Review of Analysis of Network Benefits from Smart Meter Message Flows

Transcription

1 Review of Analysis of Network Benefits from Smart Meter Message Flows (Including RIIO ED1 and ED2 phasing and categorisation of benefits) 1 st July 2013 Version 1.0 1

2 Page 2 of 15 Review of Analysis of Network Benefits from Smart Meter Message Flows Contents Page 1.0 Background Benefits in Context Scope of Review Summary of Further Research Summary of Findings Overall ED1 Summary 8 Tables (i) Benefits delivered by DNOs independently of other parties (based on SMETS2 functionality) 10 (ii) DSR benefits dependent upon Supplier-led ToU tariffs and load control / smart appliances 11 (iii) Total DNO cost-base impacting benefits (summary of tables (i) and (ii)) 12 (iv) Benefits no longer available due to changes in the Smart Meter specification 13 (v) Total network related benefits from Smart Meter message flows 14

3 Page 3 of Background In March 2012, ENA undertook an analysis of potential benefits from smart meter message flows in order to: Answer a number of specific questions from DECC s Smart Metering Implementation Programme Team relating to previously documented smart meter message flows specifically DECC s Analysis of network benefits from smart meter message flows: Data Request Table issued on 7 March 2012; and Provide an overall present value benefits analysis to support the case for specific aspects of smart meter functionality in particular functionality that would facilitate the management of electricity distribution networks. This review of benefits should be read in conjunction with the ENA March 2012 paper; the document can be downloaded from the ENA website here. Prior to publication, the final draft of the March 2012 paper was circulated to all DNOs seeking endorsement. Unqualified endorsement was received from 4 DNOs; qualified endorsement was received from SSE. WPD felt unable to endorse the analysis due to concerns over the inherent level of uncertainty regarding quantification of benefits. The March 2012 analysis necessarily incorporated numerous assumptions regarding future pressures on electricity distribution networks, particularly those relating to low carbon technologies and also regarding the potential to mitigate such pressures through influencing the quantum and shape of future electricity demand patterns which would for example depend on Suppliers introducing appropriate incentives through time of use (ToU) tariffs. Such assumptions were informed, in the broadest sense, by DECC s indicative 4 th Carbon budget scenarios for low carbon technologies but no detailed analysis of prospective residential or SME property load shape was undertaken at that time. The analysis also drew on the earlier published ENA / SEDG / Imperial College paper (Goron Strbac et al) - Benefits of Advanced Smart Metering for Demand Response based Control of Distribution Networks - which can also be downloaded from the ENA website here. The March 2012 paper identified numerous categories of potential benefits and in each case quantified these benefits in present value terms taking account of assumed take-up rates of low carbon technologies and the timing of availability of required smart metering volumes and functionality. The overall DCF study considered the period from 2015 to 2030 but took account of when benefits from the smart meter rollout would start to become available and the longevity of the benefit in each case (the rationale for assumed longevity of benefit is described in section 6 of the report). An overall potential present value of benefits of 1.292b was derived from the analysis. These benefits, if realised, would accrue to consumers in terms of: Avoided network investment, principally at the LV and 11kV network levels (consistent with the ENA / SEDG / Imperial College paper) 1 ; Reduced levels of LV and 11kV network losses (compared with a non-smart counterfactual) the costs (and hence benefits) of which would ultimately fall on (to) consumers; and In the case of quality of service benefits (which are relatively small in monetary terms), an assumed value based on customer willingness to pay data. From the March 2012 analysis it is clear that the increase in electrical energy distributed by networks, and the future daily load shape of residential and SME demand, will both be critical factors in determining the 1 note: no consideration was given to potential overlap with non-load related investment

