Loss methodology - Electricity Authority
The calculation of loss factors and the use of loss factors for reconciliation purposes Consultation paper
July 2007
Purpose 1.
The purpose of this consultation paper is to obtain industry feedback on guidelines on the calculation of loss factors and the use of loss factors for reconciliation purposes.
Background 2.
The MARIA Governance Board (MGB) identified reconciliation as a strategic priority area for MARIA for 2002/03. In August 2002, the MGB appointed members to a MARIA Reconciliation Project Team (RPT) to advise the MGB on how to ensure that the reconciliation process produced accurate, complete and timely information in a cost-effective manner. The MARIA RPT undertook a fundamental assessment of the problems associated with the reconciliation process, and proposed a solution and a framework for implementing its reconciliation recommendations. This included the establishment of both an implementation team and a project reference group.
3.
The Electricity Commission (Commission) recognised the importance of completing the work previously undertaken on reconciliation and, as a result, the implementation team established under MARIA was continued as the EC Reconciliation Project Team (ECRPT), which was appointed to make recommendations to the Commission.
4.
It was recognised during the work of both the MARIA RPT and the ECRPT that there would be benefits from a consistent approach to the calculation of distribution loss factors.
5.
A series of workshops were held by the Commission in April 2005 in Auckland, Wellington, and Christchurch to assist participants with their understanding of the proposed reconciliation rules and arrangements. These workshops presented an opportunity to discuss issues raised by participants. One of the significant issues discussed was that of how loss factors are determined. Participants considered that the Commission should reinforce the need for a common methodology for calculating distribution loss factors with all distributors.
6.
New reconciliation rules have been approved, and will be implemented on 1 May 2008. It is envisaged that before this date, distributors will be required to have adopted and implemented the requirements contained in the loss factor guidelines that the Commission has developed.
7.
There is a need for a common methodology because of the importance of loss factors within the reconciliation process. Under the current Rules, incumbent retailers are exposed to the risk of incorrect calculation and application of loss factors. Under the new reconciliation arrangements, with the introduction of the concept of unaccounted for electricity (UFE), all retailers will be exposed to this risk. This change does not remove the need for loss factors, particularly in relation to the differentiation of losses between consumption groups. Accuracy
of loss factors is crucial to the accuracy of reconciliation, and the effects of this flow right through to retailer pricing.
Submissions 8.
The Commission invites submissions on the proposal by 5pm on Friday, 17 August 2007.
9.
The Commission’s preference is to receive submissions in electronic format (Microsoft Word). Submissions in electronic version should be emailed with ‘The calculation of loss factors and the use of loss factors for reconciliation purposes’ in the subject header to [email protected].
10.
If submitters do not wish to send their submission electronically, they should post one hard copy of their submission to the address below. Jenny Walton Electricity Commission Level 7, ASB Bank Tower 2 Hunter Street P O Box 10041 WELLINGTON Tel: (04) 460 8860 Fax: (04) 460 8879
11.
The Commission will acknowledge receipt of all submissions electronically. Please contact Jenny Walton if you do not receive electronic acknowledgement of your submission within two business days.
12.
Your submission is likely to be made available to the general public on the Commission’s website. Submitters should list any documents attached in support of the submission in a covering letter and clearly indicate any information that is provided to the Commission on a confidential basis. All information provided to the Commission is subject to the Official Information Act 1982.
Distribution loss factors 13.
A distribution loss factor, normally expressed as a multiplier, is used to estimate the difference between metered quantities at the input to a network and the sum of metered quantities at the meters of consumers averaged over a period of time. The loss factor is calculated as 1/(1-loss ratio) where the loss ratio equals the average proportion of losses over a network.
14.
The multipliers are used by electricity retailers (applied to half hour data) and the reconciliation manager (applied to non half hour data) to multiply the electricity volume recorded for retail consumers to determine each retailer’s responsibility for the purchase of electricity on that network. The loss factor is also used by retailers in determining their pricing plans.
15.
Although loss factors have a direct financial impact on individual consumers’ electricity costs, inaccuracies due to non-technical losses have no impact on the actual quantity of energy passing through (or to) any part of the electrical system.
16.
Large electricity distributors are required by the Electricity Information Disclosure Requirements (2004) to disclose the loss factors that apply to their networks and are also required by rule 8.1 of section VI of part G of the Electricity Governance Rules 2003 (Rules) to supply distribution loss factors for the reconciliation process to the reconciliation manager. There is currently no single industry-wide methodology for the calculation and periodic review of distribution loss factors.
17.
There are three different loss factor types, and the loss methodology guidelines define how each type is derived: a.
reconciliation loss factors;
b.
technical loss factors; and,
c.
non-technical loss factors.
Reconciliation loss factors 18.
Reconciliation losses (also known as observed or total losses) represent the difference between the delivered electricity at one point of connection and the electricity required to be injected in order to supply the delivered electricity. Hence, a reconciliation loss factor adjusts the consumption data submitted for reconciliation to produce equivalent metering data at a grid exit point (GXP). The reconciliation loss factor is comprised of two components – technical and non-technical, as discussed below.
Technical loss factors 19.
20.
Technical losses represent the electricity entering the network that is consumed during the delivery to consumers’ installations. There are two main technical components to the loss: a.
a fixed component that arises from the standing losses of the network transformers; and
b.
variable components that arises from the heating effects of the resistance in the HV and LV network conductors, zone substations and distribution transformers.
Information about technical loss factors (given accuracy limitations) may be used to: a.
value the electricity lost during delivery;
b.
allocate technical loss factors to different voltage tiers and locations; and
c.
monitor the effectiveness of changes to a distributor’s network or asset management methodology.
Non-technical loss factors 21.
Non-technical losses represent the difference between reconciliation losses and technical losses. These include metering errors, incorrect meter installations, theft, and unread meters.
22.
Information about non-technical loss factors (given accuracy limitations) may be used to: a.
value the electricity that may have been mis-allocated;
b.
allocate non-technical loss factors to different voltage tiers, locations, and customer classes; and
c.
identify areas where reduction in distribution losses may be possible by examining the reconciliation loss factor, and the accuracy of metering systems, data, or data handling techniques.
Q1. Do you agree with the definitions and uses of reconciliation, technical and nontechnical loss factors set out in this paper? Please give reasons for your view Unaccounted for electricity 23.
Unaccounted for electricity (UFE) means the quantity of electricity that is the difference between: a.
the quantity of electricity injected into a local network or embedded network; and
b.
the quantity of electricity consumed within that balancing area as indicated in the submission information after application of loss factors and adjustment for installation control point (ICP) days;
as calculated per trading period by the reconciliation manager. Current rule requirements 24.
The current Rules relating to the application of loss factors are: a.
part A: “loss category” means the relevant code in the schedule published by a distributor which identifies the relevant loss factors that apply to consumption information; … “loss factor” means the factor applied to consumption information at the ICP or NSP (for an embedded network) to allow for losses within the local network or embedded network to produce equivalent consumption information at the relevant NSP;
b.
rule 5.1 of section VI of part G: 5.1.1 Half hour consumption information to be adjusted for losses
Half hour consumption information provided pursuant to rule 5.2 will be provided from a metering installation and will be adjusted [by the data administrator], as appropriate, to provide for losses within the local network; 5.1.2 Non-half hour consumption information not to be adjusted for losses Non-half hour consumption information provided pursuant to rule 5.3 will be provided from a metering installation and will not be adjusted to provide for losses within the local network. c.
rule 8.1 of section VI of part G: Each distributor will advise the reconciliation manager and the relevant data administrator and retailer of the loss factors applicable to each loss category for each of its networks.
25.
Under the current reconciliation arrangements, distributors publish loss factors that are then applied to the metered data submitted by independent (non-incumbent) retailers. Any difference between the electricity injected into a local or embedded network and the total of the loss adjusted volumes from independent retailers is UFE and is attributed to the retailer assigned as the incumbent for that network.
New reconciliation rules (from 1 May 2008) 26.
The revised reconciliation rules that will come into effect from 1 May 2008 contain the following rules relating to the application of loss factors: a.
part A: “loss category” means the relevant code in the schedule published by the registry which identifies the relevant loss factors that apply to submission information; … “loss factor” means the factor applied to submission information to obtain loss adjusted information at the relevant NSP;
b.
schedule J4 of part J: This schedule sets out the reconciliation process performed by the reconciliation manager, and includes the following rules: rule 1.3, which sets out a requirement to apply loss factors to submission information for non half hour metered ICPs which have been adjusted for ICP days; rule 1.4, which sets out a requirement to apply loss factors to submission information for half hour metered ICPs which have been adjusted for ICP days; rule 7, which relates to the application of loss factors. It provides: the registry must provide the reconciliation manager with the loss factors for each loss category … and the reconciliation manager must, after adjustment for ICP days scaling and application of profiles, apply the loss factors to all submission information.
