Download Mr Gavin Steel Shetland Energy Consultation, Scottish Hydro

National Grid House
Warwick Technology Park
Gallows Hill, Warwick
CV34 6DA
Mr Gavin Steel
Shetland Energy Consultation,
Scottish Hydro Electric Power Distribution,
Inveralmond House,
200 Dunkeld Road,
Perth,
PH1 3AQ
Andy Balkwill
Regulatory Policy Manager
UK Transmission
[email protected]
Direct tel +44 (0)1926 655 988
Mobile
+44 (0)7836 230 714
www.nationalgrid.com
19 December 2014
Dear Gavin
A New Energy Solution for Shetland
National Grid Electricity Transmission plc (NGET) welcomes the opportunity to response to this
consultation. Our response is not confidential.
In our role as the GB System Operator we have responsibility for the real time operation and
balancing of the GB transmission System. Our responsibilities also include managing the commercial
relationships with all parties connected to or using the GB transmission system as well as developers
seeking future connection / use of the system. Shetland has no connection to the GB mainland and
has no transmission assets, and so we have no current involvement in its operation. However the
future prospect of a transmission link from the GB transmission system to Shetland to provide
capacity for low carbon generation projects offers the potential for generators on Shetland to
participate in GB electricity market arrangements. Thus some thought rightly needs to be given to
the implications that flow from this for the energy solution that Shetland will adopt to meet its future
needs.
Given Shetland’s relatively small size, competition between multiple independent generators is
unlikely to be realistic. We therefore support the adoption of a competitive design and delivery
process for the new generation on Shetland. SHEPD will need to provide all the competitors with the
same level of access to information and will need to ensure that there is no advantage, and that
there is no perception of any advantage, conferred on its affiliated generation business.
The Role of the Distribution System Operator
The development of increasing levels of embedded generation has been widely and regularly
forecast as a driver for the development of much more active operation of distribution systems.
There is as yet no agreed model for how the “distribution system operator” (DSO) will fulfil their role
and how it will interface with the NETSO’s role, but we are supportive of such steps in principle. This
consultation raises a number of questions in relation to a DSO’s potential role;
 How will the DSO determine which plants need to be re-dispatched, constrained on or off,
what prices will apply, how will they be funding of balancing activities be managed?
 How will the DSO procure other system services (inter-trips, reactive power, voltage control,
demand side response)?
National Grid is a trading name for:
National Grid Electricity Transmission plc
Registered Office: 1-3 Strand, London WC2N 5EH
Registered in England and Wales, No 2366977
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Will DSOs be required to manage the procurement and delivery of frequency response and
reserve on their system?
How will these roles interact with the NETSO’s role if and when a cable to the mainland is
established?
The consultation document generally seems to approach the issue of a new energy solution for
Shetland in a conventional system operational manner and suggests little thought is currently being
given to new models and the opportunity that Shetland might provide for developing the DSO role
and providing a potential model for the rest of GB. We think this is an area that requires further
thought in relation to Shetland specifically but one which the industry more generally needs to
address with a reasonable degree of urgency.
Cross-subsidy to Shetland and the North of Scotland
Regarding funding the increased costs of electricity supply for consumers in Shetland, our view is that
this is an issue of social policy and ideally the additional costs should be met from general taxation so
that GB electricity users are not adversely impacted. However it is a matter for Government and for
Ofgem and they consider there should be a cross-subsidy. There should be transparency over the
level of that cross-subsidy. The existing support scheme “Assistance for Areas with High Electricity
Distribution Cost” (AAHEDC) currently sits separately from the recovery of transmission network
revenues by National Grid through Transmission Network Use of System (TNUoS) charges. This
arrangement provides transparency of the cross subsidy and we see no reason why it should not be
extended to cover any additional costs arise out of the new arrangements on Shetland.
We suggest as part of the next stage, SHEPD should show the overall cash flows and the impact on
GB consumers of both the existing cross subsidy to consumers in the north of Scotland (addressed
through the AAHEDC scheme) and also any additional proposed cross-subsidy to Shetland.