4 Page 4 of 15 reinforcement pressures that electricity distribution networks will in future be subjected to as a result of low carbon transition. The March 2012 paper demonstrated that an ability to influence (either purely through tariff price incentives, or a combination of price incentives, smart appliances and direct load control) could have a major beneficial impact on peak demand driven reinforcement at LV and 11kV (including 11kV/LV transformation) levels 2. Similarly, peak smoothing (improving load factor) could have a major beneficial impact in terms of reduced variable losses. These two (related) benefit streams account for 1.004b of the 1.292b overall present value of benefits. A smaller, albeit still important, contribution to managing future peak demands identified by the analysis was that of Active Network Management (undertaken solely by DNOs but informed / enabled by smart meter data / functionality 3 ); the March 2012 study, looking out to 2030, derived savings with a present value of 136m. 2.0 Benefits in Context It should be emphasised that whilst the March 2012 analysis derived a present value of benefits as a component of an overall cost-benefits analysis, it did not in itself constitute a cost-benefits analysis since at that time the incremental costs of providing the necessary supporting functionality within the overall smart metering system (including the data management and communications systems) were unclear. Neither did the analysis seek to quantify the costs of providing or enhancing DNOs data management systems (including systems for aggregating hh consumption data). Nevertheless, should the derived present value of benefits of 1.292b (approx. 46 per meter) prove feasible, it would seem likely that a positive NPV of benefits (net of costs) could be derived, at least for some components of smart meter functionality. It is also important to understand the context of the study which was to evaluate those network benefits that could be leveraged from the smart meter programme under ideal market conditions and regulatory frameworks, assuming that all parties (including Suppliers and/or potential intermediaries, and not least consumers) are incentivised to behave logically (for example in terms of developing (Suppliers) and responding to (consumers) time-of-use tariffs). In particular, it should be noted that by far the majority of the financial benefit is delivered through actions to shift demand from peak and/or improve load factor (reducing peak relative to average demand) which in turn enables lower costs associated with network reinforcement and losses. In order that network losses are fully valued, these were considered from a whole system perspective (i.e. the whole system costs including generation of supplying network losses and incorporating a value ascribed to carbon) and valued at 60 per MWh in line with the proposed DPCR5 incentive rate 4. This is important in supporting the business case for smart meter functionality, since ultimately it is consumers who will fund the costs of smart metering and hence should benefit from savings in such whole system costs. 2 It is important to note that the study did not assume the above benefits to be dependent on DNOs alone providing (DUoS) price signals and/or exercising control over demand; rather it assumed that consumers and/or smart appliances would control demand and that synergies in benefits between Suppliers and DNOs would, at least under most weather/demand scenarios, lead to complementary energy and DUoS time-of-use price signals 3 For example: network load balancing, phase balancing, power factor control, and active voltage control 4 Ofgem subsequently took the decision not to activate the incentive for DPCR5