The reconciliation manager must apply loss factors to submission information in respect of embedded networks, and submission information in respect of parent networks for the appropriate reconciliation period; c.
rule 10, of part E, which sets out the requirement that distributors’ processes be audited. It provides that: [Each] distributor’s process and procedures that must be audited include… 10.3 the creation and maintenance of loss factors;
d.
rule 24.2.2 of part E, which requires loss factor reports to be provided to the reconciliation manager as follows: A report detailing the loss factor value(s) for each loss category code as recorded by the registry in respect of all trading periods;
e.
rule 5 of schedule E1 of part E, which relates to loss factors on registry and provides: 5.1
Distributors advise loss factors
Distributors must advise the registry of the loss factors for each loss category code on the registry. 5.2
Two loss factors per month
A loss category code may have a maximum of two loss factors per calendar month. Each loss factor must cover a range of trading periods within that month such that all trading periods have a single applicable loss factor. 5.3
Distributors to advise market administrator
Distributors must advise the market administrator of their intention to add new loss category codes or to change the value or applicable time period of any loss factor, at least three months before the change is to take effect, or new code being added. 5.4
Distributors maintain loss factors
Distributors must advise the registry of any change to any loss factor on the registry at least two calendar months before the change is to take effect. 5.5
Registry to publish loss factors
The registry must publish an updated schedule of all loss category codes and associated loss factors advised by the distributor in accordance with rule 5.4 within one business day of being notified of a change. 27.
Under the new reconciliation rules, distributors will publish loss factors that are then applied to the metered data submitted by all retailers. The UFE will be allocated to all retailers at the relevant network supply point (NSP), not just to the incumbent retailer, as is done currently.
Examination of current and alternative methods for calculation of loss factors Interviews with industry participants 28.
A number of interviews were held with the industry from February to April 2007 to collect information about how losses and loss factors are currently calculated and treated by distributors, as well as any concerns that industry participants have with regard to loss factors.
29.
A number of different approaches are currently used by distributors in calculating loss factors, and a range of concerns were expressed by industry participants. The findings from these interviews are detailed in Appendix One.
30.
The key issues with current loss factor practices in New Zealand are that there is a lack of: a. visibility as to how loss factors are derived; b. monitoring of losses and loss factors; c. understanding of loss factors and the purpose they serve; d. clarity in the definition of losses and associated terminology; e. consistency in the calculation of losses and loss factors; and f. incentives for distributors to reduce losses. 1
How New Zealand distributors calculate loss factors 31.
As illustrated by the information in Appendix one, a number of approaches are adopted by distributors when calculating loss factors for their networks. These approaches range from using a legacy loss factor that was determined before the structural separation of retail and distribution businesses, to the use of a comprehensive calculation model including information about half hourly data of annual loading patterns and the determination of the source of technical losses.
32.
Many distributors do not regularly review loss factors, as shown by the widespread use of loss factors determined prior to structural separation. In addition, a number of distributors merely stated what the loss factors are, rather than providing information as to how the loss factors were determined.
33.
Another common practice is the derivation of loss factors using GXP extraction data minus consumption information at that GXP. Distributors use an average of this information to determine the appropriate loss factors. The longest period of time used by a distributor over which an average is determined is five years. This means that no efforts have been made by some distributors to attempt to estimate what the ‘technical portion’ of these losses might be.
34.
There are a limited number of distributors that determine and publish the portion of their losses that can be attributed to technical losses despite the fact that it is widely recognised that determining technical loss factors is not an
1 The issue identified in paragraph 30(f) above on identifying ways to reduce distribution system losses is outside of the scope of this paper. However, if greater transparency results from this project, this will assist the Commission in considering ways to reduce distribution system losses.
exact science. Information from Orion, Aurora, Vector, and Unison on how their technical losses are estimated is included in Appendix Two.
Australian loss factor regime 35.
In order to understand what best practice may be for the treatment of losses and loss factors, the Commission has considered how they are treated in overseas jurisdictions. Australia was the most useful jurisdiction to consider. The state regulators in Australia take different approaches to losses and loss factors (although they are all governed by the National Electricity Rules 2 ).
36.
There was a general lack of information about the treatment of loss factors in countries other than Australia. This may be a result of those countries having different settlement regimes to those in Australia and New Zealand.
37.
The Australian jurisdictions (and the relevant regulators) that the Commission has considered in detail were: a. New South Wales: Independent Pricing and Regulatory Tribunal (www.ipart.nsw.gov.au); b. and
Victoria: Essential Services Commission (www.esc.vic.gov.au);
c. Queensland: Queensland Competition Authority (www.qca.org.au). 38.
The Commission briefly considered the treatment of losses and loss factors in the Australian Capital Territory (ACT), Tasmania, and South Australia, but the loss factor arrangements are not as well-developed in these states and did not provide any additional insight. In addition, Western Australia and Northern Territory are not yet part of the National Electricity Market and therefore do not have the same obligations as other states.
39.
The Australian National Electricity Rules require that distributors (or Distribution Network Service Providers, as they are referred to in Australia) obtain the approval of the relevant state regulator for the distribution loss factors for their electricity networks.
40.
These loss factors must be determined by a methodology that is in accordance with principles set out in the National Electricity Rules. If the jurisdictional regulator has determined a methodology, then that methodology must be applied. If the jurisdictional regulator has not determined a methodology, then the relevant distributor must determine a methodology.
41.
Appendix Three sets out the requirements of the National Electricity Rules in relation to losses and loss factors in more detail, and some information on the approaches adopted by New South Wales, Victoria and Queensland. Further information is available on the methodologies used in Australia that (depending
2
A copy of the Rules is available at: http://www.aemc.gov.au/rules.php
on the arrangements recommended and approved in New Zealand) may assist distributors in their calculation of loss factors. Criteria developed to weigh up potential options 42.
The project team developed criteria to assist it in making recommendations on future arrangements for loss factors. In developing the criteria, the concerns expressed by industry participants, and the research conducted on loss factor methodologies in other jurisdictions, were taken into account.
43.
The project team was decided that the criteria against which proposed arrangements for loss factors should be assessed are as set out below. The arrangements should: a.
clarify the definition, purpose and application of different types of loss factors, so that there is a consistency understanding within the industry (including the difference between ICP- and NSP-referenced loss factors);
b.
allow the Commission to effectively and efficiently monitor distribution losses;
c.
give distributors an incentive to accurately determine the technical losses on their networks, using a recognised methodology, on a regular basis;
d.
provide a framework for dispute resolution between participants on the loss factors that should be used on a network;
e.
provide transparency of the calculation and periodic review of distribution loss factors;
f.
identify the amount of non-technical losses on a network, and encourage minimisation of non-technical losses; and
g.
ensure that the size and influence of any embedded generation is taken into account.
Q2. Do you agree with the criteria developed by the project team against which proposed loss factors arrangements should be assessed? Should one or more criteria be added or deleted? Please give reasons for your view. 44.
Table 1 lists the main features of the loss factor regime in Australia, and how, if adopted in New Zealand, they would contribute to the achievement of the criteria listed above. The project team considered items that contributed to the criteria and included the appropriate measures in the recommended option and draft guideline.