From the perspective of our customers it is important that our forecasts of future TNUoS charges are
accurate. Thus if TNUoS is to be used as the route for managing the cross-subsidy then we need
timely and accurate forecasts of the level of cross subsidy that is required each year so that we can
build these into our charging models. While SHEPD network costs should be relatively easy to
forecast, those associated with balancing the Shetland network are likely to be more unpredictable
due to weather conditions, fuel costs etc. and so some thought will need to be given to how this is
managed. The Use of TNUoS would also appear to render our existing Transmission Licence
conditions that relate to the AAHEDC scheme superfluous.
We have provided responses to the individual questions in the attached Annex.
As this project progresses and more detailed information becomes available regarding the solution to
be adopted we will be happy to assist in addressing the more detailed practicalities that emerge. If
you have any questions regarding any of the points in our response then we would be happy to
discuss these with you or your colleagues.
Yours sincerely
[By e-mail]
Andy Balkwill
Regulatory Policy Manager
UK Transmission
Annex
A New Energy Solution for Shetland – Responses to Questions
Q1
No comment
Q2
Yes, provided that the cost of extending the use of contingency arrangements is included in
any assessment.
Q3
Yes
Q4
Yes, we see no reason to exclude any party from the process on the basis of existing support
schemes. However it would be a matter for Ofgem to determine how best to ensure that
consumers’ interests are protected.
Q5
In principle, yes
Q6
Service providers should be appropriately exposed to the costs of service failure – if they are
then testing may not be necessary.
Q7
We suggest option (a) is most appropriate. There is uncertainty over whether or when a link
to the mainland will be built. Given the direction of travel under ITPR there is also
uncertainty over the contractual and regulatory terms under which it might be built. We
appreciate that a capital / long term generation solution will require certainty to avoid
inefficient risk premia. This would suggest that some enduring commitment / provisions are
most likely needed to deliver an economic solution. However careful thought should be
given to the split between treatment of Opex and Capex (utilisation and availability) in any
contracting arrangement. We would suggest the transfer arrangements, including
adjustments to allowed revenues, would be considered at a regulatory level between the
service provider, the SO, TOs and DNO at a later stage, with possible reopeners in tender
contract for opex costs. For non-capital intensive options these would naturally have a
shorter period of commitment and therefore unlikely to present a transfer risk i.e. they could
be set up to be renegotiated at the point of transfer.
Q8
At this stage it is appropriate for the SO on Shetland to be the contracting counter party.
Q9
No comment
Q10
No comment
Q11
In the absence of the prospect of multiple competitive generators participating in a liquid
market we consider that competitive tendering of services is most likely to achieve the best
outcome for consumers.
Q12
Normal contractual principles should apply. For example, risks should sit with the party best
able to manage them. Incentives should be used to mitigate for information asymmetry.
Q13
No comment
Q14
We broadly agree with the proposals. We assume that the comments regarding delivery of
power in “…units that provide flexibility for efficient operation…” includes units formed by
aggregation of generation and demand side services and is not restricted to “conventional
generating units”. While it is necessary for all major sources of energy to be dispatchable by
the system operator it will be important that there is early transparency on the basis of
dispatch. A proposal incorporating for example CHP plant may be less flexible than other
plant and so any developer would need to understand the basis of the SO’s dispatch rules in
order to understand what scale of CHP plant could be accommodated.
Q15
We agree that non-delivery charges / incentives are important. The design of such measures
needs to provide effective incentives while at the same time not raising project risks to an
excessive level (which could lead to inefficient operation and higher cost for consumers).
They should be reflective of the costs imposed on the SO to remedy any non-delivery.
Q16
The information might be helpful – it would depend on the extent to which it was reflected
in contractual terms for non-delivery.
Q17
The points identified seem broadly appropriate, however we have a number of comments.
Some of the requirements might be overly restrictive – e.g. inflexible plant, but could be
mitigated by demand side services. It will be important that proposals are examined in the
round and that individual components are not excluded because of a non-conformity that
could be mitigated by some other element of the package.
In relation to:
•
Identifies any fuels (if required) which may be used for generating power and their expected sources, security of fuel
supply, back-up supplies and arrangements for stock of fuel to be maintained;
These appear to us to be commercial matters for the tenderer and it is unclear why such
information is needed by SHEPD.