5 Page 5 of Scope of Review The purpose of this paper is to take stock of developments since the March 2012 paper (in particular with regard to SMETS2 functionality and the smart metering system security architecture) and provide a revised update of the deliverability of the benefits indicated by the March 2012 paper. The primary focus for the review is the derivation and quantification of those benefits which will impact DNOs cost bases. This is of particular importance to the RIIO ED1 Business Plans which DNOs will submit to Ofgem in July Hence the evaluation is in terms of ED1 and ED2 period benefits and expressed as real, non-discounted values rather than in present value terms. This paper draws on work recently commissioned by ENA with EA Technology Ltd (EATL), KEMA and Baringa Redpoint who were requested to revisit the derivation and quantum of the benefits detailed in the March 2012 paper. This latest review incorporates all information and analyses that has become available since the publication of the March 2012 paper; in particular: The more detailed analysis now available from DECC in terms of 4 th Carbon Budget scenarios (including projections for renewable DG technologies provided in February 2013); The more detailed analysis of future residential and SME load shape undertaken as part of the derivation of the Smart Grid Forum WS3 Transform Model; The conclusions drawn from the Smart Grid Forum WS3 Transform Model in terms of required levels of network investment over the ED1 and ED2 periods under DECC s 4 th Carbon Budget scenarios; and The implicit effects of the recession in reducing present demand levels and hence reducing the need for reinforcement expenditure in many parts of GB at the current time 5 (albeit the possible effects of recovery in terms of catch-up should not be dismissed); Certain network benefits are heavily dependent on parties other than DNOs for their delivery (in particular Suppliers and consumers); it is not within the gift of DNOs to enforce Suppliers to introduce ToU tariff incentives which would encourage peak demand shifting, nor do the restrictions on DNOs in terms of transmitting critical messages (such as load control actions) over the DCC network enable DNOs to directly undertake load control actions. Whilst the benefits are those associated with improved efficiency of distribution network operation and investment, not all of these benefits will be reflected in savings in DNOs costs (or increases in DNOs incomes or incentives). For example, customer service benefits, such as faster response to LV faults, are simply a monetised value ascribed to such benefits based on assumed customer willingness to pay criteria 6. Similarly, network losses savings (the single most significant benefit identified in the March 2012 paper) would accrue to DNOs only to the extent that an appropriately valued regulatory losses incentive was in place. As with DPCR5, no target-based losses incentive (such as that put in place for DPCR4) is planned for ED1 7. And whilst savings in reinforcement investment were taken as actual avoided costs, no IQI sharing of benefits (between DNOs and consumers) has been assumed; rather the implicit assumption is that these investment avoidance benefits are fully incorporated within DNOs ED1 business plan submissions. 5 Implicit because it is assumed that DNOs proposed ED1 and ED2 levels of 11kV and LV general and connections-driven network reinforcement will reflect this effect 6 Albeit in practice there would also be a small IIS benefit which would accrue directly to DNOs 7 Notwithstanding Ofgem s proposed licence condition and 32m discretionary reward

6 Page 6 of 15 Benefits that are no longer deliverable are identified and separated from those which (albeit dependent on other parties) remain achievable. For example, the current version of SMETS2 precludes the possibility of delivering the extreme voltage protection benefit (as the functionality is excluded) and the minimum IHD functionality does not support remote messaging. Whilst the monetised benefits in the March 2012 paper were presented in present value terms based on a 3.5% p.a. real discount rate (and taking account of when benefits would be expected to begin to flow; when some benefits might cease; and the variation over time of the quantum of certain benefits) these were not presented in terms of in-period benefits i.e. ED1 and ED2. In order to inform DNOs well justified business plans following the further guidance now published by Ofgem s March 2013 Strategy Paper, this latest review also provides an indication of the anticipated apportionment of benefits, in real (i.e. neither inflated nor discounted) terms, over the ED1 and ED2 periods Summary of Further Research In order to try and quantify the monetary benefits accruing to DNOs cost bases through Smart Meter technologies, EATL, KEMA and Baringa Redpoint were commissioned to undertake a review of the March 2012 ENA paper and an interim review of this paper produced by the ENA in March They were requested to re-examine and update the benefit assumptions and to include any additional areas that may have been omitted from the earlier work. EATL s work concentrated on the network investment benefits arising from the use of Smart Meter data and in particular from various levels of customer response to ToU tariffs. Their report can be found here. KEMA were requested to examine the spectrum of benefits including network faults, design processes, connections processes, reinforcement costs and active network management. Their report can be found here. Baringa Redpoint were requested to focus on the likely behaviour of Suppliers during the ED1 and ED2 periods and in particular the likely strength, format and benefits of ToU tariffs. Their report can be found here. 5.0 Summary of Findings KEMA and EATL each considered specified aspects of the benefits identified in the March 2012 report, reviewed the assumptions, and methodology and, where appropriate, applied their own assumptions and methodologies to form their view of benefits. Whilst Baringa Redpoint were not asked to review the value of the benefits, their analysis has been helpful in terms of the level of confidence that can be attributed to consumers responsiveness to ToU tariffs and the resulting impact on peak demand. 8 In the case of DSR-related benefits and network losses, such apportionment is extremely sensitive to assumptions regarding the take up rates of electric vehicles and heat pumps over the ED1 and ED2 periods

