DCUSA DCP 137 Consultation Responses – Collated
Contents
1. competition however it could also been seen as a barrier to connecting generation General Objective Three Yes a common model used by every DNO based upon a common methodology will enable compliance with distribution licenses but could result in inefficient disproportionate costs being incurred to manage a few customers UKPN Yes we consider that charging objective 3 is better met with this proposal Noted Good Energy a We consider the proposal is detrimental to CDCM Objective 1 and General Objective 3 because e the introduction of locational tariffs for generation but not for demand discriminates unfairly against generators e it is an undue complication of the current CDCM which is unwarranted bearing in mind o the issues it creates for suppliers mentioned in b below in forecasting of generation charges and their increased volatility o the number of generation dominated areas at a national level was reported by the MIG GDA Sub group to be less than 5 and is still shown in this change proposal to be less than 5 having grown by only half of 1 over 2 years b We consider the proposal is detrimental to CDCM Objective 2 and General Objective 2 because e it would become very difficult for suppliers to forecast generation charges as they would not know i when a primary is likely to move between the charging bands or ii which primary a generator was connected to when they contracted with the g2. date Noted DNOs have an obligation to review available and DNO specific however as RIIO ED1 reporting tools are better understood there the charging methodologies if better data may be more appropriate data sources becomes available UKPN Yes we agree that this is the best source of available data Additionally the LTDS is available in Noted the public domain Good Energy We are not aware of any alternative sources to use but question the suitability of the Long Noted Term Development Statement as a data source due to its lack of accuracy RWE No comments Noted SP Yes especially as this provides a consistent approach to the calculation Noted Distribution amp SP Manweb WPD Yes Noted GTC We need to be convinced that such statements contain meaningful and robust information The Working Group noted the comment The Company 4 July 2014 Our experience is that this is not always the case Question Seven The generation growth was previously based on the DCPR5 Forecast Business Planning Questionnaire assumptions The Working Group is now proposing to update the generation growth using RIIO ED1 business plan growth forecasts used to calculate the timescales for generation dominance of each substation Do you believe that there are any alternative sources for this Page 10 of 23 LTDS is dynamic and will change as the DNO networks are developed DNOs welcome identification of areas where the respondee believes there a
3. due to the fact that the available source data can change This approach allows DNOs to use the best available data The Generation Dominated Areas Working Procedure captures the approach for calculating the forecast and will form the 4 July 2014 Page 7 of 23 v1 0 DCUSA Consultation DCP 137 Question Five Do you have any comments on the attached blank CDCM EDCM and ARP models basis for what is included with the CDCM User Manual The Working Group notes that the CDCM User Manual is maintained by the DCMF MIG Working Group Comments CLP No comment Noted Envirogas ENWL We have populated the CDCM and EDCM models and are happy they correctly implement the The Working Group noted the comments change proposal We have populated the Annual Review Pack and have the following comments Sheet CDCM Forecast Data e Cells G24 J29 and G256 J264 should be coloured dark blue representing that 15 months notice is required e Rows 83 and 102 include the HVS tariff which should be removed e Rows 109 111 112 amp 114 shouldn t be coloured dark blue Sheet Table1 e Row 7 dates should be linked to row 11 in CDCM forecast data tab e Input cells should be coloured light blue Sheet Smoothed Input details e Table 1041 coincidence factors and load factors remove HVS e Formula in B1 returns an error not sure why Volume Forecasts e Remove HVS to match CDCM input table Calculation sheets e H
4. methodology it does not improve the methodology The change does not encourage competition General Objective 2 This does not result in a cost reflective charging methodology Charging Objective 3 as it is based upon forecasts A generator providing near perfect support for the network at about The Working Group noted that it had previously discussed these topics against earlier responses The use of forecasts is part and parcel of the 4 July 2014 Page 18 of 23 v1 0 DCUSA Consultation DCP 137 the point of equilibrium is penalised on the basis of reinforcement that may be needed and paid for due to the introduction of an incremental generator at the primary substation It would be more cost reflective if based upon the actual position and actual data on an annual basis We do not believe that it results in less expenditure by the DNO or more efficient networks General Objectives 1 and 4 The ongoing GDUOS credits are generally not a predominant factor in a distributed generator s location decision such ongoing income costs are not well publicised by the DNO when requesting a connection offer Of far more relevance is the availability and cost of land ongoing fuel and labour planning permission and the capital cost of a network connection Neither do we believe that it satisfies Charging Methodology 4 as it takes account of forecasts rather than actual developments charging methodologies and consider
