“because such plants will generally have a low impact on the total electricity system and it is considered appropriate therefore that, subject to consultation, such stations should be exempted from the same degree of system regulation (and costs) as imposed by standard licensing conditions.”
“National regulatory authorities should be able to fix or approve tariffs, or the methodologies underlying the calculation of the tariffs, on the basis of a proposal by the transmission system operator or distribution system operator(s), or on the basis of a proposal agreed between those operator(s) and the users of the network. In carrying out those tasks, national regulatory authorities should ensure that transmission and distribution tariffs are non-discriminatory and cost-reflective, and should take account of the long-term, marginal, avoided network costs from distributed generation and demand-side management measures.”
“In carrying out the regulatory tasks specified in this Directive, the regulatory authority shall take all reasonable measures in pursuit of the following objectives within the framework of their duties and powers as laid down in Article 37, in close consultation with other relevant national authorities including competition authorities, as appropriate, and without prejudice to their competencies: … (d) helping to achieve, in the most cost-effective way, the development of secure, reliable and efficient non-discriminatory systems that are consumer oriented, and promoting system adequacy and, in line with general energy policy objectives, energy efficiency as well as the integration of large and small-scale production of electricity from renewable energy sources and distributed generation in both transmission and distribution networks;”
“(a) that compliance with the use of system charging methodology facilitates effective competition in the generation and supply of electricity and (so far as is consistent therewith) facilitates competition in the sale, distribution and purchase of electricity; (b) that compliance with the use of system charging methodology results in charges which reflect, as far as is reasonably practicable, the costs (excluding any payments between transmission licensees which are made under and in accordance with the STC) incurred by transmission licensees in their transmission businesses and which are compatible with standard condition C26 (Requirements of a connect and manage connection); (c) that, so far as is consistent with sub-paragraphs (a) and (b), the use of system charging methodology, as far as is reasonably practicable, properly takes account of the developments in transmission licensees' transmission businesses; (d) compliance with the Electricity Regulation and any relevant legally binding decisions of the European Commission and/or the Agency; and (e) promoting efficiency in the implementation and administration of the system charging methodology.”
“The DCLF ICRP transport model calculated the marginal costs of investment in the transmission system which would be required as a consequence of an increase in demand or generation at each connection point or node on the transmission system, based on a study of peak demand conditions using both Peak Security and Year Round generation backgrounds on the transmission system. One measure of the investment costs is in terms of MWkm. This is the concept that ICRP uses to calculate marginal costs of investment. Hence, marginal costs are estimated initially in terms of increases or decreases in units of kilometres (km) of the transmission system for a 1 MW injection to the system.”
“14.15.59 The expansion constant, expressed in £/MWkm, represents the annuitised value of the transmission infrastructure capital investment required to transport 1 MW over 1 km. Its magnitude is derived from the projected cost of 400kV overhead line, including an estimate of the cost of capital, to provide for future system expansion. 14.15.60 In the methodology, the expansion constant is used to convert the marginal km figure derived from the transport model into a £/MW signal. ….”
“Under the current regime however, the total charges avoided through embedded generation do not reflect their incremental impact on network costs, but a measure of sunk costs, which are by definition unalterable. The result is a system of inefficient signals that distorts behaviour.”
“At the heart of the inefficiencies identified through this work is a mismatch between embedded generators’ incremental impact on power system costs and the charges and revenues facing them. In particular, net charging of suppliers means that embedded generators are currently in receipt of significant payments for behaviour that amounts to the avoidance of charges to recover historic network costs …”
“3.5 Does EG provide any other benefit? The locational element of the demand TNUoS charging arrangements should broadly reflect the costs and benefits that EG brings to the wider transmission system, in a similar way to wider generation transmission locational charges. However, we think that in addition to the benefits captured by the demand locational signal, EG (independent of their location) will also benefit the transmission system by avoiding investment at the importing GSPs (or increase costs if it drives investment at exporting GSPs). We note that National Grid over the years have estimated the likely size of this benefit to be between£1 /kw and£6 /kw. We have seen other attempts to estimate the additional benefit that EG provide to the transmission system beyond that captured in the locational element of TNUoS charges but are currently not convinced by the rationale presented thus far and propose that industry considers how to calculate such a number and the justification for the approach taken.”