•
Where determined relevant, has a proven track record in providing capacity and energy on a reliable basis over a
continuous period or other relevant evidence to confirm reliability.
This might be considered to be a barrier to new entrants. While any tender needs to be
rigorously examined to determine its credibility, it is not clear to us that a previous track
record is of itself a necessary requirement. The proposed test also raises questions
regarding who determines what constitutes a “proven track record”, what threshold
constitutes a “reliable basis” etc.
Q18
Time should be allowed for those without network connection offers to obtain them.
Q19
The future electricity supply for Shetland provides an opportunity for deployment of novel
technologies that might be offered by some tenderers. Factors for “technology deployment”
or “readiness” will need to be applied carefully to avoid the risk that the opportunity to use
new technologies is missed. Future system operation should be assessed with an open mind.
Q20
See above
Q21
No comment
Q22
The ancillary services listed appear relevant to an isolated system.
Q23
See response to Q25 below
Q24
Non-delivery charges and incentives are important however there is a balance to be struck.
If the incentives are too sharp then this can introduce significant risk for the generator /
service provider and they may respond by building in additional reliability / redundancy
which may not be economic. Non-delivery charges should reflect the costs that the SO
incurs in sourcing alternative energy. The value of lost load is also relevant – however this is
a complex area and it is not sufficient to apply a single figure for all customers and all times
(i.e. VOLL is dependent on the customer, the time of any interruption and the duration of
any interruption). The structure of such charges needs to be understood in advance of
tenders so the tenderers can take account of the risks they will face and design their offering
accordingly.
Q25
The length of contract duration needs to be considered in the context of the impact on
consumers. Longer contract terms give greater certainty for investors and are likely to result
in lower risk premia; however they lock consumers into choices made at a time when
technology is evolving quite rapidly. Shorter duration contracts provide opportunities for
new technologies to enter the market if they are competitive and drive costs down. They
also provide for the arrangements to be restructured to reflect the construction of a
transmission link to the GB mainland. However investors will need to be confident of
recovering their investment costs over that shorter period if excessive risk premia are to be
avoided.
The nature of the proposed solution may also have an impact – low capital cost and higher
operating cost solutions versus high capital cost and lower operating cost solutions. The
former generally argues for shorter contract durations, the latter, for longer.
All of these factors make it difficult to be specific over and ideal contract duration but given
the number of uncertainties, this suggests a medium duration contract – perhaps around 15
years (though this figure is not based on any rigorous analysis) might give a reasonable
balance between flexibility and certainty.
Though not directly related to this question, the eligibility of Shetland generation for the
Capacity Mechanism will clearly have a bearing on contract duration given the uncertainty
regarding the building of a cable to the mainland. Shetland generation will need to be
maintained to provide security of supply in the event the cable is unavailable due to planned
maintenance or a fault but its role would evolve from primary energy provider to that of
“back-up” plant. The Capacity Mechanism under EMR might help to reduce investor risk in
the event of construction of a mainland cable and so reduce cost to consumers.
Q26
See above
Q27
We broadly agree with the objectives identified.
Q28
Yes
Q29
SHEPD currently fulfils this role and could continue in the future. However some energy
solution providers might prefer to offer a package that incorporates operational control of
their generation including the balancing of demand (operation of the SHEPD network would
presumably remain with SHEPD) and so the competition should no rule this out. In terms of
a role for National Grid – we consider that this would only be likely (and even then not
certain) once a transmission link to the mainland is established. At that time the Shetland
power system would be likely to still constitute distribution network with embedded
generation and so (under current market arrangements) National Grid’s interaction would
only be with the larger generators. The evolution of an active DSO might reduce the SO role
for National Grid further still.
Q30
This question suggests that arrangements on Shetland could be modelled on the GB system
operator’s role. We think this might be a missed opportunity. The development of
increasing levels of embedded generation has been widely and regularly forecast as a driver
for the development of much more active operation of distribution systems. There is as yet
no agreed model for how the “distribution system operator” (DSO) will fulfil their role and
how it will interface with the NETSO’s role. How will the DSO determine which plants need
to be re-dispatched, constrained on or off, what prices will apply, how will they be funding of
balancing activities be managed? How will the DSO procure other system services (intertrips, reactive power, voltage control, demand side response)? Will DSOs be required to
manage the procurement and delivery of frequency response and reserve on their system?