5. not identified as generation dominated then normal HV generation charges will apply 4 July 2014 Page 1 of 23 v1 0 DCUSA Consultation DCP 137 Company Question Two Are you supportive of the principles established by this proposal The Working Group noted all respondents understood the intent of the CP Working Group Comments CLP Envirogas No The justification for GDUOS credits is that generation capacity allows demand reinforcement to be deferred specifically its presence allows more demand to be connected to the primary substation without additional reinforcement expenditure If incremental high voltage connected generation causes the primary substation to require reinforcement in our opinion it is the incremental generation that should be discouraged This is already affected via the significant upfront capital connection charge to be paid by the new generator to the DNO Accordingly there is already a significant and direct charging signal in place to discourage high voltage generation from connecting or increasing capacity where doing so requires reinforcement of the primary substation and associated expenditure We would also point out having requested new generation connection offers that the only cost signal received is that of the upfront capital connection cost The ongoing GDUOS credit or charge is not included so in this regard it does not operate as a signal to those generators t
6. that the issue highlighted while it is an issue in its own right is not the problem that the Generation Dominated Areas proposal is trying to solve 4 July 2014 Page 2 of 23 v1 0 DCUSA Consultation DCP 137 primary substation Once connected a generator cannot simply relocate to another primary substation In this context any locational signal needs to be aimed at potential new generation rather than established generators Accordingly potential generation should be provided with upfront capital connection cost and GDUOS pricing signals which encourage appropriate locational decisions in support of efficient and effective network management Further basing any change in current GDUOS credits on forecast data is not cost reflective as it reduces credits in a period where existing generators provide actual network support Such signals must be aimed at planned new generation in line with and reflective of the cost implications associated with the locational decision of those whose contemplated actions are forecast to change the current efficiency and balance of the distribution system We believe that GDUOS credits should be maintained for existing generators up to the point where generation does in fact dominate based upon actual data Given that DNOs will check primary substation data on an annual basis per paragraph 7 16 the decision on whether a primary substation is demand or generator dominated can be made annually
7. the methodologies and assumptions used are not clear or readily available for independent scrutiny An independent growth forecast by Ofgem could be a better approach providing a consistent and more transparent methodology for across the UK This would be especially important if actual charges are based on the forecasts but would be less so if the forecasts are used as an indicative price signal RIIO ED1 analysis on the take up of low carbon technologies appeared to have heavily focused on LV technologies which seems to be less relevant to the question of whether HV connections should be receiving credits The DNO forecasts are based on the best available data at the time taking into account government forecasts and planned policy The current source data for the DNO forecasts is reviewed by Ofgem as part of the price control mechanism As previously stated LV generation growth and subsequent net demand reduction is likely to be a significant factor in generation dominated areas SP Distribution amp SP Manweb No this seems to be the most appropriate data to use Noted WPD No Noted 4 July 2014 Page 11 of 23 v1 0 DCUSA Consultation DCP 137 GTC Company We are not aware of any credible sources Growth in generation will in large part be driven by government policy and incentives Question Eight The current methodology uses the size of the installed generation plant The W
8. to monitor the situation over the next few years domination across the DNO areas however it is not in the remit of the Working Group to quantify by how much the DCUSA Objectives are better facilitated but rather to determine solely whether or not they are better facilitated The Working Group assess that the implementation costs are smaller than the benefits that will be derived UKPN Yes we are supportive of improving the cost reflectivity of the methodology where it is cost efficient to do so Noted Good Energy No it discriminates unfairly against generators by proposing locational DUOS tariffs for generators and not for demand This does not seem to recognise that the future progression of networks needs to manage demand and generation as equal customers The Working Group noted that this Change Proposal is about the implementation of locational credits and not about applying locational charges The group does not believe that the CP is discrimatory as it is seeking to remove credits where use is seen to increase the need to potentially reinforce the network Demand users are currently seen as potentially needing to increase network investment RWE Generators on the HV and LV network reduce the need for network reinforcement by offsetting local demand and the current methodology of awarding them credits is cost reflective and should prevail The DCP137 proposal to remove credits from HV generators conn
9. using actual data There is no need to use inaccurate forecasts What would also be a useful locational signal for existing and potential generators would be information on the current balance between demand and generation at a primary substation the likely future change in that balance and speed of such change In summary we do not support the proposal which reduces GDUOS credits for existing generators in periods when they are supporting the networks and thereby reducing costs when such a reduction is based on something which may or may not happen in the future using long range forecasts which are likely to be inaccurate and will certainly be wrong if the GDUOS charging signals work for incremental generation ENWL Yes Noted SSE Power Yes Noted Distribution NPG Yes we are supportive of the principle that generators should not be incentivised to connect The Working Group are progressing the at a primary where that primary is close to becoming generation dominated and in need of reinforcement However we do not think the penetration of Generation Dominated Areas currently or forecast is sufficient to warrant this change to be progressed at this time and feel that it proposal on whether it better meets the DCUSA Objectives The Working Group noted that at this stage there is predicted to be little generation 4 July 2014 Page 3 of 23 v1 0 DCUSA Consultation DCP 137 would be more prudent
