)

the value in monetary amount attached to this request in the congestion management procedure is lower than all other requests intended to be accepted for the same service and conditions.

(a)

the characteristics of the markets,

(b)

the operational conditions, such as the implications of netting firmly declared schedules,

(c)

the level of harmonisation of the percentages and timeframes adopted for the different capacity allocation mechanisms in place.

(a)

Northern Europe (i.e. Denmark, Sweden, Finland, Germany and Poland),

(b)

North-West Europe (i.e. Benelux, Germany and France),

(c)

Italy (i.e. Italy, France, Germany, Austria, Slovenia and Greece),

(d)

Central Eastern Europe (i.e. Germany, Poland, Czech Republic, Slovakia, Hungary, Austria and Slovenia),

(e)

South-West Europe (i.e. Spain, Portugal and France),

(f)

UK, Ireland and France,

(g)

Baltic states (i.e. Estonia, Latvia and Lithuania).

(a)

Use of a common transmission model dealing efficiently with interdependent physical loop-flows and having regard to discrepancies between physical and commercial flows,

(b)

Allocation and nomination of capacity to deal efficiently with interdependent physical loop-flows,

(c)

Identical obligations on capacity holders to provide information on their intended use of the capacity, i.e. nomination of capacity (for explicit auctions),

(d)

Identical timeframes and closing times,

(e)

Identical structure for the allocation of capacity among different timeframes (e.g. 1 day, 3 hours, 1 week, etc.) and in terms of blocks of capacity sold (amount of power in MW, MWh, etc.),

(f)

Consistent contractual framework with market participants,

(g)

Verification of flows to comply with the network security requirements for operational planning and for real-time operation,

(h)

Accounting and settlement of congestion management actions.

(a)

annually: information on the long-term evolution of the transmission infrastructure and its impact on cross-border transmission capacity;

(b)

monthly: month- and year-ahead forecasts of the transmission capacity available to the market, taking into account all relevant information available to the TSO at the time of the forecast calculation (e.g. impact of summer and winter seasons on the capacity of lines, maintenance on the grid, availability of production units, etc.);

(c)

weekly: week-ahead forecasts of the transmission capacity available to the market, taking into account all relevant information available to the TSOs at the time of calculation of the forecast, such as the weather forecast, planned maintenance works of the grid, availability of production units, etc.;

(d)

daily: day-ahead and intra-day transmission capacity available to the market for each market time unit, taking into account all netted day-ahead nominations, day-ahead production schedules, demand forecasts and planned maintenance works of the grid;

(e)

total capacity already allocated, by market time unit, and all relevant conditions under which this capacity may be used (e.g. auction clearing price, obligations on how to use the capacity, etc.), so as to identify any remaining capacity;

(f)

allocated capacity as soon as possible after each allocation, as well as an indication of prices paid;

(g)

total capacity used, by market time unit, immediately after nomination;

(h)

as closely as possible to real time: aggregated realised commercial and physical flows, by market time unit, including a description of the effects of any corrective actions taken by the TSOs (such as curtailment) for solving network or system problems;

(i)

ex-ante information on planned outages and ex-post information for the previous day on planned and unplanned outages of generation units larger than 100 MW.