Further National Grid Comments on Draft TAR NC.
We would like to propose the following issues for discussion within the TAR WG.
Article 4(5): We’ve had some push back on the lack of clarity about the CRRC. Perhaps this
could be simplified by not referring to a “capacity-based” option. We could simply state that
the complementary revenue recovery charge “may be commodity-based”. This will shorten
the text and not prohibit other types of CRRC. I am unaware that any TSO actually wants to
use a capacity-based complementary revenue recovery charge or there being any support
for such a charge from elsewhere.
Article 5(2): Is this section needed? What is stated is implicit in the cost allocation
methodologies and secondary adjustments.
Article 12: This still isn’t clear. 12(b) is still somewhat muddled, and 12 (d) & (e) are
incomplete.
I would propose something based on the following text:
1. The relevant parameters for variant A of virtual point based methodology shall include,
but shall not be limited to:
(a) the transmission service revenue;
(b) supply and demand data including the direction of the gas flow for each entry and for
each exit point under a peak demand scenario;
(c) detailed representation of the transmission network with identification of segments and
nodes based on the existing pipelines and new pipelines expected to be operational as from
or before the relevant gas year;
(d) the value of the long run average incremental costs;
(e) the factor of the costs for the expansion of the transmission network;
(f) the annuitisation factor;
(g) the entry-exit split;
(h) the identification of a reference node.
2. The reference prices shall be calculated in the following sequential steps:
(a) choose one node from the transmission network as the reference node;
1
(b) The aggregate supply flow is adjusted to ensure supply is equal to the peak demand
scenario. The adjustment in peak supplies at each point is done following a merit order that
reflects the supply patterns of the network. This is done until the aggregate supply has been
reduced to the level that matches the aggregate demand. Thus the supply figures for
individual supply points may be set at a level that is less than or equal to the technical
capacity of that point.
(c) An optimisation model (a mathematical solver) takes the inputs described above and
uses a transport algorithm to derive the pattern of balanced network flows from each entry
point to the selected reference node and from the reference node to each relevant exit
point such that it minimises the distances travelled by these flows from a supply node or to
a demand node, assuming every network section has sufficient capacity. It thus derives the
minimum total network flow distance (the product of flow and distance) for that given set of
supply and demand flows in accordance with the following:
(i) the model calculates the flow distance values for each pipeline segment in the network
model. Values shall be recorded as positive values for a given segment of the transmission
network where the direction of the gas flow under peak conditions coincides with the
direction of the transport route from the entry point to the reference node or from the
reference node to the exit point. Otherwise, the resulting values shall be recorded as
negative values for a given segment of the transmission network.
(ii) An aggregate flow distance value is allocated to each entry and exit point based on the
sum of flow distance values for each segment in the transport route between each entry
point and the selected reference node and the reference node to each exit point.
(d) This is a marginal cost model thus the long run average incremental cost value at each
node represents the sensitivity of the calculated total network flow distance value to a
change in supply or a change in demand at that node. The marginal cost is expressed in units
of distance (or marginal distance) since this is a flow gradient representing the total flow
distance divided by a change in the nodal flow. The marginal distance values for each entry
and exit point are derived from their flow distances per change in flow.
(e) The values referred to in point (d) represents the marginal distances resulting from the
optimisation of the flow distance to and from the reference node. These initial marginal
distances shall be adjusted to either maintain the chosen entry-exit split in transmission
service revenues where prices are used to set reference prices, or to recover a target level
of revenue, where prices are floating. This adjustment represents the optimisation of the
flow distances to a virtual point to achieve the desired tariffs.
(f) The adjusted marginal distances are converted into unit costs by multiplying by the
relevant factor of the costs for the expansion of the transmission network which represents
the capital cost of the transmission infrastructure investment required to transport a given
unit of energy over a given unit of distance. The projected cost of expansion of pipelines at a
given pressure rating and compression facilities shall be based on manufacturers’ budgetary
prices and historical costs inflated to present values.
2
(g) , the unit costs described in (f) are converted into reference prices by applying the
relevant annuitisation factor which is calculated with consideration of the assumed asset
life, the allowed rate of return on capital expenditure and any operating expenditure
allowance and dividing by the number or days or hours in the year.
Article 16 (3): Propose deletion. This potentially blocks the “virtual point A” methodology
and its inclusion isn’t required by the FG.
Article 27: Although this is aligned to the FG, I think we need a discussion about aligning
publication of tariffs to the auction calendar rather than the tariff period.
Article 38 (3): line 2 change “cost allocation methodology” to “cost allocation approach” –
links better to article 4(6).
Article 41 (2): Greater clarity could be given that we are discussing the option of “fixed price
mechanisms” rather than a simple fixed price. This needs discussion within the tariff group
but I would propose that we give two clear options (as described in the stakeholder
workshops):
1: the use of generating a predicable floating price using the indexation of the allocated
reserve price (a small additional variable (i.e. commodity) charge should be allowed in such
cases).
2: the use of a risk premium to lock in the price (as an alternative to the floating price). This
requires discussion as to how the risk premium is treated. For example, we could suggest
that it is held in a separate account and only transfer funds from this account to the TSO’s
allowed revenue up to the value of the calculated “floating” price. The key questions
concern who shares this risk if the risk premium account is insufficient to off-set the
increase in the floating price, (i.e. TSO or all shippers) and if the risk premium should lock in
certainty for the duration of the contract. The calculation of the risk premium also has to be
considered.
3