edcm development workshop
DESCRIPTION
EDCM Development Workshop. Welcome. 18 November 2010. 1 | Energy Networks Association. Introduction. Andrew Neves CMG Chair. 18 November 2010. 2 | Energy Networks Association. Agenda. 18 November 2010. Ofgem Background and governance EDCM Workstream summary - PowerPoint PPT PresentationTRANSCRIPT
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EDCM Development Workshop
Welcome
18 November 20101 | Energy Networks Association
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Introduction
Andrew Neves
CMG Chair
18 November 20102 | Energy Networks Association
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Agenda
18 November 20103 | Energy Networks Association
Ofgem
Background and governance
EDCM Workstream summary
Main demand charging issues: • Scaling
• Justifying level of charges
Questions
----------------------- Lunch --------------------
Break Out Sessions
Output from Breakout Sessions
Q & A Session
Next steps
Close
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Background / governance
Harvey Jones
DCMF Chair
18 November 20109 | Energy Networks Association
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Background
18 November 201010 | Energy Networks Association
• Original submission date: 1 September 2010
• DNOs worked to meet Ofgem requirements and to complete by deadline.
• Ofgem consulted in August 2010 and decided to extend the deadline to 2011
• DNOs published ‘EDCM Information Report’ early September
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Decision to delay
18 November 201011 | Energy Networks Association
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Revised timetable
18 November 201012 | Energy Networks Association
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Boundary change
18 November 201013 | Energy Networks Association
Current Boundary for applying site specific charges:
• All customers connected at 22kV or above
• Any customers connected at less than 22kV but on site specific charges prior to 1st April 2010, will continue to be charged site specific charges
• Any new connectee lower than 22kV will receive CDCM tariffs
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Boundary change
18 November 201014 | Energy Networks Association
New Boundary for applying site specific charges:
(effective from 1st April 2012)
• All customers at 22kV or above
• All customers metered at a EHV/HV substation
Note: Customers who are currently on site specific charges who do not meet the above criteria will migrate to CDCM on 1st April 2012.
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Ofgem’s decision
18 November 201015 | Energy Networks Association
• Ofgem decided to move the boundary for “site-specific” customers down to C1 and C2 – i.e. customers connected between 1kV and 22kV directly to the substation
• This decision will be implemented in April 2012 alongside the pre-2005 connected generation arrangements and the EDCM
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Treatment of pre-2005 generation
• DPCR5 removed the exemption on pre April 2005 DG from paying use of system charges
• Ofgem issued a decision on 23rd August requiring an unbundled solution
• We await Ofgem decisions on what, if anything should be compensated for
• We also require Ofgem to consider and decide on:– a practicable compensation scheme – a uniform national basis for compensation – clear, definite and secure arrangements for DNOs to recover all
compensation paid (in DPCR6 or otherwise)
16 | Energy Networks Association 18 November 2010
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Governance
18 November 201017 | Energy Networks Association
• Modifications process managed under DCUSA, like any other DCUSA change
• Ofgem has asked for issues and modification ideas to be raised first at DCMF
• DNOs are planning their own resources under the auspices of ENA (Commercial Operations Group)
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The open governance process
CDCM issue raised
Recommendationreceived
Issue assessed and developed
Min 15 WD Consultation for standard changes
DNO modeling carried out(note: possibly coordinated by the COG Charging Group)
Review and challenge
Consultation presented to SIG
Initial assessment Report presented to the DCUSA Panel
Response to consultation reviewed & published
ProgressCP?
Added to next SIG
Progression route and timetable conf irmed
Working Group Invitations sent and assessment carried out
Authority decision
letter issued
Change declaration issued to Ofgem
Yes
Potential resource provision f rom COG
Parties vote and issue DCUSA recommendation
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Next steps for the DCM SIG
18 November 201019 | Energy Networks Association
• Set out the process in more detail for the next DCMF.– DCMF SIG terms of reference
– DCMF terms of reference
– COG (CMA) group terms of reference
– Criteria for urgent modifications
– Step by step guidance of the process.