10. DCUSA Consultation DCP 137 DCUSA DCP 137 Consultation Responses Collated Comments to what should apply where a DNO network is generation dominant but the IDNO network is not and vice versa Who determines what charge should apply IDNO or DNO Company Question One Do you understand the intent of the CP Working Group Comments CLP Yes Noted Envirogas ENWL Yes Noted SSE Power Yes Noted Distribution NPG Yes we understand that it is not prudent to pay a credit to HV generators connected at a Noted specific primary which is generation dominated where the increase in generation will actually incur a cost to the DNO the reinforcement of the primary UKPN Yes Noted Good Energy Yes Noted RWE Yes the intent of the CP is clear Noted SP Yes we understand the intent of the CP Noted Distribution amp SP Manweb WPD Yes Noted GTC We understand the intent of the proposal at the high level context However it is unclear as The Working Group noted that the concept under DCP 137 is that the DNO is applying charges for the use of their network Information on the generation dominated areas will be included within the LC14 charging statement The information will list the primary substation along with HV generation connections and IDNO connections It will be for the IDNO to reflect the appropriate charge in their network area for any HV generation that they may have connected If a network is
11. IDNO areas in the short term In the longer term the currently ongoing settlement reform work may mean 4 July 2014 Page 13 of 23 DCUSA Consultation DCP 137 that the number of LLFCs available is removed as an issue OD took an action to check on what is being done within other working groups in terms of this issue A BSC change would need to be brought forward to introduce additional LLFCs It was observed that as it would currently stand it is likely that the costs of implementing the BSC Change would outweigh the benefit of introducing the generation dominated area proposal UKPN We do not foresee any problems with the additional tariffs Noted Good Energy We have previously experienced difficulties with the application of LLFCs to generators and Noted have had to bear unexpected additional costs when LLFCs have been corrected retrospectively after monthly invoices have been settled This will be even more important to an embedded generator claiming a FIT CFD as their payment will be based on loss adjusted export A response to the previous consultation indicated that some DNOs would be unable to accommodate the additional number of LLFs required RWE No comment Noted SP No Noted Distribution amp SP Manweb WPD No Noted GTC As an LDNO we operate over 14 GSP groups with only 999 LLFCs available We are not sure The Working Group noted that in the short whether we would need to replica
12. and this change relies upon suppliers passing on this change in charge to the based on whether it better meets the DCUSA amp SP customer so the customer received the locational cost signalling and incentive the customer objectives Manweb to efficiently use the network However this may become increasingly important as the networks develops overtime WPD No Noted 4 July 2014 Page 22 of 23 DCUSA Consultation DCP 137 GTC No comment Noted 4 July 2014 Page 23 of 23 v1 0
13. at a generator that is forecast to be connected driving efficient use of the network to a generator dominated primary substation in 5 or 7 years should face a reduction in GDUOS credits today and The purpose of the 2 5 5 7 5 and ten year Given the annual review of charges there is no reason that an annual forecast should not be timeframe is to provide a staged signal and used when the assumptions of incremental generation could be validated against live avoid a step change in the application of connection offers credits ENWL Yes we agree that a ten year time horizon is a suitable time period to assess the likelihood Noted that a primary substation is likely to become generation dominated This is also consistent with the approach adopted in the Frontier report SSE Power Yes Noted Distribution NPG Yes we agree with the ten year time horizon and that having four time periods seems to be Noted appropriate 4 July 2014 Page 6 of 23 DCUSA Consultation DCP 137 UKPN Yes we agree with the ten year horizon and how it has been split This provides a pragmatic Noted approach that enables clear pricing steps over a reasonable planning horizon Good Energy We do not agree with the ten year time horizon and how it has been split because we do not Noted support the introduction of locational DUoS tariffs for generators RWE A ten year time horizon for forecasts is long especially when looking a range of techn
