To minimise the total cost of the system,
the system operator first uses the cheap
generation in City A. Generators in City A
serve the local demand (50 MW). That is
why the nodal price in City A equals the
local generation cost ($10/MWh). Generators in City A also export 80 MW to
City B. Since the capacity of the interconnection is fully utilised, expensive
generators in City B serve the rest of the
local demand (10 MW). As a result, the
nodal price in City B equals the local
generation cost ($20/MWh). The total cost
is $1,500 (= 140 MW * $10/MWh +
10 MW * $20/MWh).
However, nodal pricing has disadvantages as
well as advantages. First, vulnerability to market
power may arise because the segmentation of the
electricity market into smaller locational markets
increases the concentration of generators at each
node with a supply deficit. Some authors challenge this view and argue that the network
architecture is the main driver of market power,
instead of the pricing mechanism. Nodal pricing
can also reduce liquidity in long-term contracting, such as financial transmission rights and
contracts for differences. This problem is
addressed in the USA by averaging nodal prices
into trading hub prices to provide liquidity to
market participants.
Zonal pricing, another form of locational
pricing, may provide a useful compromise
between uniform and nodal pricing. Zonal pricing addresses the complexity introduced by large
numbers of nodes by aggregating nodes into
zones. Similar to dispatch under nodal pricing,
the system operator first dispatches generation,
given transmission constraints between zones. If
transmission lines in a given zone are congested,
the system operator has to re-dispatch generation
in that zone to alleviate congestion. As a result,
zonal pricing provides some of the benefits of
nodal pricing in terms of signalling network
congestion but does not fully eliminate the
re-dispatch costs associated with uniform pricing.
Locational pricing may be considered once
time-of-use pricing is fully implemented. Wider
changes to improve the flexibility of the electricity system through electricity storage and
demand response are expected to reduce demand
and generation peaks, which would automatically
reduce network congestion relative to an inflexible system. These changes require time-of-use
pricing to be fully implemented across all system
resources (including end users) to be fully
effective.
Fig. 68 Nodal pricing reflects the cost of supplying additional electricity at a given node. Source Vivid Economics
568
S. Yaodong and A. Gillespie
the system operator first uses the cheap
generation in City A. Generators in City A
serve the local demand (50 MW). That is
why the nodal price in City A equals the
local generation cost ($10/MWh). Generators in City A also export 80 MW to
City B. Since the capacity of the interconnection is fully utilised, expensive
generators in City B serve the rest of the
local demand (10 MW). As a result, the
nodal price in City B equals the local
generation cost ($20/MWh). The total cost
is $1,500 (= 140 MW * $10/MWh +
10 MW * $20/MWh).
However, nodal pricing has disadvantages as
well as advantages. First, vulnerability to market
power may arise because the segmentation of the
electricity market into smaller locational markets
increases the concentration of generators at each
node with a supply deficit. Some authors challenge this view and argue that the network
architecture is the main driver of market power,
instead of the pricing mechanism. Nodal pricing
can also reduce liquidity in long-term contracting, such as financial transmission rights and
contracts for differences. This problem is
addressed in the USA by averaging nodal prices
into trading hub prices to provide liquidity to
market participants.
Zonal pricing, another form of locational
pricing, may provide a useful compromise
between uniform and nodal pricing. Zonal pricing addresses the complexity introduced by large
numbers of nodes by aggregating nodes into
zones. Similar to dispatch under nodal pricing,
the system operator first dispatches generation,
given transmission constraints between zones. If
transmission lines in a given zone are congested,
the system operator has to re-dispatch generation
in that zone to alleviate congestion. As a result,
zonal pricing provides some of the benefits of
nodal pricing in terms of signalling network
congestion but does not fully eliminate the
re-dispatch costs associated with uniform pricing.
Locational pricing may be considered once
time-of-use pricing is fully implemented. Wider
changes to improve the flexibility of the electricity system through electricity storage and
demand response are expected to reduce demand
and generation peaks, which would automatically
reduce network congestion relative to an inflexible system. These changes require time-of-use
pricing to be fully implemented across all system
resources (including end users) to be fully
effective.
Fig. 68 Nodal pricing reflects the cost of supplying additional electricity at a given node. Source Vivid Economics
568
S. Yaodong and A. Gillespie