• Establish a chair (seek DNO volunteers) for SIG• Establish a secretariat - Proposal is that this is DNO funded
via the ENA• Establish a meeting regime for the SIG• Hold the first meeting and prioritise the outstanding issues• Report back to the DCMF
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EDCM workstream update
Andrew Neves
CMG Chair
18 November 201020 | Energy Networks Association
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Workstream A
Marginal / incremental costing
18 November 201021 | Energy Networks Association
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Marginal / incremental costing
18 November 201022 | Energy Networks Association
• Each DNO must implement the Forward Cost Pricing (FCP) or the Long Run Incremental Costing methodology (LRIC)
• Network studies used to identify future reinforcement requirements
• Marginal / incremental charges based on future reinforcement requirements– Only capacity-related considered
• Marginal / incremental charges form part of final Use of System tariffs
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Overview of methodologies
Long Run Incremental Costing (LRIC)
Forward Cost Pricing(FCP)
Price granularity Node Network group
Reinforcement requirements
Change in NPV of reinforcements due to 0.1MW increment
Cost of reinforcements in 10 yr period
Demand growthFixed at 1% across entire network
Derived from LTDS data
18 November 201023 | Energy Networks Association
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Improvements - LRIC
18 November 201024 | Energy Networks Association
• Revision of generation modelling in the ‘Minimum Demand’ scenario– generation coincidence within GSPs introduced
• ‘Sense-checking’ of power flows derived from the application of security factors– thresholds applied
• ‘Sense-checking’ of overall recovery of branch reinforcement costs– scaling factors introduced for branches with excessive recovery
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Improvements - FCP
18 November 201025 | Energy Networks Association
• Increased testing of impact of generation across network– increased testing around perimeter of network group in order to
create a more rigorous and reflective generation testing regime
• ‘Sense-checking’ of ‘test size’ generators (TSGs)– ‘circuit’ and ‘substation’ TSGs introduced
– thresholds introduced
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Ongoing work
18 November 201026 | Energy Networks Association
• Development of the ‘Notional Path’ methodology– calculation and apportionment of the EDCM ‘pot’ based on EDCM
customer usage of the EHV network
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Workstream B
Development work since September has focused on:•Pre allocation of more identifiable costs, reducing residual revenue allocation when scaling.
•Refined allocation methods (notional path assets used)
•Different approaches to scaling residual:– Fixed adder (Ofgem guidance)– Voltage level adder– Site specific adder
•Changes to generation scaling
•Developing in-year charging options
•Improved definition for sole use assets
18 November 201027 | Energy Networks Association
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Workstream C - Objectives
The workstream C objectives are:
• To assess the volatility of CDCM and EDCM
• To improve the transparency and predictability of CDCM and EDCM
• If necessary, to develop long term products to allow customers/suppliers to mitigate the volatility inherent in the charging methodologies.
28 | Energy Networks Association 18 November 2010
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Workstream C – EDCM Work
• Completed EDCM Work– EDCM Volatility Analysis produced for September 2010
information pack – on ENA website
• Current EDCM Work– Produce a 1 year volatility analysis once EDCM methodology
is locked down.
– Produce 5 year EDCM prices for each customer by varying Allowed Revenue.
– Volatility assessment to be included in Dec 2010 consultation – dependant on locking down EDCM methodology in November.
– Full volatility analysis and 5 year prices to be provided with EDCM submission in April 2011.
– Standardise EDCM inputs once methodology agreed
18 November 201029 | Energy Networks Association
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Approaches to demand scaling
Shankar Rajagopalan Reckon LLP (ENA/CMG consultant)
18 November 201030 | Energy Networks Association
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Demand charging issues
The purpose of this development workshop is to seek views and feedback on two specific issues:
• Approaches to demand scaling
• Justification of prices
18 November 201031 | Energy Networks Association
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Charges overview (1)
EDCM tariff elements for demand:
• p/kVA/day import capacity charge
• p/kWh consumption at peak time charge
• p/day fixed charge (sole use asset charge)
18 November 201032 | Energy Networks Association
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Charges overview (2)
EDCM charge elements for demand:
•Marginal charges (based on LRIC/FCP)
•Allocation of transmission exit charges
•Allocation of direct and indirect costs
•Allocation of network rates
•Allocation of residual allowed revenue (scaling)
18 November 201033 | Energy Networks Association
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Need to scale
• DNO allowed revenue set by price controls
• DNOs need to recover the revenue from EDCM and CDCM customers
• Marginal charges and allocated costs may not match the revenue entitlement
• Scaling is used to adjust the charges to match the revenue target
18 November 201034 | Energy Networks Association
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Methodology overview (1)
• Each EDCM demand customer is given a notional asset value based on the network levels it uses and its sole use assets.