14. dded networks in other DNO areas spare LLFCs may be Noted Distribution lacking NPG As a consequence of the new tariffs there will also be new LLFCs created and it will be The Working Group observed that other necessary to migrate to a new LLFC over time as primary substations move from low GDA medium GDA high GDA Ensuring that customers are migrated correctly when the threshold is reached may be problematic especially as customers will lose credits at 2 5 years and 7 5 years The number of LLFCs available in settlements is known to be an issue 999 per licence particularly for IDNOs Consideration needs to be given to how this will be addressed if there are several changes approved which require new LLFCs DCP 179 is currently under development and will require DNOS to create new LLFCs The working group should consider an RFI to ensure DNOs have sufficient available LLFCs DCUSA DCPs are resulting in additional LLFCs needing to be used and the issue is likely to become increasingly problematic over time The number of LLFCs available may need to be addressed by another group With regards to DCP 137 the impact is unlikely to materialise in the short term as although six new DNO tariffs will be introduced it is about whether there are any HV customers on IDNO tariffs connected to a Generation Dominated Area It is unlikely that there will be thirty six i e all IDNO tariff combinations of these types of customer in any
15. e proposed legal text other than those made in response to Noted other questions below RWE No comments Noted 4 July 2014 Page 5 of 23 v1 0 DCUSA Consultation DCP 137 SP None Noted Distribution amp SP Manweb WPD No Noted GTC We do not think the legal text sets out fully how arrangements apply in respect of The Working Group will detail the Company downstream embedded networks which may or may not inject energy onto the upstream system We cannot support the current drafting Question Four Do you agree with the ten year time horizon and how it has been split If not please provide additional details application of generation dominated area tariffs in their LC14 statement in line with the detail provided on the other DUoS tariffs Please see the response to question 1 Working Group Comments CLP Firstly we believe that any changes to GDUOS credits should be considered annually and The Working Group observed that the Envirogas based upon actual data as set out in the response to question 2 and not forecasts DCUSA Charging Methodologies are If a forecast period is to be used we think 10 years is too long for the following reasons currently based on forecasting long run costs i The longer the time frame the more inaccurate it becomes and and not on actual accounts based costs The therefore less cost reflective purpose of this is to provide a signal for ii We do not believe th
16. e that there is sufficient time for those affected to alter their revenue forecasts UKPN The proposed implementation date is acceptable Noted Good Energy No if it is approved implementation should be deferred until 1 April 16 at the earliest to give Noted industry participants and generators more notice of the change and to facilitate migration of generators to new LLFCs well before implementation We have previously experienced 4 July 2014 Page 16 of 23 DCUSA Consultation DCP 137 difficulties with the application of LLFCs to generators and have had to bear unexpected additional costs when LLFCs have been corrected retrospectively after monthly invoices have been settled RWE There needs to be sufficient time to communicate the change to generation customers and Noted for them to factor the change in credits in to annual business plans SP Yes this impact of this change is that some generators will see a reduction in their credits Noted Distribution but given these credits are for supporting the network it is more appropriate to ensure that amp SP this change is in place as soon as possible to improve cost reflectivity Manweb WPD No the amount of extra working in initially setting this would mean implementing this for Noted April 2015 would be impractical and it should be April 2016 at the earliest or April 2017 if DCP 178 is approved GTC We do not support the change But if it was ap
17. ected to primary substations that are generator dominated is also fair given the rationale that such generators do not reduce network reinforcement need The assessment methodology for determining whether a primary substation is currently generation dominated makes sense Reviewing the status of primary substations on an annual basis is also supported Basing the level of entitlement on forecasts is more contentious The proposed approach to setting credits depends heavily on speculation by DNOs about future levels of demand and generation over the next 10 years While giving new connection applicants an indication of The Working Group noted that the respondent s first paragraph is supportive With regards to the second and third paragraphs the Working Group noted that DNO forecasts are not speculative but rather are based on documented assumptions using the best available published data at that time Credits are paid based on forecasts that generators will offset the need for demand reinforcement If DNOs did not use forecasts 4 July 2014 Page 4 of 23 v1 0 DCUSA Consultation DCP 137 future network cost changes is useful and can act as the desired price signal in itself actually charging based on forecasts does not appear strictly cost reflective One issue to be addressed if forecasts are used is that some form of incentive penalty measure needs to be in place for the DNO s to make accurate forecasts The work
18. ed good business practice ENWL We believe this change proposal will result in more cost reflective charges for generators and reduce the incentive on generators to locate in areas where they may drive reinforcement Consequently this CP better meets charging objectives 3 and 4 and general objective 1 Noted SSE Power Distribution Yes Noted NPG Charging Objective One Yes a common methodology will result in consistency and also transparency of process Charging Objective Two Yes The commonality of approach towards HV generators will assist in the facilitation of competition however it could also been seen as a barrier to connecting generation Charging Objective Three Yes as there will not be credits given to generators who have actually caused a cost to be incurred by the DNO but could result in inefficient disproportionate costs being incurred to manage a few customers Charging Objective Four Yes a review of generation growth and load growth carried out on a yearly basis will ensure that changes in the actual license area will be captured in the model General Objective One Yes this new approach will ensure that credits are not given to generators who have caused the DNO to incur a cost General Objective Two Yes commonality and transparency will assist in the facilitation of Noted 4 July 2014 Page 19 of 23 v1 0 DCUSA Consultation DCP 137