“System peak is lower today due to a number of factors, including embedded generation, and therefore some argued that embedded generation has resulted in a smaller transmission network and hence lower cost than otherwise may have been ( … ). Others pointed out that additional embedded generation in constrained areas of the system, for example Scotland, has contributed to a need for more transmission circuits to be constructed, to allow their power to be exported from these areas.”
“Understanding the residual. Further, the notion that the D-TNUoS charge can be split into the locational element of the charge that is cost-reflective, and the residual charge that represents a charge to recover the “fixed/sunk” costs of the network is entirely unjustified. The locational element of the charge is only designed to signal differences in the cost demand imposes across different locations, not the absolute level of transmission cost that demand imposes. Whilst the total locational charge only accounts for 10% of the allowed transmission revenue, the demand locational charge nets to a£0 recovery. This therefore implies either that there is no capital investment, maintenance or operational costs incurred on the transmission system as a result of demand or, more likely, that this signal is in fact, not cost-reflective.” (2) Other members of the Workgroup expressed the following view: “… evidence has been presented to the working group and contained in this report that demonstrated that: • Flows on the transmission system are identical following the connection of an equal volume of distribution or transmission connected generation at the same location. • The size of the transmission system (and hence the cost) is effected by the location of the connection point and is independent of the how the generation is connected i.e. distribution and transmission connected generation have the same effect on the transmission system. • In general a larger transmission system will be needed to accommodate generation if it is connected independently of a locational signal. It is recognised that the current embedded benefit regime does not provide a strong locational signal. • Demand customers pay an additional premium above the cost required to fund available TNUoS to pay embedded benefits to distribution connected generation”
“The logical basis for the changes in the TNUoS methodology that Ofgem’s Open Letter seems to be contemplating is extremely weak. In particular, the notion that the D-TNUoS charge can be split into the locational element of the charge that is cost-reflective, and the residual charge that represents a charge to recover the “fixed/sunk” costs of the network is entirely unjustified. The locational element of the charge is only designed to signal differences in the cost that demand imposes across different locations, not the absolute level of transmission cost that demand imposes. The ratio between the two depends on regulatory decisions regarding what share of costs generation and demand should bear, and the arbitrary choice of reference node in the charging methodology. In fact, rather than a problem with the residual charge, there are a range of flaws associated with the locational element of the charge. If these flaws were rectified, the locational element of the charge would recover a larger amount of revenue, and the expected growth in the demand residual could be moderated. In fact, the range of reforms to TNUoS arrangements put forward through the CMP264/5 working group process also introduce a range of new distortions that would detrimentally affect welfare. Any new reform aimed at addressing existing distortions would need to examine carefully the trade-off between the new distortions that the modifications would create.”
“The current method for setting the locational element of the TNUoS charges fails to recognise that two (otherwise identical) generators impose the same cost on the transmission system, irrespective of whether they are embedded within distribution systems or connected to the transmission system. There should also be no difference between the transmission costs imposed on the system (per kW of generation capacity) by embedded generators with capacities above or below 100MW, if they are designed and operated in an identical way in other respects. The current approach of setting different charges for different types of generation depending on whether they are embedded or not and depending on size does not reflect the fact that they impose the same costs on the transmission system.”
“Ofgem’s references to “fixed” and “sunk costs” also appear misleading. Transmission network capacity is built to serve network users. Once provided, the costs of providing that transmission are sunk, but at the point of provision the investment was avoidable. Hence, it is economically efficient to signal these costs through TNUoS charges. The vast majority of transmission costs could also be described “fixed” in the sense that they are capital costs that do not vary with output (eg. MWh transported) and cannot be avoided in the very short-term. However, transmission investment requirements vary with the behaviour of network users, and as such are not fixed in the medium to long-term.”
“Question 7: Do you agree with our assessment that the value of the avoided GSP investment cost best facilitates the applicable CUSC objectives?” “Question 9: Please provide evidence to show if there are other cost savings which small EG drive in comparison to larger (over 100MW) EG on the distribution system. Question 10: Is there other evidence that payment above avoided GSP/generation residual would better facilitate the applicable objectives?”