7 Page 7 of 15 Baring Redpoint and EATL have applied different approaches in their assessment of impact of ToU tariffs on peak demand and their respective results are not directly comparable. However, both indicate a material reduction in peak demand over the ED2 period but a much smaller benefit over ED1. In most cases KEMA and EATL s assessment of benefits is broadly consistent with those in the ENA March 2012 paper with one notable exception relating to the losses benefit. The assessment of the losses benefit in the ENA March 2012 paper was based on a number of assumptions relating to the increase in demand from Low Carbon Technologies, the proportion of overall losses occurring on DNO low voltage networks and the proportion of the potential load flattening benefits identified in the Imperial College work that could be achieved in practice. The assessment of the losses benefit assessed by EATL was derived from the Transform model and would have used different, albeit related, assumptions. These assumptions have resulted in a reduced level of peak load shifting associated with ToU tariffs and consequently lower losses benefit (network variable losses are proportional to the square of the current, so the effect of a reduced level of peak demand shifting is magnified). The most material assumptions when assessing the losses benefit are those relating to the extent to which Suppliers introduce ToU tariffs and the response of consumers to them. Whilst the difference in assessed losses benefit is material when compared with the other benefits this different needs to be set into context against the total GB losses value and their associated cost. Current GB losses are in the region of 17.5TWh pa which at 60/MWh equates to 1050m pa or 8400m in an eight year ED1 period (assuming no appreciable increase in network utilisation factors and no decrement to daily load factor over the eight year period). However, by 2030, under DECC's 4th Carbon Budget scenarios, electricity consumption could increase by as much as 19% compared with today due to electric vehicle and heat pump load. It follows that, especially taking account of the fact that network copper (variable) losses are proportional to the square of the current, a reasonable assumption is that distribution network losses could increase by as much as 7.5TWh pa (42%) to 25TWh pa by 2030, i.e. 1500m pa or in the region of 10,000m over an eight year period ED2 (the aggregate value over eight years will depend on the ramp-up rate over this period). Taking ENA's March 2012 saved losses benefit evaluation of 100m over ED1, at 60 per MWh this equates to a saving of 1.7TWh or just 1.2% of the estimated distribution network losses over the ED1 period. It follows that even under ENA's original evaluation, the assessed network losses benefit in ED1 and ED2 is relatively small when compared against the total cost of losses. The much smaller range of assessed network losses benefit in ED1 and ED2 as assessed by EATL is therefore extremely small when compared against the total cost of losses.

8 Page 8 of 15 Whilst the Baringa report does not comment on the impact on network losses of ToU tariffs, their modelling does show a significant reduction in winter peak day demand (around 5GW at the system level, and up to 7.9GW of domestic peak demand in 2031 compared with the BaU case) under all of their ToU scenarios. Further analysis by ENA indicates that a peak demand reduction of this magnitude (and even allowing for an equivalent level of demand to occur at off-peak times such that the overall level of energy consumed is constant) could result in a reduction in variable losses of around 3.5% 9 Given the large number of uncertainties particularly with the rate of demand growth associated with Low Carbon Technologies and DG growth, the phasing of the Smart Meter roll out plans and the response of consumers, it was not considered practicable to focus on a single benefit value per benefit category. Instead, a likely range of benefits was derived from the work of the consultants and the earlier work by ENA members. These results are presented below and disaggregated into 4 categories: Benefits impacting on DNOs cost bases which are deliverable by DNOs independently of other parties; Benefits impacting on DNOs cost bases which are dependent on the actions of Suppliers and consumers in particular relating to the introduction of and response to ToU tariffs; Benefits that do not impact on DNOs cost bases; and. Benefits no longer available due to limitations in smart metering equipment specifications (or security architecture). Each category of benefits is separately shown for the ED1 and ED2 periods and presented in real, nondiscounted terms 10. A brief description of the derivation of each benefit is provided. However, for a complete understanding, reference should be made to the papers detailed above. It will be noted that, in general, the benefits are skewed towards the ED2 period reflecting both the anticipated completion of the smart meter rollout programme (end of 2020) and, more significantly, the anticipated growth trends for low carbon technologies such as heat pumps and electric vehicles, and hence the benefits of managing such demand away from peak periods. 6.0 Overall ED1 Summary The benefits attainable by DNO action and directly impacting DNOs cost bases should be within the range 35m- 54m. The Baringa and EATL work shows that load shaping via Supplier ToU tariffs has a marginal benefit to DNOs cost bases in ED1 but a much greater, but uncertain, benefit in ED2. In ED1 ToU tariffs are likely to confer a further 12m - 26m benefit to DNOs cost bases. The total benetit impacting DNOs costs bases should be within a range of 47m to 80m. 9 This is based on peak reduction at the system level and assumes network resistance remains constant (i.e. no difference in network capacity) under both the ToU and BaU scenarios. A 7.9% reduction in peaks demand at the HV/LV network level would result in even greater reductions in losses at this level. 10 except where otherwise stated