19. ed elsewhere in the industry However each DNO should Noted also review the actual generation growth and if there is a significant variance from this then a separate DCP should be raised to vary the 1 to an average of all 14 licence areas and this should be reviewed yearly UKPN We believe that it is appropriate to continue to use the notional 1 demand growth rate Noted This is consistent with the growth rate used for other charging purposes Good Energy No if the generation growth rate used is for the ED1 period the demand growth rate used should also be for the ED1 period If a long term demand growth of 1 is used the generation growth rate should also be a long term view There must be consistency between the demand and generation growth rates The Working Group noted that generation growth reflects new technology far more than demand growth does therefore the Working Group feels that it is appropriate to use long term demand growth against more recent forecasts of generation growth RWE Under RIIO ED1 DNOs have worked up forecasts of the take up of demand technologies such See above comment as electric vehicles It appears odd that while generation is based on forecast models demand growth is based on an arbitrary status quo fixed figure SP As the demand growth rate of 1 is used in EDCM this should be consistent throughout all Noted Distribution the charging methodologies From applying DNO specific d
20. emand growth rates and 4 July 2014 Page 15 of 23 DCUSA Consultation DCP 137 amp SP comparing the outputs to the 1 growth rate it appears that this input has minimal impact Manweb on the calculation WPD Yes Noted GTC No comment Noted Company Question Eleven If DCP 137 is approved is the proposed implementation date of 1 April 2015 acceptable If not please provide your preferred implementation date and supporting rationale Working Group Comments It is the view of the Working Group that the target implementation date of April 2015 is achievable but note there is a potential issue with the settlement systems and the restriction of Line Loss Factor Classes the impact of which needs to be understood The Working Group noted that there may be an interaction with DCP 178 regarding the 15 month notice period that DCP 178 seeks to introduce CLP We do not think that DCP 137 should be approved in its current form The Working Group noted the respondent s Envirogas view ENWL We support the implementation date of April 2015 Noted SSE Power Yes Noted Distribution NPG This date is achievable provided a decision is received in a timely manner to allow inclusion in Noted indicative charges in December i e by the end of October 2014 However it may be more prudent to move this to April 2016 to allow for the change to be communicated to customers in advance to ensur
21. enerator e tariffs would become more volatile due to generators being switched between charging bands year on year and with potentially little warning c We also believe the proposal is detrimental to General Objective 1 because it would be difficult for DNOs to give accurate indications of which tariff band would apply to a generator If they received requests for the applicable tariff band from several generators in a year and It was noted that comments around discrimination had been addressed against an earlier consultation response The Working Group appreciates that the current status of generation dominated areas may be seen as being immaterial but the Working Group feel that the change will better meet the DCUSA objectives in the round 4 July 2014 Page 20 of 23 v1 0 DCUSA Consultation DCP 137 all of the connections proceeded it could move the primary into a higher generation dominance band If the DNO treated each request in isolation it could understate the applicable charges however if they assumed all enquiries would go ahead then it could deter generation connections unnecessarily We understand this issue has already been encountered with the EDCM RWE It is not clear that the statement that charges can be reasonably expected to be incurred by The reason that a long term forecast is being DNOs can be supported when the charging under this proposal would be based on l
22. eration output are captured in the model UKPN Yes we agree with this change in the legal text as it will allow the DNO to allow for contracted Noted generation capacity that is not being exported onto the network Good Energy We agree this is an improvement to the previously proposed legal text but consider it should refer to the observed maximum generation export rather than the observed maximum generation output The group discussed this comment and suggested that rather than using the word export it should be exported RWE No comment Noted SP Yes this will help ensure that customers generation tariffs reflect what is actually Noted Distribution happening on the network and not what could happen amp SP 4 July 2014 Page 12 of 23 DCUSA Consultation DCP 137 Manweb WPD Yes Noted GTC No comment Noted Company Question Nine The CP introduces six new CDCM tariffs and thirty six LDNO discounted tariffs These additional tariffs could impact the use of other industry data and systems for example line loss factor classes used in settlement Do you foresee any issues with the implementation of the additional tariffs Working Group Comments CLP No comment Noted Envirogas ENWL We do not see any implementation issues with the introduction of this change proposal for Noted Electricity North West SSE Power Where DNO IDNOs have embe