• The CDCM customers are taken together as a group and given an asset value based on the 500 MW model.
• The DNO’s direct costs, indirect costs, network rates are allocated between EDCM and CDCM users based on these notional asset values.
• Residual revenue (allowed revenue minus these costs) is allocated on the same basis
• The allocation of these elements to EDCM users gives the EDCM revenue target.
18 November 201035 | Energy Networks Association
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Methodology overview (2)
FCP/LRIC charges are applied to EDCM demand users.
Identifiable DNO costs are allocated to EDCM demand users.
These include:• Direct operating costs
• Indirect costs
• Network rates
• Transmission exit charges
These are allocated to each EDCM user. The method of allocation varies between options.
18 November 201036 | Energy Networks Association
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Methodology overview (3)
The recovery from cost allocation and marginal charges is compared to the target EDCM revenue.
The difference (shortfall or excess) is allocated to EDCM demand users. The process of allocating the difference is called scaling.
We are considering three options:
• Fixed adder• Voltage level adder• Site specific adder
18 November 201037 | Energy Networks Association
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Methodology overview (4)
18 November 201038 | Energy Networks Association
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EDCM demand revenue
18 November 201039 | Energy Networks Association
Breakdown of EDCM demand revenue
-1 0 1 2 3 4 5 6 7 8 9 10 11 12
WPD West
WPD Wales
UKPN SPN
UKPN LPN
UKPN EPN
SSE SHEPD
SSE SEPD
ENW
CE YEDL
CE NEDL
£ millions
Sole use asset charges Transmission exit Direct costs Indirect costs
Network rates LRIC/FCP charges Demand scaling
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Fixed adder method
• Direct and indirect costs, network rates and revenue shortfall/excess are allocated to each EDCM demand user.
• This allocation between EDCM demand users does not use assets. It uses a measure of aggregate network use (kVA) calculated as the sum of 50 per cent of agreed import capacity and historical demand at peak-time of all EDCM demand users.
• A single DNO-wide charging rate in £/kVA is calculated and applied to the sum of 50 per cent of agreed import capacity and historical demand at the time of peak of each EDCM demand user.
18 November 201040 | Energy Networks Association
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Voltage level adder
• Direct costs, indirect costs, network rates and revenue shortfall (or excess) are allocated to each EDCM demand user
• This allocation between EDCM demand users does not use assets. Instead, it uses a measure of network use at each network level that is used by the customer
• The measure of network use at the network level of connection is based on agreed import capacities. At higher network levels used, it is based on demand at the time of peak
18 November 201041 | Energy Networks Association
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Site specific adder
• Direct costs, indirect costs, network rates and revenue shortfall (or excess) are allocated to each EDCM demand user.
• The allocation is based on the value of assets used by each EDCM demand user.
• This allocation between EDCM demand does not assume average use of assets at each network level by each user. It uses a “network use factor” for each network level and user.
• This allocation method is consistent with the construction of the EDCM revenue target.
18 November 201042 | Energy Networks Association
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Stylised example
• DNO allowed revenue - £20 million
• Total notional assets - £200 million
– EDCM notional assets - £20 million (£10 million at 132 kV and £10 million at 33 kV)
– CDCM notional assets - £180 million
• EDCM notional assets are 10 per cent of total
• Therefore EDCM demand revenue target is £2 million
18 November 201043 | Energy Networks Association
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Stylised example
The DNO has three EDCM demand customers:
18 November 201044 | Energy Networks Association
Customer 132 kV customer
33 kV customer 1
33 kV customer 2
Capacity 50,000 kVA 10,000 kVA 40,000 kVA
LRIC charge £2/kVA/year £10/kVA/year £5/kVA/year
Notional assets at 132 kV
£2 million £5 million £3 million
Notional assets at 33 kV
Not used £7 million £3 million
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Stylised example
• EDCM demand revenue target is £2 million
• Revenue forecast from the LRIC charge is £400,000
• Total other costs to be allocated are £1 million
• Amount to be recovered from scaling is £600,000
18 November 201045 | Energy Networks Association
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Fixed adder