Table 1: Assessment of features of the Australian Regime Australian feature/principle
Criteria developed by the Loss Factor Project Team Clarify the definition, purpose and application of different types of loss factors
Allow the Commission to monitor losses
Give an incentive to distributors to regularly and accurately determine technical loss factors
1. Loss factors determined for all connection points either on a site-specific basis or collectively in relation to connection point classes
Already a feature of the current New Zealand arrangements
2. Allocation of connection points to either a single transmission network connection point or to a virtual transmission node and to a class of distribution network connection points
Already a feature of the current New Zealand arrangements
3. Distributors must conduct a reconciliation between the actual and forecast losses for the previous financial year
9
4. Distributors must use the most recent actual load and generation data available for a consecutive 12month period (and adjust this data by projected load growth)
9
5. For non-site-specific connection points, determine the loss factor by using a volume weighted average of the average electrical energy loss between the transmission network connection point or virtual transmission node to which it is assigned and each distribution network connection point in the relevant class of distribution network connection points for the financial year in which the loss factor is to apply
Already a feature of the current New Zealand arrangements
6. For site-specific connection points, determine the loss factor by reference to the average electrical energy loss between the distribution network connection point and the transmission network connection point to which it is assigned in the financial year in which the loss factor is to apply
Already a feature of the current New Zealand arrangements
7. Treat flows in network elements that solely or principally provide market network services as constant
Already a feature of the current New Zealand arrangements
8. Distributor must satisfy the regulator that the levels of losses are consistent with that of a well managed network
9
9
Provide a framework for dispute resolution
Provide transparency of the calculation and review of loss factors
Identify the amount of non-technical losses on a network and encourage minimisation
Ensure that embedded generation is taken into account
9
9
9
9
9
9
9
9
Australian feature/principle
Criteria developed by the Loss Factor Project Team Clarify the definition, purpose and application of different types of loss factors
Allow the Commission to monitor losses
Give an incentive to distributors to regularly and accurately determine technical loss factors
Provide a framework for dispute resolution
Provide transparency of the calculation and review of loss factors
9. Distributor must satisfy regulator that calculation methodologies are uniform and consistent with methodologies used previously
9
9
9
9
10. Distributor must satisfy regulator that appropriate allowance has been made for theft and metering inaccuracy (and other non-technical losses)
9
9
9
9
9
9
9
9
9
9
9
9
11. If necessary, the regulator can undertake public consultation and/or engage a consultant to assist in assessing the proposed loss factors
9
12. If a distributor makes a material change in its methodology, it must give reasons for the change and explain how the proposed methodology differs from that used in the previous year 13. Regulators specify a (high-level) typical methodology to assist distributors with the calculation of loss factors
9
9
14. Regulator specifies what the distributor’s methodology paper should contain (minimum requirements)
9
9
15. Distributors’ methodologies are published
9
Identify the amount of non-technical losses on a network and encourage minimisation
9
Ensure that embedded generation is taken into account
Options for future loss factor arrangements 45.
Four different options were examined by the project team and these are outlined below. The four options fit into the following three ‘higher level’ alternatives: a.
the status quo (Option One);
b.
determination of a reconciliation loss factor (Option Two); and
c.
new definition of a reconciliation loss factor (Options Three and Four).
Option One: Status quo 46.
One option is to leave loss factor arrangements as they currently are. However, given the issues that have arisen to date with and the numbers of concerns identified by participants in Appendix Two, this option was discarded early in the process. It does not satisfactorily meet any of the criteria in Table Two.
Option Two: Determination of a reconciliation loss factor - GXP extraction data less consumption data 47.
Option Two is generally the status quo for a number of distributors. It would involve defining losses as the GXP extraction data less consumption data, and calculating a loss factor that represented these losses.
48.
There would be no distinction between technical and non-technical losses.
49.
This option would involve using an average of the differences between GXP extraction data and consumption data over a period of time to determine the loss factor (to take out the effects of seasonality).A two-year average would be appropriate, because it would smooth out extraordinary events while still providing having an up-to-date load profile.
50.
After submission data has been loss adjusted for the loss factor calculated by subtracting consumption data from GXP extraction data, any difference between this and the GXP data would be:
51.
52.
a.
allocated to the incumbent retailer under the current Rules;
b.
classified as UFE under the new reconciliation rules, and allocated accordingly.
The advantages of Option Two are as follows: a.
it is simple and mechanistic; and
b.
it is low cost, as some distributors currently use this method.
The disadvantages of Option Two are as follows: a.
the aggregated data would not enable the Commission or participants to track trends in either technical or non-technical losses; and
b.
the opportunity to provide incentives to reduce the level of non-technical losses by having a transparent process is lost.
Option Three: Disaggregation of loss factor components - estimation of both technical and non-technical losses 53.
This option would make it mandatory for distributors to estimate technical and non-technical losses. In order to do this, the following would be required: a.
a set of principles to guide distributors on how to determine technical losses and loss factors;
b.
a requirement that technical losses to be reviewed every five years, unless there is a significant change in network configuration and/or load; and
c.
54.
55.
a requirement on distributors to publish the methodology they use to determine technical losses. In terms of non-technical losses, this option would involve using an average over a period of time to determine the non-technical loss factor (to take out the effects of seasonality). The Commission considers that a two-year average would be appropriate. After submission data has been loss adjusted for the loss factors calculated at (53) and (54), any difference between this and the GXP data would be: a.
allocated to the incumbent retailer under the current Rules; and
b. classified as UFE under the new reconciliation rules, and allocated accordingly. 56.
The advantages of Option Three are as follows: a.
it identifies opportunities for reduction of losses by retailers and distributors; and
b.
UFE volumes would be more manageable.
The disadvantage of Option Three is that the process has higher costs than Option Two, given that it may involve new activity for some distributors. Option Four: Disaggregation of loss factor components - new definition of a reconciliation loss factor 57.
This option would redefine reconciliation losses as being only technical losses.
58.
It would be mandatory for distributors to estimate technical losses. In order to do this, the following would be required: a.
a set of principles to guide distributors on how to determine technical losses and loss factors;
b.
a requirement that technical losses to be reviewed every five years, unless there is a significant change in network configuration and/or load; and
c.
a requirement on distributors to publish the methodology they use to determine technical losses.
59.
60.
61.
Q3.
After submission data has been loss-adjusted for the loss factors, any difference between this and the GXP data would be: a.
allocated to the incumbent retailer under the current Rules; and
b.
classified as UFE under the new reconciliation rules, and allocated accordingly.
The advantages of Option Four are as follows: a.
it identifies opportunities for reduction of technical losses by distributors; and
b.
it is more transparent than Option Two.
The disadvantages of Option Four are as follows: a.
it does not assist with the objective to achieve the closest reconciliation between actual consumption and the loss-adjusted consumption, which the industry should be able to do, and the UFE is the “trim”. If the industry can estimate the technical and non-technical loss factors on a consistent basis, then UFE should be minimal. When it is not, then it will be clear when something out of the ordinary has occurred;
b.
the declared loss factor assists with planning, pricing and risk management and by declaring only a technical loss factor there could be a huge variance in the actual observed losses. This would create problems for this planning, pricing and risk management; and
c.
UFE volumes may be unmanageable.
Are there any options for future loss factor arrangements other than the four options identified in this paper? Please give reasons for your view.
Assessment of options against criteria 62.
In addition to the identification of advantages and disadvantages of each option above, Table 2 summarises the assessment of each of the options against the criteria identified in paragraph 43.
Table 2: Assessment of options against criteria Status quo
Determination of a reconciliation loss factor
Disaggregation of loss factor components
Criteria
Option One
Option Two
Option Three
Option Four
Clarify the definition, purpose, and application of different types of loss factors, so that there is a consistency of understanding within the industry (including the interaction between ICPand NSP-referenced loss factors)
8
8
99
9
Allow the Commission to effectively and efficiently monitor distribution losses
8
8
99
99
Give distributors an incentive to accurately determine the technical losses on their networks, using a recognised methodology, on a regular basis
8
8
99
99
Provide a framework for dispute resolution between participants on the loss factors that should be used on a network
8
8
99
9
Provide transparency of the calculation and periodic review of distribution loss factors
8
9
99
99
Identify the amount of nontechnical losses on a network, and encourage minimisation of non-technical losses
8
8
99
99
Ensure that the size and influence of any embedded generation is taken into account
8
9
9
9
Legend:
63.
99
= contributes to the criterion
9
= meets the criterion
8
= does not meet criterion
As a result of this analysis, the project team has recommended that Option Three be implemented.
Q4. Do you agree that Option Three should be implemented (mandatory estimation of both technical and non-technical loss factors)? Please give reasons for your view.
APPENDIX ONE: RESULTS OF INTERVIEWS WITH INDUSTRY PARTICIPANTS
Concerns expressed by industry participants i.
Lack of visibility of how loss factors are derived.
ii.
Lack of frequent review of loss factors.
iii.
Lack of analysis performed on loss factors.
iv.
Loss factors are not high enough, so incumbent retailers are wearing a portion of the technical loss.
v.
Lack of understanding about loss factors and their purpose.
vi.
Lack of clarity in the definition of “losses” and associated terminology.
vii.
Lack of consistency.
viii.
Loss factors are not seasonal, and losses are not getting apportioned across the right connection types.
ix.
Distributors are currently discouraged from putting in low loss equipment.
x.
The data that retailers are submitting to distributors is not the same as the data being submitted to the reconciliation manager, and retailers are not monitoring that these are the same This is a problem, because the distributors are calculating the loss factor on one set of data, and the UFE will be determined using another set of data.
xi.
Embedded generators do not currently see any benefit in helping to reduce losses on the distribution network.
xii.
Although embedded generators are a loss reduction element in the distribution network, if they generate more and the generation is pumped on to the national grid, this causes more losses on the distribution network.
xiii.
It is not clear how losses should be allocated given that losses are a squared function (i.e. not linear). Because they are non-linear, heavy users should be penalised more, but distributors are unsure what best practice is.
xiv.