9 Page 9 of 15 Losses benefits (which do not accrue to DNOs cost bases) are significantly reduced when compared with the ENA March 2012 report due to the lower EATL and Baringa assessments of the load shaping opportunity via Supplier ToU tariffs and lower demand levels than originally anticipated. 24m of benefits previously available to the DNO will not be available as a result of further development of SMETS2. The following tables compare the values of benefits as assessed by ENA in March 2012 with those now assessed by KEMA and EATL.

10 Page 10 of 15 (i) Benefits deliverable by DNOs independently of other parties (based on SMETS2 functionality) ENA ENA KEMA KEMA Benefit impacting on DNO cost base in ED1 in DNO control Benefit impacting on DNO cost base in ED2 in DNO control Category 1. Proactive Planning of HV & LV networks 2. Voltage monitoring and sag/swell alarms 3. Proactive Planning of HV & LV networks 4. Power Outage Management Nature of Benefit Better informed load-related investment decisions Avoided voltage complaints and admin costs Reduced investment to serve new connections ED1 Period ED2 Period ED1 Period ED2 Period ** 5.5** Reduce duration of LV interruptions Notes From only - then superseded by Responsive Demand and ANM benefits Assume gradual increasing trend from 2015 to 2020 due to increasing smart meter volumes and from 2025 due to faster LCT ramp rate and full smart meter coverage From only - then superseded by Responsive Demand and ANM benefits Increasing from 2015 to 2019 (when rollout complete). ENA benefit is based purely on consumer willingness to pay (WTP) value of 0.17p per minute and assumes no DNO incentive benefit or opex saving KEMA benefit is based on Ofgem's RIIO ED1 value of lost load (VOLL) i.e p per minute and again assumes no DNO incentive benefit or opex saving Min ( m) Max ( m) Min ( m) Max ( m) (Do not impact on DNO cost base) (Do not impact on DNO cost base) 5. Power Outage Management Reduced Guaranteed Standard failure payments From 2019 assuming energisation status polling capability Note: proposed ED1 reduction from 18h to 12h not taken into account Active Network Management Optimising LV network voltage and power flows informed by smart meter data to 8* 6 to 221* Based on LCT exponential growth trend and minimum cost of counterfactual in the IC report (assuming 10% increase in capacity headroom) Assumes hh real time data flows from smart meters min total max total NOTES: ENA values are those presented in the March 2012 report presented as undiscounted values aggregated for the ED1 and ED2 period. Benefits are based on a 2014 mass roll out commencement rather than the new 2015 mass roll out, so the ED1 benefits will be reduced if new timing is applied. *All the ENA and KEMA values are undiscounted values apart from these as the base figures KEMA used were provided to them by EATL as discounted values. **ENA values used as figures not provided by KEMA for these items. The two dark green columns on the right show the range of monetary benefit for those items that impact DNOs cost bases. Note that the nominal QOS improvements do not confer a DNO IIS benefit as outage start and finish times advance by the same amount. There is a notional benefit associated with open circuit faults, but it s so small as to be negligible. 10