23. hat will disturb the equilibrium The proposal not only ignores this predominant signal of upfront charging it takes a currently balanced demand generation position for a primary substation forecast to swing to a generator dominated position within 2 years and encourages additional demand and less generation through a notional cost signal In this proposal any existing generator who is forecast within say 2 years to be connected to a generator dominated primary substation is by definition contributing significantly to distribution network efficiency However the proposal is to discourage and penalise such a generator by removing or reducing its GDUoS credits based upon forecast data and the possible actions of an unidentified notional new generator We believe that the existing generator should be rewarded and encouraged up until the point it is no longer benefitting the network The proposal is therefore perverse in that it would not reward efficiencies rather it would discourage them Further the majority of demand is generally connected at low voltage and sees neither a step change in DUoS charges nor any other change in charges if reinforcement is carried out at the The Working Group observed that generation growth can also be caused by LV generation growth and by reductions in net demand at both LV and HV rather than solely by increases in localised HV generation caused by new HV generation connections The Working Group believe
24. ide calculation sheets or move to one sheet as used in DCP123 Sheets Y to Y 4 Latest forecast of CDCM revenue cell F50 should point to row 47 within the Table1 tab This will allow Suppliers to paste in the latest DCP66 submission but still get the actual prices and will feed them back to the modelling support consultant 4 July 2014 Page 8 of 23 DCUSA Consultation DCP 137 where they have already been issued SSE Power No Noted Distribution NPG Not at this time Noted UKPN No Noted Good Energy No Noted RWE No comments Noted SP No Noted Distribution amp SP Manweb WPD No Noted GTC Not reviewed Noted Company CLP Envirogas Question Six The current methodology uses the latest Long Term Development Statement as the data source used for identifying generation dominated areas The Working Group still believes that this is the best source of available data do you agree If not what alternative sources do you believe should be used This is a difficult question to answer without reading each DNO s Long Term Development Statement these are not all readily available on line That said we do not believe that the Long Term Development Statement is the best source of information it does not appear and does not claim to be fit for the purpose of determining GDUOS credits Using WPD s Long Term Development Statement as an illustration i The statement is co
25. ing group have concluded that no refunds of credits should be made if forecast state of generator dominance does not materialise In our view without an appropriate measure in place there is a driver for the DNO to forecast higher levels of generator dominance then these credits could not be paid It was noted that the respondent assumes that DNOs can benefit from the reduction in credits paid This is not the case as DNOs are neutral to the benefit credit that is paid The credits benefits are paid by demand users in return for the forecasts of the reduction in costs that will be obtained through reducing the need for demand reinforcement SP Yes we are supportive of the principle of the CP Noted Distribution amp SP Manweb WPD Yes Noted GTC In principle However we have difficulty in understanding how this will work in practice for Please see response to question 1 embedded networks which themselves may or may not be generation dominant i e there is unlikely to be net export from IDNO network to DNO s upstream network Company Question Three Do you have any comments on the proposed legal text Working Group Comments CLP No comment on the legal text Noted Envirogas ENWL We have reviewed the legal text and are happy that it correctly implements the change Noted proposal SSE Power No Noted Distribution NPG Not at this time Noted UKPN No Noted Good Energy We have no comments on th
26. mpiled in accordance with Licence condition 25 and ii Due to the volume of data and the speed with which it can become outdated data on the 11kV and LV systems has not been included in the statement We believe that actual data can and should be used for assessing whether a primary substation is moving towards and is actually generator dominated supplemented by active connection requests Working Group Comments The Working Group still believe that the LTDS is the best source of information Long Term Development Statements are readily available as required under DNOs licence conditions The group believe that the example given is taken out of context about it not being fit for purpose The illustration provided in the response is more about the volume of data and the change that would need to be provided for the HV and LV systems rather than the data that is provided in the LTDS statement 4 July 2014 Page 9 of 23 DCUSA Consultation DCP 137 As stated previously if charges were based on actual data then credits would not be provided in the first place ENWL We agree that the LTDS is the most appropriate source of data and is transparent to Noted customers SSE Power Agree that the LTDS is the best source of data currently available and is transparent Noted Distribution NPG We agree that the LTDS is currently the best source of data as it is the most up to