Distributors are not responsible for all technical losses – for example, the network stops at the connection point/customer service mains – therefore losses through the service main are not the responsibility of distributor.
xv.
There is a lack of understanding of the true cost of distributed generation.
xvi.
Participants have been trying to determine a new methodology, however they are having difficulty getting meaningful results. There are a lot of assumptions that need to be made about load factors and peak loading.
Different approaches used by distributors to calculate loss factors i.
Loss factors are regularly updated and communicated to/discussed with retailers. In terms of determining loss factors: engineering calculations are completed, billing records are examined, the difference is then considered and non-technical losses are estimated.
ii.
Legacy loss factors are used – i.e. those calculated before the structural separation of retail and distribution companies.
iii.
Loss factors are not done very well, and some distributors have no historical data of load flow. Loss factors are determined by calculating the difference between GXP and metered data.
iv.
The disclosed loss factor is a legacy loss factor from when the key measure was GXP data minus sales. However, technical loss factor is estimated looking at substation losses, heating, etc.
v.
Losses on the network are used to pro-rata total losses to customers according to size – those down to 11kV take a share of losses on upstream; large industrials have a slightly higher contribution to losses because of short runs of low voltage (LV), but are closer to 11kV transformers; and then tail end customers contribute to losses right down to LV. Technical losses are distinguished, but non-technical losses are built into published loss factors.
vi.
Loss factors are based on information from about six years ago.
vii.
Take what retailers report and use a five-year average.
viii.
Loss factors have not changed since structural separation, and some factors are purely technical, while others represent total losses.
ix.
Representative customers are identified and the average load for each customer is calculated and the average losses are weighted. A percentage is then added on for non-technical losses. In the past, calculations were done on transmission and subtransmission configurations, but there is no incentive to do this any longer.
x.
Use a 12-month rolling average of total losses.
xi.
Use estimated loss factors for mass market (derived before structural separation), and calculate accurate technical loss factors for larger customers (usually a dedicated line, so easier to determine). A three-year rolling average is used.
Suggestions made by participants in terms of improvements that could be made i.
Require publication of the methodology used and a mandated review period.
ii.
Introduce a regime that means distributors have an incentive to get the loss factor correct.
iii.
If loss factor is found to be incorrect, then require distributors to do the washup calculation for the time period for which the loss factor was incorrect.
iv.
Require publication of technical and non-technical losses.
v.
Require distributors to reassess loss factors when the network changes, at the time that it happens.
vi.
Develop loss factor guidelines.
vii.
Require independent audits (and if audit reveals deficiencies, then Commission mandates methodology).
viii.
Introduce a “compliant” methodology as a default.
ix.
Put incentives in place for distributors to minimise losses, bearing in mind other regulations.
x.
Should continue the current practice in relation to technical losses and global reconciliation and the differences exposed between total losses and technical losses
xi.
If global reconciliation is introduced, either specify what the technical losses (and technical loss factors) are, so that the rest can be classified as UFE; or have a watchdog that is keeping an eye on the levels of losses.
xii.
Establish a Loss Factor Review Panel so that if an issue arises with a loss factor, then it could go to this group for advice and resolution.
xiii.
Once there is global reconciliation, the loss factor should just be a technical loss factor and everything else can be classified as UFE.
xiv.
In terms of embedded generation: the loss factor should be defined as whatever it would be without the embedded generation, and then the embedded generator should receive some ‘reward’ for reducing losses.
xv.
A simple methodology with one loss factor for half hour and one for non half hour should be introduced.
xvi.
If there is a national standard, then the standard needs to allow for embedded generation, not be heavily computer-powered, and the loss factor should not need to be updated too regularly.
xvii. There should be a disciplined, engineering basis for technical loss factors and they should be reviewed annually. xviii. An acceptable methodology to use before global reconciliation should be introduced. A two-year rolling average should be used, but the data used needs to be at least seven months old. xix.
Greater consistency should be introduced in relation to the data retailers give to distributors.
Concerns raised by participants in terms of improvements to loss factor arrangements i.
Benchmarking between networks would be inappropriate, given different networking configurations. There would be changes in efficiency over time, depending on the network’s investment plan.
ii.
Any regime introduced may become a “stick to beat distributors with”.
iii.
Having to develop a new methodology would be a new activity and so this would mean an increase in costs for distribution companies.
iv.
There would be an impact on costs for consumers if there are increased compliance costs.
v.
A cost-benefit analysis should be conducted. This has been ignored in the past and the view is that the ‘headroom’ is running out for some distributors, i.e. distributors do not have the time nor the resources to conduct one.
vi.
Engineering calculations to determine technical losses are too difficult. A lot of computing power would be needed and the results may not be accurate.
APPENDIX TWO: CALCULATION OF TECHNICAL LOSSES AND LOSS FACTORS BY NEW ZEALAND DISTRIBUTORS
Orion 1.
Orion has derived its loss factors in light of the following: 3 a.
Orion has two different sub-networks, with distinctly different loading patterns – Zone A, urban winter-peaking and Zone B, rural summerpeaking;
b.
losses depend on loading level. Different factors apply by season and by time of day (day/night) according to the differences in average loading levels. Orion also has substantial numbers of night-only loads, which are supplied when the loading levels are low. Specific profiles apply;
c.
losses depend on the part of the network involved in distribution. The factors are higher for distribution to general connections, where the complete network is involved, than for major customer connections, where the LV network is not involved;
d.
losses depend on the voltage level where the metering is connected, low voltage (LV) or high voltage (HV). The key difference is the losses in the distribution transformer. Different sets of loss factors apply for major customer connections, depending on the voltage of metering.
2.
Orion has a comprehensive calculation model, with half-hourly data of annual loading patterns, which has been used to determine all of its published loss factors. Orion has derived the set of factors in order to provide reasonable accuracy in accounting for the key influences on losses.
3.
Orion publishes the following information in its Quality of Supply Statement:
Orion Network: Sources of technical losses Source
Urban
Rural
Subtransmission lines and cables
0.5%
1.0%
District (power) transformers
0.5%
0.5%
11kV lines and cables
1.5%
3.5%
Subtotal subtransmission + 11kV
2.5%
5.0%
Distribution transformers
1.2%
1.2%
230/400V lines and cables
1.3%
0.3%
Subtotal Low Voltage (LV)
2.5%
1.5%
Loss ratio totals
5.0%
6.5%
4.
Orion has used its losses model to consider the marginal losses that occur during peak loading. The basis of the losses model is LL=LNL + LFL x P^n (LL = Loss Load; LNL=Loss at no load; LFL=Loss at full load; P=Normalised load power; n=Exponent in range1-2).
5.
Orion considers its technical loss ratio for its urban network to be 5% +/-1%.
3
“Review of Loss Factors”, Neville Ross, Commercial Contracts & Pricing Manager, Orion, 08/09/2004
Aurora 6.
Aurora notes that there are two main technical components to distribution losses: 4 a.
a fixed component due to the standing losses of the zone substation and distribution transformers; and
b.
variable components arising from the heating effects of the resistance in the delivery conductors. The resistive losses are proportional to the square of the load current and occur in the 66kV, 33kV, 11kV and 6.6kV and LV network conductors and in the zone substations and distribution transformers.
7.
Aurora notes that other components of loss arise from time to time including metering errors, theft, and sales. These are included in the overall calculated loss determined from the sales reports received from retailers. Hence, the loss ratio reported for information disclosure purposes is determined by subtracting metered data provided by retailers from grid exit point (GXP) data. Aurora notes that in its information disclosure document, it is unable to audit the metered data and has little confidence in the accuracy, and suggest that the ratio should be treated with great caution. 5
8.
Aurora’s methodology for determining loss factors is as follows:
9.
a.
the average of the last five years loss percentage for the distribution network (as declared for information disclosure purposes) is calculated;
b.
kWh lost is determined for the year;
c.
the total ‘fixed’ annual losses from zone substation and distribution substation transformers are determined;
d.
the total fixed annual losses are subtracted from the total kWh lost to determine the variable losses;
e.
variable losses are allocated to each half hour of the year using the total network demand for each half hour;
f.
the fixed component is added back on to give the kWh loss for each half hour; and
g.
from this the loss factor is calculated for each half hour.
The loss factor includes both technical and non-technical loss factors, Aurora attempts to differentiate the losses , however, the variable losses determined do include a portion of non-technical errors.
Vector 10.
