IEEE Power & Energy Magazine - July/August 2015 - 62

between £20 billion and £50 billion across onshore (main
transmission system), offshore (connecting mainly offshore
wind farms) and cross-border interconnection transmission projects. The exact level and cost of these transmission
investments will depend on a number of factors, including the location of new conventional and renewable energy
sources (RES) plants (considering on- and offshore developments); decommissioning of existing ones; demand growth;
cross-border trading of energy and ancillary services; and
uptake of distributed generation, energy storage, demandside response, and other smart grid technologies.
Given this uncertainty and to a certain degree flexibility
on the potential investment plans, it becomes imperative that
these investments are undertaken, as much as possible, in
an efficient and timely manner that will largely depend on
how transmission investment is undertaken and how costs
are allocated. In this context, we analyze two main factors
that can significantly impact the level and cost of the transmission investments going forward by drawing on our recent
experience of 1) reviewing transmission pricing in Great
Britain and 2) examining the benefits of alternative policy
approaches associated with different levels of coordination
and Great Britain-European Union (EU) market integration
among offshore wind generation and interconnector projects
in the North Seas, respectively.

Effects of Transmission
Pricing Options in Great Britain
In principle, the mechanisms used to allocate short- and
long-term transmission network costs could materially affect
the value of a generator and its output and hence also affect
the generators' locational decisions. For instance, the choice
of where to locate a wind farm should involve consideration
of the trade-off between regional variation in wind speeds
(i.e., load factors) and the costs imposed on the transmission

Onshore
Transmission
Offshore
Transmission
Interconnection

system; similarly the choice of the location of gas-fired generators entails a trade-off between regional variation in gas
prices and electricity transmission system costs, along with
other factors such as the availability and costs of cooling
water. Efficient network charges that recover the costs of
infrastructure, congestion/constraints, and losses convey
pricing signals to investors and therefore provide a means of
ensuring the overall system economic efficiency.
In this context, we will explore this question further by
drawing on the recent experience of reviewing transmission
charging regime in Great Britain and the analysis carried out
(as part of this process) to assess the impact of the alternative
network charging options.

Great Britain Transmission Arrangements
The British wholesale market is characterized by a single
national wholesale price that reflects the prevailing marginal cost in a system without network congestion/constraints. Although there is no location-specific pricing,
infrastructure costs are recovered through network tariffs called transmission network use of system (TNUoS)
charges that include a location-specific component. Given
the dominant north-to-south power flows, network charges
for generators vary from around £25/kW/yr in Northern
Scotland to £-5/kW/yr in South West England (Figure 2),
while network charges for demand customers, based on
their peak demand, vary from £23/kW/yr in North Scotland to £45/kW/yr in South West England.
For 2015/2016, the total revenue collected will be £2,637
million, and it is expected to almost double by 2030. The cost
is split 27/73 (the exact split is currently under review with
proposals to review it annually or change the split to 15/85)
between generation and demand, and currently, the majority of transmission network costs (about 75%) are collected
through nonlocation specific flat charges (called residual
charge) implying a high level
of cost socialization. The locational part of the TNUoS tariffs
is computed using a methodology
that intends to reflect the longrun marginal costs of transmission investment. This part of the
transmission tariff was recently
reviewed through a regulatory
project called TransmiT.

Project Transmit Overview

Total
0

10

20
30
40
50
(Billions of £)
Current Asset Value
Minimim Expected Investment to 2030
Maximum Expected Investment to 2030

figure 1. Great Britain's current and future transmission asset value.
62	

ieee power & energy magazine	

60

The TNUoS charging methodology called investment cost related
pricing (ICRP) aims at setting
network charges that proxy the
network investment costs needed
to accommodate a "marginal"
megawatt of generation capacity or demand. Since historically
july/august 2015



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