11 Page 11 of 15 (ii) DSR benefits dependent upon Supplier-led ToU tariffs and load control / smart appliances ENA ENA EATL EATL Benefit impacting on DNO cost base in ED1 outside DNO control Benefit impacting on DNO cost base in ED2 outside DNO control Category 7a. Responsive Demand - TOU tariffs 7b. Responsive Demand - Load Control Nature of Benefit Reduced need for network capacity to meet peak demand Remote control or smart appliance managed responsive demand ED1 Period ED2 Period ED1 Period 12.0 to ED2 Period 94.1 to Notes Based on LCT growth in the various 4th carbon budget scenarios and taking outputs from Transform for the two scenarios giving the extreme figures. For this analysis, no distinction has been drawn between response to ToU incentives and use of smart appliances, as discussed in the report Min ( m) Max ( m) Min ( m) Max ( m) (7a. only) 8. Management of Network Losses Mitigated increase in variable I2R network losses due to improved load factor to to 66.4 Based on DECC 4th carbon budget scenarios 3 and 4 assuming losses valued at 60 per MWh (DR5) Note equates to 1.7TWh saving over ED1; equates to 11.4 TWh saving over ED2. Benefits from losses reduction do not accrue to DNOs (no target based losses incentive in ED1) (Do not impact DNO cost bases) (Do not impact DNO cost bases) min total max total Responsive Demand benefit ranges above are those that DNOs have determined to be the best estimate after consideration of all he factors available and taking into account the high degree of uncertainty. NOTES: ENA values are those presented in the March 2012 report presented as undiscounted values aggregated for the ED1 and ED2 period. Benefits are based on a 2014 mass roll out commencement rather than the new 2015 mass roll out, so the ED1 benefits will be reduced if new timing is applied.

12 Page 12 of 15 (iii) Total DNO cost-base impacting benefits (Summary of tables (i) and (ii)) RIIO ED1 Period DNO cost-base impacting benefits (in DNO control) RIIO ED2 Period DNO cost-base impacting benefits (in DNO control) Category 1. Proactive Planning of HV & LV networks 2. Voltage monitoring and sag/swell alarms 3. Proactive Planning of HV & LV networks 5. Power Outage Management Nature of Benefit Better informed load-related investment decisions Avoided voltage complaints and admin costs Reduced investment to serve new connections Reduced Guaranteed Standard failure payments Min ( m) Max ( m) Min ( m) Max ( m) Active Network Management Optimising LV network voltage and power flows informed by smart meter data Responsive Demand - TOU tariffs 8. Responsive Demand - Load Control Reduced need for network capacity to meet peak demand Remote control or smart appliance managed responsive demand Total

13 Page 13 of 15 (iv) Benefits no longer available due to changes in the Smart Meter specification ENA ENA Category 1. Remote Messaging 2. Extreme Voltage Protection Nature of Benefit Reduced postal / transport charges for notified shutdowns (from 2019) ED1 Period ED2 Period 4 8 Elimination of damage to consumer appliances Notes Minimum IHD spec in SMETS2 does not support text messaging Assumed Floating Neutral (extreme voltage) Protection now excluded from SMETS2 Total NOTE: ENA values are those presented in the March 2012 report presented as undiscounted values aggregated for the ED1 and ED2 period.

14 Page 14 of 15 (v) Total network related benefits from Smart Meter Message flows Source: ENA ENA EATL & KEMA EATL & KEMA ENA EATL & KEMA Combined benefits of (i) and (ii) for ED1. ( m) Combined benefits of (i) and (ii) for ED2. ( m) Combined benefits of (i) and (ii) for ED1. ( m) Combined benefits of (i) and (ii) for ED2. ( m) Total ED1 & ED2 network benefits ( m) min max Total ED1 & ED2 network benefits ( m) NOTE: ENA values are those presented in the March 2012 report presented as undiscounted values aggregated for the ED1 and ED2 period.

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