4
Vector has three measures of losses: 6 a.
technical losses (line resistance, transformer resistance, harmonic currents, unbalanced loading and high resistance joints);
b.
observed losses (technical losses, plus non-technical losses such as metering errors incorrect meter installations, and theft); and
“Aurora Energy Ltd Loss Factors”, 1 October 2006, http://www.electricity.co.nz/download/2006_LossFactors.pdf 5 2006 Information Disclosure, Aurora Energy Ltd, http://www.electricity.co.nz/download/ID06.pdf 6 Auckland Network Loss Factor Review, Daniel Gill, Tim Jackson and Ashok Parsotam, Vector, 01/11/04
c.
published losses (a weighted average of the losses based on the loss factors published on the registry).
11.
Vector identifies two key components of technical losses, and these are defined the same as done by Aurora in paragraph 6.
12.
Vector notes that technical losses on the Auckland network range between 4% and 5%, and that the reason these are lower than those in other lines companies is due to Vector’s higher customer population and energy density.
13.
Vector’s methodology for determining loss factors is as follows: a.
network power and energy losses are estimated for every month of the previous calendar year;
b.
DigSILENT Powerfactory network modelling software is used to calculate losses in the sub-transmission and 11kV distribution networks (to LV terminals of distribution transformers) – load data from SCADA tables is used for these calculations;
c.
The following methodology is used: i.
conductor temp = 20 deg C;
ii.
all loads are balanced across 3 phases;
iii.
average values for transformer load and no load losses are used for transformer loss calculations;
iv.
losses in 11kV distribution network calculated based on feeder maximum demand load scaling since actual loads at distribution transformers are either not recorded or not available at this stage;
v.
the network topology of the network model is assumed to be static, i.e. switching and changes in the normally open points in feeders are not modelled to reflect changes in few feeder loads. The error in the overall loss estimate due to this assumption is relatively small;
vi.
only direct current (DC) resistance is taken into account. The true network loss is caused by alternating current (AC) current. Although the 50 Hz AC current is dominant in the sub-transmission and the 11kV networks, harmonic currents are increasing in the LV network which tends to further heat conductors and increase AC resistance of lines and cable and distribution transformer windings. Therefore losses would be marginally higher than estimated by using only DC resistance of conductors;
vii.
losses in street light supply cabling are not included in the estimate;
viii. estimated technical losses include a 10% allowance for above mentioned factors which could not be modelled explicitly; and ix.
losses in the LV lines and cables are estimated based on historical calculations.
Unison 14.
7
Unison notes 7 that technically, loss categorisation is performed by looking upstream from loads to differentiate between the connectivity of loads to
“System Loss Allocation”, Unison, 7 March 2007
different network component types which are responsible for different losses. Once deemed to connect, directly or indirectly, to a particular network component type, all loads connected will be treated as if supplied from an equivalent circuit, where all loads share the energy loss across that equivalent circuit. The loss of an equivalent circuit of a particular component type is the sum of all losses across all components belonging to that group type. 15.
The apportionment of the share of losses between loads is based on the energy metering information at the customer’s connection. The factors of physical locations of loads and different load profiles are not taken into account. The apportionment of variable losses involves two terms: the mutual and self terms, while the apportionment of fixed losses is performed linearly.
16.
The fixed losses on Unison’s network assets are caused by following components:
17.
a.
33/11kV transformer no-load losses (estimated from the average representation of loss in kW per MVA transformer capacity based on test certificates of a sample of transformers – the losses are recorded when the transformers are tested on nominal tap and energised to nominal voltage); and
b.
11kV/400V transformer no-load losses (determined using an empirical formula).
The variable losses on Unison’s network assets are caused by following components: a.
33kV line copper losses;
b.
11kV line copper losses;
c.
33/11kV transformer copper losses;
d.
11kV/400V transformer copper losses;
e.
low voltage network losses;
f.
customer service mains losses; and
g.
contact losses.
33kV and 11kV line losses 18.
Line losses are determined by running a non-linear load flow with all the relevant network components being modelled in the equivalent steady-state. Theoretically, an accurate evaluation of steady-state line losses would require numerous runs of load flow with ample data samples for every nodal load in the network. Unfortunately, Unison suggests this is not possible with most distribution utility computation resources. Under this circumstance, the load flows are run under the equivalent root mean square (RMS) loading. Generally, the RMS equivalent method provides good estimations if the nodal load profiles are strongly correlated.
11kV/400V transformer copper losses 19.
The full-load copper losses of a transformer are determined from the empirical formula: L=-2.8143ln(r)+24.691 watts.
LV distribution losses
20.
21.
With respect to determining LV distribution losses, a distinction is made between LV distribution and LV service mains. All the LV distribution cannot yet be practically modelled at this stage, so Unison has made some assumptions in order to estimate these losses: a.
suburban areas contribute to most LV distribution losses;
b.
a sample of randomly chosen suburban distribution substation LV reticulation areas are modelled in each city of Napier, Hastings, Rotorua and Taupo;
c.
to estimate losses, it is assumed that each ICP has a coincidental demand of 3.5kW is chosen as a typical value found as the after diversity load for 20 or more domestic consumers.
The above assumptions give an annual 26.1% load factor and a 0.11 loss load factor. A simple load flow model of the LV feeders is obtained from the sample substation, and the load flow model is run and the value of losses obtained. These losses are calculated as a percentage of the consumption per consumer.
Service mains and contact losses 22.
According to Unison, an accurate assessment of service mains losses is currently not feasible and therefore estimations are used. Contact losses are also estimated, using a formula.
Miscellaneous losses 23.
Unison call the non-technical losses on the network (meter error, theft, etc), ‘miscellaneous’ losses, and note that they represent the difference between the sum of the above losses and the actual system loss.
APPENDIX THREE: THE AUSTRALIAN LOSS FACTOR REGIME
National Electricity Rules 1.
The requirements of the National Electricity Rules (NER) are: a.
Loss factors must be determined for all connection points either on a sitespecific basis, or collectively in relation to connection point classes. Site specific loss factors will be determined for a connection point: i.
for an embedded generating unit with actual generation of more than 10MW;
ii.
for an end-user with actual or forecast load of more than 40GWh or an electrical demand of more than 10 MW;
iii.
for a market network service provider; and
iv.
between two or more distribution networks.
b.
Allocation of connection points to either a single transmission network connection point or to a virtual transmission node and to a class of distribution network connection points.
c.
The principles that must be applied to the methodology are as follows: i.
the total amount of energy calculated in relation to a distribution network (as adjusted for losses by the relevant loss factor) for a particular financial year is as close as reasonably practicable equal to the total metered or estimated energy flowing through all connections points in the distribution network and the total (actual) electrical energy losses incurred on the distribution network in the financial year;
ii.
the extent to which the objective above has been achieved must be demonstrated through a reconciliation based on the previous financial year’s adjusted gross energy and loss factors, i.e. by a reconciliation between the aggregate adjusted gross energy at all customer connection points on the distribution network in the previous financial year (applying the loss factors set for that previous year) and the sum of the total metered energy at those points in that year plus the total (actual) losses incurred on that network in that year;
iii.
for non-site specific connection points, determine the loss factor by using a volume-weighted average of the average electrical energy loss between the transmission network connection point, or virtual transmission node to which it is assigned, and each distribution network connection point in the relevant class of distribution network connection points for the financial year in which the loss factor is to apply;
iv.
for site specific connection points, determine the loss factor by reference to the average electrical energy loss between the distribution network connection point and the transmission network connection point to which it is assigned in the financial year in which the loss factor is to apply;
v.
the most recent actual load and generation data available for a consecutive 12 month period must be used to determine the average electrical energy losses referred to above, adjusted if necessary to take into account projected load and or generation growth in the financial year in which the distribution loss factors are to apply; and
vi.
treat flows in network elements that solely or principally provide market network services as invariant.
2.
Once Australian distributors have determined the loss factors, distributors must submit them to the appropriate regulator for approval in time for the National Electricity Market Management Company Ltd (NEMMCO) to publish by 1 April of each year. 8
3.
The New South Wales and Queensland regulators have not determined a loss factor methodology. Each distributor in these states must therefore develop, publish, and maintain a methodology in accordance with the NER.
4.
In Victoria, however, distributors have adopted a common methodology with some small difference, which take into account any individual features of the different networks and data management systems. The methodology was developed by the Victorian Distribution Loss Factor Working Group (made up of the five distributors and the former Victorian Power Exchange, with the involvement of the regulator).
New South Wales Regulator requirements 5.
As well as the principles outlined in the NER, the Independent Pricing and Regulatory Tribunal (IPART) has determined that distributors must satisfy the tribunal that: 9 a.
the levels of losses are consistent with that of a well-managed network;
b.
calculation methodologies are uniform and consistent with methodologies used previously; and
c.
appropriate allowance has been made for theft and metering inaccuracy.
6.