• £1 million other costs and £600,000 scaling are split between customers based on capacity
• Total EDCM capacity is 100,000 kVA
• Other costs are charged at £10/kVA
• The scaling fixed adder is £6/kVA
18 November 201046 | Energy Networks Association
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Fixed adder
The fixed adder approach (based on kVA alone)
18 November 201047 | Energy Networks Association
Customer 132 kV customer 33 kV customer 1 33 kV customer 2
Capacity 50,000 kVA 10,000 kVA 40,000 kVA
LRIC charge £2/kVA/year £10/kVA/year £5/kVA/year
Notional assets at 132 kV
£2 million £5 million £3 million
Notional assets at 33 kV
Not used £7 million £3 million
LRIC recovery £100,000 £100,000 £200,000
Cost allocation£10/kVA
£500,000 £100,000 £400,000
Scaling£6/kVA
£300,000 £60,000 £240,000
Final charge £900,000 £260,000 £840,000
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Voltage level adder
• £1 million other costs and £600,000 scaling are split between network levels based on assets
• Half the EDCM notional assets are at 132 kV and the other half at 33 kV
• Therefore £500,000 other costs and £300,000 scaling at allocated to each network level
• These amounts are allocated to users of the network levels based on capacity
18 November 201048 | Energy Networks Association
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Voltage level adder
18 November 201049 | Energy Networks Association
Customer 132 kV customer 33 kV customer 1 33 kV customer 2
Capacity 50,000 kVA 10,000 kVA 40,000 kVA
LRIC charge £2/kVA/year £10/kVA/year £5/kVA/year
Notional assets at 132 kV
£2 million £5 million £3 million
Notional assets at 33 kV
Not used £7 million £3 million
LRIC recovery £100,000 £100,000 £200,000
Cost allocation£1 million
£250,000 £150,000 £600,000
Scaling£600,000
£150,000 £90,000 £360,000
Final charge £500,000 £340,000 £1,160,000
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Site specific adder
• £10 million of assets at 132 kV is split between the users of the network level based on capacity and network use factors.
• £10 million of assets at 33 kV is split between the users of 33 kV network level based on capacity and network use factors
• Total notional assets are used to allocate £1 million costs and £600,000 scaling
18 November 201050 | Energy Networks Association
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Site specific adder
18 November 201051 | Energy Networks Association
Customer 132 kV customer 33 kV customer 1 33 kV customer 2
Capacity 50,000 kVA 10,000 kVA 40,000 kVA
LRIC charge £2/kVA/year £10/kVA/year £5/kVA/year
Notional assets at 132 kV
£2 million £5 million £3 million
Notional assets at 33 kV
Not used £7 million £3 million
LRIC recovery £100,000 £100,000 £200,000
Cost allocation£1 million
£100,000 £600,000 £300,000
Scaling£600,000
£60,000 £360,000 £180,000
Final charge £260,000 £1,060,000 £680,000
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Summary
18 November 201052 | Energy Networks Association
Customer 132 kV customer 33 kV customer 1 33 kV customer 2
Capacity 50,000 kVA 10,000 kVA 40,000 kVA
LRIC charge £2/kVA/year £10/kVA/year £5/kVA/year
Notional assets at 132 kV
£2 million £5 million £3 million
Notional assets at 33 kV Not used £7 million £3 million
LRIC recovery £100,000 £100,000 £200,000
Final charge with a fixed adder
£900,000 £260,000 £840,000
Final charge with a voltage level adder
£500,000 £340,000 £1,160,000
Final charge with a site specific adder
£260,000 £1,060,000 £680,000
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Scaling objectives
Demand scaling must meet the following objectives:
1.It should recover a fair allocation of allowed revenues from EDCM users.
2.It should preserve forward-looking cost signals from LRIC/FCP.
3.The final charges after scaling should be cost-reflective and justifiable.
18 November 201053 | Energy Networks Association
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Objective 1
“It should recover a fair allocation of allowed revenues from EDCM users.”
•All three approaches allocate the same amount of revenue to the EDCM group as a whole.
•The revenue split between EDCM and CDCM users is done on the basis of assets used (using notional path).
Is this a fair allocation method?
18 November 201054 | Energy Networks Association
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Objective 2
“It should preserve forward-looking cost signals from LRIC/FCP”
•What does preserve signals mean in practical terms?
•We have three candidate definitions.
There may be others. Suggestions are welcome during the breakout session.
18 November 201055 | Energy Networks Association
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Objective 2
Definition 1:
An approach preserves signals if the difference in the final charge between two locations (within the same DNO area) is equal to the difference between their LRIC/FCP charges.