27. nd uncertainty to the CDCM may cease to be generation dominated because of the affect that it had been previously classified as generation dominated and this causing the desired effect or reducing generation It was observed that refunds where a substation ceases to be generation dominated will not be applicable This is 4 July 2014 Page 17 of 23 DCUSA Consultation DCP 137 charging model which currently has average charges for most customers and introduces semi site specific tariffs for this group of customers It is also potentially at odds with the current desire for simpler more transparent predictable charges We believe there is a real risk of customers changing tariffs year on year depending on whether or not the reinforcement actually goes ahead and it has the potential to creates some significant billing refund issues between DNOs Suppliers and end customers because the reason you are paying credits is to remove the need to reinforce Charges are based on creating incentives to behave in ways that will reduce network costs using forward looking approach UKPN We have not identified any unintended consequences of this proposal that have not been addressed during the development of the solution Noted Good Energy If any DNO is unable to accommodate the additional number of LLFCs required without an increase in their total number of LLFCs to above 999 there could be far reaching unintended co
28. nsequences of the proposal Noted See earlier response regarding LLFCs RWE No comment Noted SP This change proposal will also introduce additional complexity thus reducing the transparency The Working Group noted the first two Distribution of the calculated generation tariffs paragraphs of this response ee b The tariffs are also dependant on forecast data that may or may not materialise there could With regards to the third paragraph the ANNE be an increase in volatility of the charges year on year given DNOs will be required to review Working Group notes that this could be a the substations list annually consequence of the methodology but does Some customers may find that the primary substation they are connected to had been not believe that 1 postive OF negative A od i ar its effect in that it reflects conditions at the identified as likely to become generation dominated in one year receiving a reduced credit ers then the forecast may change the following year where this is no longer the case this could Pen er lps aere leave some customers feeling unfairly charge and visa versa WPD No Noted GTC See above Noted Company Question Thirteen Do you consider that the proposal better facilitates the DCUSA objectives Working Group Comments CLP Envirogas We do not believe that this change discharges Charging Objective 1 and General Objective 3 Whilst it is a review of the charging
29. ologies with varied deployment lead times ranging from a few months to a couple of years and connections that are heavily dependent on changeable Government policy regarding subsidies While giving new connection applicants an indication of future network cost changes is useful and should form part of the proposal actually charging based on forecasts should not occur as it is not cost reflective The reason a ten year timeframe was chosen is because it provides a reasonable staged approach rather than a step change It also gives generators a view of what will happen longer term and thus enables them to prepare SP Distribution amp SP Manweb Yes this time horizon and split seem to be the most appropriate Noted WPD Yes Noted GTC Judgements based on a 10 year horizon would appear to be open to subjective judgement in many instances We are therefore not convinced that the legal text sets out the criteria required to ensure such judgement is robust The values proposed have been set out in the consultation document and DNOs have followed a consistent approach in setting these forecast values The approach for calculating the forecast will be set out in the CDCM User Manual should this CP be approved This is consistent with how other forecasts are derived within the methodology The Working Group do not believe that it is appropriate to hard code in DCUSA the method for calculating the forecast
30. on DCUSA Charging Methodologies are offers currently based on forecasting long run costs and not on actual accounts based costs The purpose of this is to provide a signal for driving efficient use of the network 4 July 2014 Page 21 of 23 v1 0 DCUSA Consultation DCP 137 ENWL No Noted SSE Power No Noted Distribution NPG Not at this time Noted UKPN We have not identified any Noted Good Energy There is no need for the proposal or the consideration of any alternative solutions bearing in mind that the number of generation dominated areas at a national level was reported by the MIG GDA Sub group to be less than 5 and is still shown in this change proposal to be less than 5 having grown by only half of 1 over 2 years It was noted that the CP must be assessed based on whether it better meets the DCUSA objectives RWE No comment Noted SP Not at this time Noted Distribution amp SP Manweb WPD No Noted GTC No comment Noted Company Question Fifteen Do you have any further comments Working Group Comments CLP No further comments Noted Envirogas ENWL No Noted SSE Power No Noted Distribution NPG Not at this time Noted UKPN No Noted Good Energy No Noted RWE No Noted SP We would like to note that the overall impact on the changes as a result of this change are It was noted that the CP must be assessed Distribution minimal
31. ong term used is that this removes the uncertainty forecasts with high uncertainty that short term forecasts would provide For example year on year growth would be a lot more uncertain SP Yes we agree with the working group s views that this proposal better facilitates Charging Noted Distribution Objective one amp four and General Objective three Sor The working group also it could be argued that this proposal may also reduce competition Manweb given that it adds further complexity to calculating and passing on the charge thus acting as a barrier to entry WPD This change improves how DNOs meet the General and Charging objectives by rewarding Noted customers generators that are supporting the network and reducing or removing that reward where that benefit is reduced or the generation is detrimental to the network i e it causes the need for reinforcement GTC We still remain to be convinced that this change is more economic and efficient and that it Noted will lead to more cost reflective charges and thereby better facilitate competition In particular we are not convinced that the impact on embedded networks has been fully considered and assessed e J e e e ee 4 a ere d 0 E 0 E 0 UY 0 o 0 O U DE e z e e e O UE 0 CLP The use of the actual generator demand balance on an annual basis in conjunction with The Working Group observed that the Envirogas publicised historic trends and movements together with accepted and open connecti