IPART may also undertake public consultation and engage a consultant to assist in assessing the proposed loss factors. If a distributor makes a material change in its methodology, it must give reasons for the change and explain how the proposed methodology differs from that used in the previous year.
7.
IPART specifies a typical methodology to assist distributors with the calculation of loss factors, namely:
8
a.
review the historical energy consumption of the entire network;
b.
review the historical actual overall energy losses of the entire network based on the total energy purchased, the total metered energy sale, estimated un-metered energy sales and allowances for theft and faulty metering equipment;
These can be found at http://www.nemmco.com.au/transmission_distribution/171-0014.htm “Assessment and Approval Process of Distribution Loss Factors proposed by DNSPs for 2007/08”, IPART, December 2006 9
8.
9.
c.
forecast the total energy consumption for the next financial year;
d.
forecast the overall energy losses based on historical data, planned changes to network configurations, customer load patterns (‘top-down’);
e.
compare the forecast ‘top-down’ overall losses with the calculated ‘bottom-up’ estimation of total energy losses by multiplying the individually forecast energy consumptions of site-specific customers and the forecast consumptions of all other customers by the estimated loss factors; and
f.
adjust the estimated loss factors by scaling so that the total ‘bottom-up’ losses equal the ‘top-down’ forecast of overall energy losses.
IPART also specifies that the distributor’s methodology paper should contain: a.
how the distributor determined the proposed loss factors;
b.
how the methodology used by distributors complies with the NER; and
c.
the information required for the assessment of the proposed loss factors, namely: i.
detail that the loss factors are forward looking estimates;
ii.
reconciliation of forecast and actual losses;
iii.
how the distributor estimated losses (total technical and nontechnical losses, network losses by voltage level);
iv.
how the distributor allocated losses at each voltage level; and
v.
comparison of current and proposed loss factors.
IPART commissioned a consultant (Intelligent Energy Services) to determine and explain a standard and compliant methodology for the calculation of loss factors. The report can be viewed at: http://www.iprt.net/papers/IES_DLF0904.pdf
NSW Distributor: EnergyAustralia 10.
The steps taken by EnergyAustralia for the calculation of its non-site-specific loss factors are as follows (more detail can be obtained at http://www.ipart.nsw.gov.au): 10 a.
reconciliation of the previous financial year by subtracting ‘purchases’ from ‘sales’;
b.
estimation of losses for the year in which the loss factors are to apply using the most recent data available. This data is adjusted to reflect factors such as anticipated seasonal load variability and to account for any differences demonstrated by the previous financial year’s reconciliation;
c.
determination of the volume weighted average of the average electrical energy loss for connection points – an engineering calculation is done to determine the anticipated losses for each asset category. Once this allocation takes place, any remaining proportion of losses is allocated to unread meters and accrual. This accrual is allocated to the LV network.
10 ‘Distribution Loss Factor Calculation Methodology Paper’, EnergyAustralia, February 2007 (http://www.ipart.nsw.gov.au/files/EnergyAustralia%20DLF%20methodology%20February%202007%20v1.1.P DF)
Distribution losses for non-site-specific connection points are considered in categories, related to the functional part of the network, and are estimated using the following approaches: Loss element
Series loss
Shunt loss
Transmission (parallel 132 kV)
Transformer substation and typical shunt
Radial 132 kV network
Negligible
132/66 and 132/33 substations
TPRICE simulation
Transformer substation and typical shunt
ST networks
Negligible
Zone substations
Transformer substation and typical shunt
HV network
Sample studies, peak and loss load
Negligible
Distribution substations
Transformer count, load and loss load
Transformer substation and typical shunt
LV network
Loadflow on a sample LV networks
Negligible
Meters and load control
Negligible
Device count typical shunt
Non technical losses
Residual calculated purchases less sales
Series (or copper) losses occur in the network connection between generator(s) and load(s) due to the resistance to electrical flow and vary with the power supplied to the load. Series losses tend to follow a “square law”, in that the series loss in a simple network is proportional to the square of the current supplied to the load. Shunt (or iron) losses are a “leakage” of energy (mainly associated with the connection of transformers and other equipment to the network) and occur regardless of the flow of power to the load.
d.
a portion of each asset class’s losses is then allocated to customer classes. For example, a certain amount of losses relates to 33kV underground and overhead feeders. Some of those losses are caused by domestic customers load further below in the network. The allocation of asset losses to customer class is carried out based on a pro rata energy allocation as well as considering each customer class peak, shoulder and off peak energy mix and their average power factor. Having carried out this allocation, the calculation of loss factors at this point is then a simple case of taking the losses, dividing by the total energy for that customer class and adding one; and
e.
EnergyAustralia make the point that the year-on-year variation of (purchases-sales) is significant, due to the effect of seasonal loading, particularly relating to the winter/summer cycle of heating/cooling load for SME and domestic customers. The other key effect in this instability is related to comparing “entering” energy, measured up to the hour, against ‘exit’ energy, smeared across a quarterly billing cycle. This makes it difficult to determine loss factors which provide a result that seeks to ensure that the total amount of energy calculated in relation to a distribution network (as adjusted for losses by the relevant loss factor) for a particular financial year is as close as reasonably practicable equal to the amount of electrical energy flowing through all connection points in the distribution network and the total electrical energy losses incurred on the distribution network in the financial year. For this reason, Energy Australia applied a methodology from 2000 to 2004 whereby the
distribution losses were calculated on the basis of a five-year rolling average. For 2005, this method was modified to be carried out on a three year rolling average. This methodology was accepted by IPART and the consequent loss factors were approved by IPART. In calculating loss factors from 2006 to 2007 however, EnergyAustralia moved away from the rolling average methodology as this approach had shown not to be responsive enough and had introduced a consistent under signalling of losses from 2001 to 2005. To address the under signalling, rather than an average, the most up to date full year losses for FY04 of 5.32% was used as a basis for calculating loss factors for 2006 (extra billing data demonstrated an overall loss factor of 5.36% for 2004). This methodology was accepted by IPART and the subsequent loss factors were approved. 11.
12.
The method EnergyAustralia use to calculate its site-specific loss factors is as follows: a.
EnergyAustralia calculates site-specific loss factors using the cost allocation software TPrice. TPrice is used in the National Electricity Market (NEM) for the allocation of transmission costs and the calculation of Transmission Loss Factors by NEMMCO.
b.
EnergyAustralia uploads the full topology of the network down to the 11kV busbar of each zone substation and then also down to each customer of greater than 10MW usage, in to TPrice. This covers line impedances, connections, transformer impedances, and standard operating conditions. Each customer’s load profile from metering data is uploaded, and each zone substation has a deemed load profile applied and uploaded in to TPrice as well. TPrice then runs a loadflow for each hour of the year. Any loadflow must calculate losses as part of its calculation of energy flows, since a loadflow cannot converge to a solution without all power flows balancing.
c.
TPrice then collates the results and calculates the total losses attributable to each large customer. It does this by allocating upstream shared losses on a total energy basis. For example, consider a substation that a large customer connected but with other load connected as well. Consider that TPrice has determined electrical losses on the substation of 100MWh over the year and substation saw 20,000MWh of load pass through it during the year. The large customer connected downstream used 500MWh, then the losses through the zone substation attributed to the large customer are: 100MWh x 500/20,000 = 2.5MWh. This method is applied to all upstream assets such that the large customer receives a portion of losses all the way along the supply chain.
d.
For information about calculation of subtransmission network series losses, subtransmission network shunt losses, high voltage network series losses, distribution substation series losses, and meters and load control device shunt losses see EnergyAustralia’s distribution loss factors methodology paper (found at http://www.ipart.nsw.gov.au).
EnergyAustralia defines non-technical losses as including fraud, and metering, data and information system deficiencies. EnergyAustralia uses approximately 150 compact recording instruments (theft monitors). These are installed in the street to check the meter readings at premises under investigation. Recently, this process was expedited by taking special meter readings at such premises,
allowing many checks to be completed in a matter of weeks rather than a full three-monthly billing cycle. EnergyAustralia suggests that non-technical losses are simply the left over portion of losses that cannot be attributed to the electrical network. Once technical losses have been determined, it can be expected that a small amount of overall system losses is unaccounted, and must therefore be attributed to fraud, meter reading errors and other minor billing errors. All non-technical losses are assumed to take place on the low voltage network and therefore are attributed to this class of customer. Victoria Regulator requirements 13.
The Victoria regulator, the Essential Services Commission (ESC), specifies the methodology to be used by distributors in Victoria. Details of this methodology can be found at http://www.esc.vic.gov.au/NR/rdonlyres/76075646-8A4C40E6-9BCDD2D203A05C1B/0/GLGuidanceDLFcalculationmethodology20070207.pdf, The steps that distributors in Victoria must follow are set out below.