How will these roles interact with the NETSO’s role when a mainland cable is present?
The consultation document generally seems to approach the issue of Shetland in a very
conventional system operational manner and suggests little thought is being given to new
models and the opportunity that Shetland might provide for developing the DSO role
(possibly with some elements as a model for more general application in GB). We think this
is an area that requires further thought in relation to Shetland specifically but the industry
more generally.
Q31
We think these questions need to be addressed as part of a wider industry debate on the
DSO role.
Q32
Are the current arrangements central despatch or are the ‘constrained despatch’? I.e. if the
power station on Shetland were in merit in GB it would sell energy in to the GB market, it
would run and SHEPD would not need to instruct it to run. It is by virtue of its high cost that
it is not self despatched. It is not clear that the Shetland SO being the single counter party
for all generation and supply would best serve consumers in Scotland or wider GB consumers
who subsidise this arrangement unless appropriate incentives were in place.
Q33
Yes
Q34
Yes
Q35
No
Q36
It appears to us that the Assistance for Areas with High Electricity Distribution Cost
“AAHEDC” already contributes / covers the costs of managing Shetland’s energy needs.
SHEPD incurs the cost of the network and generation; Ofgem allows it to be passed through
via AAHDEC scheme with is recovered by NGET from all Electricity Suppliers (this sits entirely
outside of the TNUoS charging arrangements). If additional costs (e.g. for balancing) were
likely to be efficiently incurred these should also be considered as part the periodic review of
AAHEDC, likewise any benefits could be returned to GB end consumers. If Ofgem did not
allow the costs separately in the SHEPD licence then this would be a loss for SHEPD as
AAHDEC is netted of the revenue they are allowed to collect from their network users.
With regards to the costs of balancing the system we believe that:
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Q37
the costs should be transparent;
there needs to be a mechanism to ensure that the NETSO’s performance against its incentive
scheme is not adversely impacted by poor Shetland SO performance in managing balancing costs
(i.e. they are excluded from the BSIS target); and
we see no reason why the Shetland SO should not be exposed to some form of incentive from day
one (even if it is relatively weak in terms of sharing factors and caps and collars). There should
not be a situation where they don’t care what the costs are as they just get passed through to GB
consumers.
A 100% pass through of all costs incurred gives no incentive to the Shetland system operator
to manage the costs efficiently. While we recognise that the costs of operating the system
on Shetland may be uncertain in the first few years we feel that there should be some level
of incentive on the system operator. It should be possible to estimate the likely cost range
and if necessary make use of regular reviews / reopeners to adjust targets in light of early
experience. Sharing factors could be set at a low level to provide an incentive without an
excessive risk, caps and floors can also be used to further manage exposure.
The implications of this consultation document and DECC’s ‘Support for non-domestic
electricity consumers on Shetland’ suggests that the increased cost of electricity on Shetland
would be recovered by National Grid via TNUoS. As noted above, the current AAHEDC
scheme sits outside of the TNUoS arrangements and we see no reason why these
arrangements could not be extended to cover the costs of balancing the Shetland power
system.
However if TNUoS is to be used then the key issues we believe are transparency of the costs
involved and accurate forecasts of the costs involved so that further uncertainty over
charges is not created for our customers. The increased distribution network costs on
Shetland should be readily forecastable so that accurate figures can be provided to NGET for
incorporation in TNUoS. If the costs of balancing the Shetland power system are also to be
recovered via TNUoS then, based on SHEPD’s views in the Consultation, there is likely to be
considerable uncertainty over this cost. Through its price control NGET is financially exposed
to any inaccuracies in its forecasts of demand and of various other components in the price
control. It is not appropriate to further expose NGET based on the cost estimates and
performance of a third party over which we have no control or influence. NGET should not
therefore bear the financing costs of any mismatch between the actual and the forecast
costs of subsidising the Shetland power system. Such costs should sit with the party best able
to manage them – SHEPD and the Shetland system operator.