32. orking Group has identified that in some circumstances this can trigger a generation dominated area even though there is not HV export capacity at that primary It is felt that the methodology would be improved by using the observed maximum generation output Do you agree with the change to the legal text paragraph 146B of the legal text to enable this Noted The DNO forecasts are based on the best available data at the time taking into account government forecasts and planned policy Working Group Comments CLP Agreed but the difference between the installed and actual should be tracked as part of Noted Envirogas managing an efficient network ENWL Yes we agree with this amendment The current charging methodology means that HV Noted generators can maintain an export capacity without incurring a material charge and consequently have no incentive to reduce their Maximum Export Capacity even though they may not be using it Consequently it would be reasonable to remove any unused generation capacity from the calculation of whether a primary is generation dominated SSE Power Yes provided the observed data is readily available What is the process if this data is not Noted Distribution available NPG Yes we agree with this change to the legal text To keep the scenario realistic the historical Noted maximum generation output should be used however this should be revisited yearly to ensure that any increases in maximum gen
33. proved we may need to raise a change to Noted settlement systems to allow more than 999 LLFCs If this was the case we do not think the BSC and parties to the BSC would be able to accommodate such changes in such a short timescale The stress on the availability of LLFCs needs to be considered in junction with changes to bring PC5 8 customers into a new HH measurement class P300 in BSC Company Question Twelve Are there any unintended consequences of this proposal Working Group Comments CLP The creation of further uncertainty for distributed generators those already operating and Noted Envirogas those considering investment ENWL We are not aware of any unintended consequences of this change proposal Noted SSE Power Not currently aware of any Noted Distribution NPG As per paragraph 6 5 The Working Group also noted that refunds of credits should not be The Working Group noted that a substation paid in future years if it is established that the generation dominance of any primary substation did not materialise We note that the working group have suggested that no rebates will be given However it would not be fair or equitable for a generator at anon GDA primary that was never forecast to become GDA to receive credits conversely whilst a generator at a primary that was forecast to become GDA but never did would not receive credits nor would they receive a rebate This change introduces an additional level of complexity a
34. re inaccuracies Working Group Comments DCUSA Consultation DCP 137 information that would be preferable CLP We would prefer the use of actual data validated on an annual basis If a forecast must be See previously comments regarding use of Envirogas used there is no reason that an annual forecast incorporating assumptions of incremental actual data generation validated against accepted and open connection offers could not be used ENWL We believe that the growth rates assumed within the RIIO ED1 business plans are initially the Noted most appropriate source of this data However we note that generation growth rates at individual primary substations can vary from the overall average we therefore welcome the flexibility given by the legal text to amend the growth rate depending on the actual growth seen on the individual primary networks SSE Power Not aware of any better alternatives Noted Distribution NPG No we do not believe that there are any alternative sources at this time The most recently Noted available published data RIIO ED1 is appropriate to use and the data sources these are taken from are standard over all DNOs UKPN We are not aware of an alternative source of forecast that would be preferable Noted Good Energy We are not aware of any alternative sources to update the forecast generation growth Noted RWE DNO forecasts of generation growth have proven to be inaccurate in the past and
35. te all LLFCs In an extreme example we would need 42 36 term the group does not believe that all 6 X14 LLFCs This gives a total of 588 We do not have sufficient spare LLFCs to facilitate this LLFCs if any would need to be replicated 4 July 2014 Page 14 of 23 v1 0 DCUSA Consultation DCP 137 Company Therefore we cannot support this solution as being cost effective at this time Question Ten Do you agree that the demand growth rate of 1 should continue to be used If not how should this value be forecast However see note above regarding BSC changes Working Group Comments CLP We do not believe that forecast should be used we would prefer the use of actual data The Working Group has noted in previous Envirogas If forecasts are to be used then these should be a best estimate and there appears to be no comments about the use of actual data rationale for using a generic 1 we suggest using the growth forecasts provided by each DNO for its specific network area The 1 demand growth is an excepted long term demand growth used within the charging methodology and it reflects the rate of demand growth that has been seen in the longer term ENWL Yes this value is consistent with the assumption used within the EDCM and more Noted representative of the long term average SSE Power Yes This is a pragmatic approach It can be reviewed in the future Noted Distribution NPG Yes this is a sensible value and is us
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