14.
For site-specific loss factors for large customers, the following method is used:
15.
a.
calculate all upstream losses from the site-specific customer’s point of supply to the transmission network connection point (being the relevant terminal station);
b.
determine the total energy sales at each segment of the distribution network upstream from the customer;
c.
determine the fraction of the total upstream energy sales associated with the site-specific customer. This can be calculated by dividing the energy sales of the customer by the total energy sales at each segment of the distribution network upstream;
d.
multiply the percentages calculated in (c) by the energy losses calculated in (a) to determine the amount of losses at each segment that are attributable to the site-specific customer. Add these together to get the total distribution network losses attributable to the site-specific customer;
e.
calculate the site-specific loss factor as: 1 + (the total energy losses attributable to the site-specific customer) / (total energy sales to the sitespecific customer);
For network average loss factors for general customers and small embedded generators, the following method is to be used: a.
distribution losses are grouped into five major segments of the distribution network. Customers should pay for the losses based on which of the five segments are used to supply their power;
b.
the five network segment categories are: i.
Category A: Sub-transmission feeders operating at 66 kV or 22 kV (note: 1 kV = 1000 Volts);
ii.
Category B: Zone substations operating at 22 kV, 11 kV or 6.6 kV;
iii.
Category C: HV distribution feeders operating at 22 kV, 11 kV or 6.6 kV;
Category E: Distribution substations operating at 240/415 V; and
v.
Category E: Low voltage (LV) feeders operating at 240/415 V;
c.
a customer connected to the low voltage network utilises all upstream assets, causing electrical energy losses in each network segment upstream of its connection point. Customers connected to sub-transmission feeders, however, only cause losses on the sub-transmission network;
d.
each customer should be categorised as A through to E depending on the customer’s connection point to the network and the location of the metering point;
e.
energy losses can be calculated for each network segment. Once the losses in each segment are determined, the total losses attributable to a customer class can be determined by combining all upstream losses from the customer’s point of supply to the terminal station (transmission network connection point) similar to the calculation process of sitespecific loss factors. Distribution loss factors (DLF) are then calculated for each category A to E;
f.
16.
iv.
i.
DLF-A is the distribution loss factor to be applied to a second tier customer or market customer connected to a sub-transmission line (at 66 kV or 22 kV);
ii.
DLF-B is the distribution loss factor to be applied to a second tier customer or market customer connected to the lower voltage side of a zone substation at voltages of 22 kV, 11 kV or 6.6 kV;
iii.
DLF-C is the distribution loss factor to be applied to a second tier customer or market customer connected to a distribution line from a zone substation at voltages of 22 kV, 11 kV or 6.6 kV;
iv.
DLF-D is the distribution loss factor to be applied to a second tier customer or market customer connected to the lower voltage terminals of a distribution transformer (at 240/415 V);
v.
DLF-E is the distribution loss factor to be applied to a second tier customer or market customer connected to a low voltage line at 240/415 V; and
separate loss factors must also be calculated for each of the DLF categories A to E depending on whether the length of the subtransmission line supplying the customer is ‘short’ or ‘long’. This creates a total of ten loss factors per distributor. A short sub-transmission line is defined as a radial sub-transmission line where the route length of the line is less than 20 km; or a sub-transmission line in a loop where the total route length of all lines in the loop is less than 40 km. All other long sub-transmission lines are defined as ‘long’.
For site-specific loss factors for large embedded generators, the following method is to be used: a.
model the operations of the generator based on historical record or other relevant information available;
b.
determine the relevant forecast network losses by modelling the distribution network between the generator’s connection point and the
transmission network connection point for each modelled operating period of the generator; c.
calculate the annual overall loss factor utilising a volume weighting factor based on the forecast average electrical energy loss for each modelled operating period of the generator in the financial year in which the loss factor is to apply.
17.
The ESC noted that a consistent approach to the choice of weighting factor is essential to achieving consistency in regulation and to provide a level playing field for competition in embedded generation. In the past, the ESC has approved some site-specific loss factors for embedded generators where losses have been expressed as a percentage of consumer sales, that is: loss factor = 1+losses/sales. This is consistent with how network average losses are weighted when determining loss factors for small embedded generators and general customer loads, and is appropriate when the volume of sales is very much larger than the generator’s output volume.
18.
However, a problem arises when the output volume of the generator is larger than the energy consumed by customers in that part of the network between the generator and the transmission connection point. In such circumstances, there is a net export of energy from the generator into the transmission network connection point and the loss factor could be less than zero. As a loss factor represents losses in a network and losses are always present to some extent; it is evident that a loss factor must always be a positive number and therefore expressing losses as a percentage of sales in some circumstances is not an appropriate approach.
19.
The ESC requires that the loss factor be determined using the following formula: 1 + Losses/ (magnitude of sales less generation). This volume weighting is consistent with treating a generator as a negative load in network load flow modelling and allows a consistent approach to be adopted and an appropriate loss factor to be developed in all likely operating conditions.
Queensland Regulator requirements 20.
In Queensland, the approach adopted by the Queensland Competition Authority (QCA) has been to engage independent advice to assess the distributors' methodologies (particularly their load flow calculations). The QCA revisits this assessment every three years. In intervening periods, the QCA audits the calculated loss factors submitted by the distributors to ensure these are calculated consistent with the approved method. The QCA told us that as part of this process they have not encountered any problems of note.
Queensland distributor: Energex 21.
11
The methodology used by Energex 11 for site-specific customer calculations is as follows:
http://www.energex.com.au/network/deregulation/distribution_loss_factor_methodology.html
22.
a.
regardless of whether a full re-calculation of loss factors is being undertaken (every third year), or only a review, the methodology for determining loss factors for site-specific customers is identical;
b.
site-specific loss factors are calculated using load flow analysis based on the customers forecast demand data and network load data for the year in which the loss factors are to be applied. The analysis involves load flow studies on the directly connected network between the customer connection point and the transmission network connection point. The directly connected network is defined as all network which will experience a change in power flow due to a change in customer loads. In addition, iron losses of the transformers included in the directly connected network are calculated and apportioned based on the ratio of customer load and network load flowing through the transformer; and
c.
Energex uses the marginal loss factor methodology to calculate sitespecific loss factors. This process involves determining the losses for the customer by assessing the relativity between the change in system load associated with a change in the customer's load.
The methodology used for the calculation of average loss factors is as follows: a.
average loss factors are calculated for each significant supply level in the network, with loss factors for major customers being calculated individually in order to determine the losses directly attributable to their loads. The average loss factors categories applied by Energex are: i.
132/110 kV Network;
ii.
33 kV Network;
iii.
11 kV bus;
iv.
11 kV line;
v.
LV bus; and
vi.
LV line;
b.
the method used to calculate average loss factors is to carry out a series of load flow studies to determine the losses at the coincident network peak, followed by the application of calculated Loss Load Factors (LLFs) to obtain the actual losses;
c.
the transmission and subtransmission systems are modelled using appropriate load flow packages. Losses on the 11 kV distribution system are calculated using forecast feeder peak demand data and feeder length data which is obtained from Energex’s corporate database. Losses at the LV bus are calculated based on the average impedance of distribution transformers, and losses in the LV network are calculated as the difference between the total losses (calculated by the difference between total purchases and total sales), and the losses resulting from the higher voltage network studies;
d.
the loss factors for the network are then calculated based on the formula: Loss factor = [losses (GWh) for section of network – ICC losses]/[sum of sales (GWh) for all sectors downstream and including that sector (excluding sales to ICCs)]
ICC = Individually Calculated Customers (all customers of greater than 10 MW demand or 40 GWh annual consumption). Feedback from Australian Regulators and Distributors 23.
The project team also received feedback from a few participants from Australia on the loss factor arrangements in Australia. Most participants that responded were largely happy with the arrangements. Some of the observations made were: a.
it might be worth investigating under what circumstances a distributor should be asked to create additional classes to increase differentiation (apparently there were some requirements that were removed from the Australian rules);
b.
one distributor said that it is not feasible to use the ‘most recent twelve months’ worth of data as they need to wait three to six months for all the meters to be read;
c.
in terms of site-specific loss factors, quite a few customers that were on site-specific loss factors went back to average loss factors after the introduction of the 10MW / 40GWh rule (i.e. that site-specific loss factors be calculated for end users with actual or forecast load of more than 40GWh or an electrical demand of more than 10 MW). It worked out well for the customer as they always ended up with a lower loss factor. It was one distributor’s view that it made the rules open to gaming, for example, a new mine in the middle of nowhere may avoid having to pay as much by splitting its proposed connection point into two;
d.
in terms of the site-specific method, one distributor did not think that the generic load loss factor method was accurate enough, especially where there were different load profiles. They felt that the calculation should be done half hour by half hour (the problem being that this requires specialist software to perform loadflow network simulation for every half hour in the year).