18 November 201056 | Energy Networks Association
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Objective 2
How do the different approaches satisfy definition 1?
•The fixed adder does well if we compare two customers identical in capacities, demand at the time of peak and sole use assets.
•The voltage level adder only does well if the two customers also used the same network levels.
•The site specific adder is the most restrictive. It requires these identical customers to use the same value of network assets.
18 November 201057 | Energy Networks Association
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Objective 2
Definition 2:
An approach preserves signals if the difference between the final charge arising from a reduction in demand at peak by 1 kVA is equal to the FCP/LRIC charge in £/kVA.
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Objective 2
How do the different approaches satisfy definition 2?
•Our current proposal is to apply a part of the LRIC/FCP charge (the part that relates to higher network levels) and the transmission exit charge to in-year consumption at the time of peak.
•To preserve signals under definition 2, we would need to:
– Continue to apply a part of the LRIC/FCP charge to in-year consumption.
– Consider applying the local FCP/LRIC charge to in-year consumption as well.
– Apply the transmission exit charge as a capacity charge.
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Objective 2
Definition 3:
An approach preserves signals if the difference between the final charge and the recovery from the application of the FCP/LRIC charge represents a fair or cost-reflective allocation of residual revenue across customers.
How do our approaches do if we use definition 3?
To answer this question, we need to ask a further question: Which leads us to objective 3.
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Objective 3
“The final charges after scaling should be cost-reflective and justifiable.”
•What do we mean by “cost reflective”?
We take cost-reflective to mean that the final charges are no higher than an allocation of DNO expenditure (or revenue) based on tangible cost drivers.
• Network assets used• Capacity• Demand at peak• Need to reinforce (congestion)
Some costs might not have individual customer based drivers
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Objective 3
Fixed adder:
•Allocates residual revenue using a single DNO-wide £/kVA/year charging rate.
•Capacity and peak demand drive residual revenue allocation.
•Customers with higher capacities have a higher allocation (all else being the same)
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Objective 3
Voltage level adder:
•Allocates residual revenue using different £/kVA/year charging rates for different network levels.
•Capacity at voltage of connection and peak demand at higher levels are used to calculate the charging rate.
•Takes some account of network level usage. e.g. 132/11 kV connected customers do not pay an allocation in respect of 33 kV circuits.
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Objective 3
Site specific adder (unique £/kVA/year for each user):
•Allocates residual revenue on the basis of notional assets used within each network level (using network use factors).
•Method of calculating EDCM revenue target is the same as the method for allocating the costs and residual revenue to EDCM users.
•Customers who use 1 km of 33 kV cable pay less per kVA than customers who use 10 km of 33 kV cable.
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Questions on scaling
• What are the advantages and disadvantages of each scaling approach?
• Which one best meets the EDCM objectives?
• Which approach should we adopt?
• Are there other approaches we should consider?
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Justification criteria
Oliver Day
WSB
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Justification (1)
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Justification (2)
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Justification (3)
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Justification (4)
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Justification (5)
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Justification (6)
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Justification (7)
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Justification (8)
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Justification (9)
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Question and answer session
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Lunch
Restart at 1pm
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Breakout sessions
Session 1:
•What are the advantages and disadvantages of each scaling approach? (30 minutes)
Session 2:
•Justification of prices. (30 minutes)
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Breakout sessions feedback
Feedback from breakout sessions.
•Scaling– Group A– Group B– Group C
•Justification– Group A– Group B– Group C
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Next steps
Andrew Neves
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Next steps
•Workshop review
•Further work on EDCM development
•Issue consultation
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Outline timeline
• DCMF meeting 2 December 2010• Consultation published 10 December • Consultation workshop 13 January 2011• Consultation closes 31 January • DCMF meeting 3 February• EDCM submission deadline 1 April
See ENA web site for details of timeline:
http://energynetworks.squarespace.com/edcm-file-storage/05-edcm-meeting-dates-project-plan-and-project-risks/
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Revised plan
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Model Lockdown
End of December
April 2011 Submission
Sept
Oct
Nov
Dec
Jan
Feb
Mar
Apr
DCMF 7/10
Trial Justification
Workshop 18/11
Further Development
Consultation Testing
Industry Briefing
Industry Briefing
DCMF 2/12
Workshop 13/1
DCMF 3/2
Prepare Consultation
DCMF TBC
Justification Criteria
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EDCM Development Workshop
Thank you!
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