“However, one thing that is treated differently is embedded generation when it is treated as negative demand. Instead of being scaled, removing the generators capacity from the demand (effectively netting off their output with the demand from the area) will have a full, unscaled impact on the system, so in an area where demand reduction or generation can reduce the MWkm on the system, EG (when treated as negative demand) has a bigger positive impact on the system because that demand reduction “goes further” than the corresponding generation increase which is scaled if that same EG was treated as demand. In an area where demand reduction or additional generation increases the MWkm on the system, the impact of the EG would again be greater as unscaled. Effectively this is as much an administrative choice as anything but it is important to note that it is correct to state that EG is different in the SQSS. All this means that EG does currently, when treated as negative demand rather than generation (i.e. when its capacity is subtracted from the demand rather than its capacity used to feed into the generation locational tariff models), appear different than other generation. We have argued, and still stand by the claim that embedded generation has the same impact on the transmission system, and that it is the differential treatment that leads to the different result.”
“Our final assessment is that avoided GSP costs are the only benefits to the transmission system that have been robustly demonstrated to flow from smaller EG. A value of ‘x’ equivalent to avoided GSP costs would reduce the TDR payment to one which reflects long run cost savings achievable on the system from the reduced need to reinforce the points where the distribution system meets the transmissions system.”
“4.17. When treated as negative demand rather than generation, EG is not scaled by a scaling factor (as set out in the SQSS) as other generation would be. This means that removing the generators’ capacity from demand by netting off their output with the demand from the area will have a full, unscaled impact on the system. This can have a bigger impact on the modelled system because that demand reduction “goes further” than the corresponding generation increase, as it is not scaled. We disagree this is evidence of EG’s benefits, and note that it is no different than other generation. It is the differential treatment via the model that leads to the different result. 4.18. The locational charges have a broad relationship with the investment needs that underpin the system and are defined in the SQSS. The SQSS is not concerned with how residual costs should be recovered or charged. These should be recovered on economic principles in a way that reduces distortions.”
“4.26 It was also noted that load-related volume drivers within RIIO provide £/kW values for the cost of infrastructure build. Some respondents have suggested the embedded generators can prevent the requirement for these transmission upgrades, therefore, they should be paid an annuitized value of those infrastructure upgrade costs. 4.27 We would note that while the TOs, so far, have outperformed their load-related volume drivers, having not built the level of generation/demand connections forecast in their RIIO baseline, we are only 3 years into the price control and it is difficult to link the underspend directly with increased embedded generation. We therefore think that there is not currently sufficient evidence of a direct causative link between embedded generation and reduced expenditure on transmission assets beyond that of the GSP infrastructure savings.”
“WACM4 leads to a consumer saving in the years to 2024 of£2.2bn , and£7.5bn in the years to 2034.”
“If, hypothetically, all generators were embedded and matched to the local demand they are serving, there would be no need for the [transmission network], and hence the costs of the transmission network would be zero. More realistically, given that [transmission-connected generation] was providing 87% of peak demand based on the most recent data available, if there were no [embedded generation] then the [transmission network] would have to be commensurably larger.”
“The two-stage process by which courts in discrimination cases distinguish between comparability and objective justification is a useful tool of analysis and probably indispensable in dealing with allegations of discrimination on ground of gender, race or other personal characteristics. More generally, a rigid distinction between the two stages was implicit in the four-stage test proposed by Brooke LJ in Wandsworth London Borough Council v Michalak[2003] 1 WLR 617 , para 20, for cases arising underarticle 14 of the European Convention on Human Rights . But a tool of analysis should not be transformed into a rule of law. As Lord Hoffmann pointed out in R (Carson) v Secretary of State for Work and Pensions[2006] 1 AC 173 , paras 29-31, the question whether two situations are comparable will often overlap with the question whether the distinction is objectively justifiable: “If an “analogous situation”… means that the two cases are not relevantly different (no two cases will ever be exactly the same) then a relevant difference may be the justification for the difference in treatment … [T]his division of the reasoning into two stages is artificial. People don't think that way. There is a single question: is there enough of a relevant difference between X and Y to justify different treatment? … [T]he invocation of the ‘rational and fair-minded person’ (who is, of course, the judge) suggests that the decision as to whether the differences are sufficient to justify a difference in treatment will always be a matter for the judge.”” “If an “analogous situation”… means that the two cases are not relevantly different (no two cases will ever be exactly the same) then a relevant difference may be the justification for the difference in treatment … [T]his division of the reasoning into two stages is artificial. People don't think that way. There is a single question: is there enough of a relevant difference between X and Y to justify different treatment? … [T]he invocation of the ‘rational and fair-minded person’ (who is, of course, the judge) suggests that the decision as to whether the differences are sufficient to justify a difference in treatment will always be a matter for the judge.””