IEEE Power & Energy Magazine - July/August 2015 - 63

We analyze two main factors that can significantly
impact the level and cost of the transmission investments
going forward.
the transmission system was planned and built to provide the
capacity required during peak demand conditions, the current ICRP methodology reflects the network investment costs
needed to meet this requirement.
However, the need to accommodate peak demand conditions is no longer the sole driver of transmission capacity
requirements. Increasingly, investments to expand the transmission system are required to integrate renewable generators into the transmission system, particularly wind farms.
Wind generators typically produce less during extreme
winter conditions when demand is highest. Instead, their
production is highest on windy days when overall electricity demand is typically lower than peak levels. These dual
drivers of transmission investment are now reflected in the
network planning standards, which specifies the criteria that
transmission owners must apply when deciding how much
transmission capacity to provide. As a result, transmission
system operators (TSOs) are obliged to provide sufficient
boundary capacity to fulfil two criteria:
✔✔ a demand security criterion that requires sufficient
boundary capacity to ensure continued system operation in peak demand conditions, on the assumption
that intermittent generation and interconnectors are
unavailable and with all other generation variably
scaled uniformly to match generation to demand
✔✔ an economic criterion that requires sufficient boundary capacity to ensure economic operation of the system (balanced network investment and congestion/
constraints), on the assumption that output from different low-carbon generation technologies (intermittent,
nuclear, and carbon capture and storage), conventional
generation, pumped storage, and interconnectors are
scaled by specific factors to meet demand.
For this reason, in 2010, the Great Britain energy market regulator, Ofgem, announced a fundamental review of
current electricity charging arrangements, called Project
TransmiT, which aimed to improve the charging methodology. Through this process, Ofgem originally proposed
to consider three possible scenarios for network charging
going forward:
✔✔ the status quo, whereby the current model would continue with minor modifications
✔✔ a socialized or uniform charging model, whereby generation TNUoS charges would be paid through a uniform charge per megawatthour of energy output
✔✔ an improved ICRP charging model, which seeks to
alter the existing charging model to reflect the fact
july/august 2015	

that different types of generation may impose different costs on the transmission system.
The way the uniform charges are calculated is straightforward; the total amount of revenue that needs to be recovered from generators [27% of the annual regulatory asset
value (RAV)] is just split by the total generation capacity resulting to a fixed uniform charge on a £/kW/yr basis.
To calculate the status quo and improved ICRP charges, a
transport model is used that calculates the marginal cost of
investment in the transmission system, required as a consequence of an increase in demand or generation at each
connection point or node on the transmission system, by
analyzing the system power flows during peak demand
conditions. The key difference between the two charging
methodologies is how generation is scaled so as to meet
this peak demand condition. In the status quo, all generation capacity is scaled down uniformly. In the case of
improved ICRP, the transport model runs twice with different scaling factors for different technologies. The first run,
called peak scenario (accounting for the demand security
criterion), assumes that interconnection and RES load factor is zero and all other generators are scaled uniformly.
The second scenario, called year-round (that accounts for
the economic criterion), sets different scaling factors for
different types of plant (Table 1).

25.42
22.79

30.25
19.75

26.15 21.55
16.40

18.51
16.49 15.53

12.84
11.07
7.47

7.41

8.64
6.34
5.18

3.49

2.44
5.57

2.92

-5.16

-4.44
0.04

-3.04

-1.69

0.19

figure 2. Great Britain generation transmission tariffs
£/kW/yr.
ieee power & energy magazine	63



Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - July/August 2015

IEEE Power & Energy Magazine - July/August 2015 - Cover1
IEEE Power & Energy Magazine - July/August 2015 - Cover2
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IEEE Power & Energy Magazine - July/August 2015 - Cover3
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