24.
One of the state regulators told the project team that there was some discussion between the jurisdictional regulators three or four years ago that there should be national consistency to avoid potential distortions in price signals on account of the use of different DLF methodologies across jurisdictions. It was decided, however, that this was not considered necessary. The current approach was deemed adequate for achieving the aim of capturing and allocating losses.
25.
In terms of the idea of adopting a more prescriptive approach than that adopted in Australia, one of the state regulators noted that in their experience, the only concern would be whether differences in distribution network characteristics should give rise to different approaches in the derivation of losses. Also, there was a concern that such an approach might not provide incentives (and conversely penalties) to promote more efficient losses and whether these should be included into the efficiency or regulatory mechanism.
APPENDIX FOUR: GUIDELINES ON THE CALCULATION AND USE OF THE LOSS FACTORS FOR RECONCILIATION PURPOSES
Guidelines on the calculation and the use of loss factors for reconciliation purposes v1.0 Version
Date issued
Comments/amendments made
1.0
15 June 2007
Draft for consultation
These guidelines have been produced to promote understanding and encourage consistency in the calculation methodologies and processes surrounding distribution loss factors. The general approach set out in this information guide in no way reduces the requirement upon participants and comply with their obligations under the Electricity Governance Rules 2003 (Rules). These guidelines do not necessarily reflect the Electricity Commission’s (Commission) views about the Rules.
Background 1.
As required under the Government Policy Statement on Electricity Governance, the Commission should, whenever possible, use its powers of persuasion and promotion, and provision of information to achieve its objectives rather than recommending regulations and rules.
2.
These guidelines are therefore recommended for use by distributors when calculating and publishing distribution loss factors for the purposes of reconciliation.
Defined terms 3.
The following defined terms are used in these guidelines: “loss category code” means the relevant code in the schedule published by the registry which identifies the relevant loss factors that apply to submission information; “loss factor” means the factor applied to consumption information at the ICP or NSP (for an embedded network) to allow for losses within the local network or embedded network to produce equivalent consumption information at the relevant NSP; “non-technical loss factor” means, a loss factor that represents the difference between reconciliation losses and technical losses. These losses represent inaccuracies caused by measurement and data handling and include metering and reading errors, incorrect meter installations, theft, and unread meters. Identification and quantification of this component, facilitates
investigation into these inaccuracies, and a subsequent reduction in the loss factor; “technical loss factor” means a loss factor that represents the electricity that is consumed during the delivery to consumers’ installations. The technical loss factor represents There are two main technical components to the loss: •
a fixed component that arises from the standing losses of the zone substation and distribution transformers; and
•
variable components arising from the heating effects of the resistance in the delivery conductors. The resistive losses are proportional to the square of the current and occur in the high voltage (HV) and low voltage (LV) network conductors, the zone substations and distribution transformers;
Identification and quantification of this component, facilitates investigation into improvements that are available to these components, and a subsequent reduction in the loss factor; “reconciliation loss factor” means, a loss factor that represents the difference between the delivered electricity at one point of connection and the electricity required to be injected into any other point of connection in order to supply the delivered electricity. This loss factor is used in: •
the reconciliation process by the reconciliation manager to allocate volumes of electricity at grid exit points to participants (both buyers and sellers from/to the clearing manager; and
•
the retail pricing process by retailers for electricity purchases and in the case of grid exit point (GXP) charging networks, the calculation of network charges.
Distributor loss factor obligations 4.
Distributors must calculate and publish reconciliation loss factors for each loss factor code in the registry each year.
5.
Distributors must calculate and publish on their website both technical and non-technical losses and loss factors for each loss factor code that they have used in the registry each year.
6.
Technical loss factors will be reviewed every five years (unless there is a significant change in network configuration and/or load in which case the review will be re-run), although they will still need to be reported each year to the Commission.
7.
Non-technical loss factors will be reviewed every year (using a sliding window of two years’ generation and consumption information), and reported each year to the Commission.
8.
Distributors will submit to the Commission the technical and non-technical and reconciliation loss factors (the format for this is detailed further below), and the loss factor methodology used to determine loss factors for the next financial year, prior to 1 March of each year.
9.
Distributors will satisfy the Commission that the levels of losses are consistent with those of a well-managed network.
10.
Should the Commission disagree with the loss factors calculated, the Commission will refer the issue to the Loss Factor Review Panel (LFRP), who will provide advice to the Commission on the distributor’s compliance with these guidelines. In the event that the Commission considers that the loss factors are not calculated in accordance with the guidelines, the distributor will re-calculate the loss factors.
Q5.
Are one year (for non-technical loss factors) and five years (for technical loss factors) the appropriate timeframes within which to review loss factors? Please give reasons for your view.
Retailer loss factor obligations 11.
In order to enable distributors to accurately calculate loss factors, retailers shall provide the following to distributors by 31 July each year, for the 12 month period to 1 April of that year: a.
Prior to 1 May 2008 – annual billing information, normalised, and summarised by network supply point; and
b.
After 1 May 2008 - annual summarised reconciliation manager submission information by network supply point and loss category code.
Creation and population of loss category codes on the registry 12.
Loss factor codes are used in the installation control point (ICP) records on the registry to indicate to retailers, data administrators and the reconciliation manager which loss factors apply for settlement purposes. Retailers also use this code for the allocation of retail tariffs.
13.
Loss factor codes need to be unique to each loss factor, and the numbering system employed by distributors is to ensure that these codes are unique. The number of characters must not exceed that allowed by the registry.
Q6.
Do you think that the loss category code needs to be standardised? Please give reasons for your view.
Distributor loss factor methodology obligations 14.
Distributors will submit to the Commission the technical, non technical and reconciliation loss factors calculated (format noted below) and the loss factor methodology used to determine loss factors for the next financial year prior to 1 March of each year.
15.
The loss factor methodology applied by distributors in accordance with paragraph 8 must meet the following criteria: a.
Site-specific loss factors will be determined for a connection point: i.
for an embedded generating unit with actual generation of more than 10MW;
ii.
for an end-user with actual or forecast load of more than 40GWh or an electrical demand of more than 10 MW;
iii.
for a market network service provider; and
iv.
between two or more distribution networks.
Site-specific loss factors may be calculated for generation or consumption at levels lower than the above at the discretion of the distributor. b.
Different loss factors will be calculated for different voltage levels (as the distributor deems appropriate).
c.
Distributors will conduct load flow studies to assist in determining technical loss factors.
d.
The average used to determine reconciliation loss factors will be two years.
e.
The total amount of energy calculated in relation to a distribution network (as adjusted for losses by the relevant loss factor) for a particular financial year will be as close as reasonably practicable equal to the total metered or estimated energy flowing through all connections points in the distribution network and the total (actual) electrical energy losses incurred on the distribution network in the financial year.
f.
Distributors will demonstrate the extent to which the objective above has been achieved through a reconciliation based on the previous financial year’s adjusted gross energy and loss factors, i.e. by a reconciliation between the aggregate adjusted gross energy at all customer connection points on the distribution network in the previous financial year (applying the loss factors set for that previous year) and the sum of the total metered energy at those points in that year plus the total (actual) losses incurred on that network in that year.
g.
For non-site-specific connection points, the loss factor is to be determined by using a volume weighted average of the average electrical energy loss between the transmission network connection point or virtual transmission node (or in the case of embedded networks the gateway meter point/points) to which it is assigned and each distribution network connection point in the relevant class of distribution network connection points for the financial year in which the loss factor is to apply.
h.
For site-specific connection points, the loss factor is to be determined by reference to the average electrical energy loss between the distribution network connection point and the transmission network connection point to which it is assigned in the financial year in which the loss factor is to apply.
i.
Distributors are to use the most recent actual load and generation data available for a consecutive 24-month period to determine the average electrical energy losses referred to above, adjusted where necessary to take into account projected load and or generation growth for the year in which the distribution loss factors are to apply.
Derivation of losses 16.
Losses and loss factors are to be derived as follows for each network area:
a.
Gross electricity (Gr) flow is to be determined using the immediate past 24 months embedded generator and customer point of connection injection and consumption information for an electrically connected network area.
b.
Technical losses (TL) – this is to be the determined for an electrically connected network area by load flow studies as determined above, allocated to each loss category code.
c.
Reconciliation losses (RL) – this is to be derived from the immediate past 24 months injection and consumption information for an electrically connected network area, allocated to each loss category code.
d.
Non Technical Losses (NTL) – this is to be derived using the equation NTL = RL - TL
e.
Technical loss factor (TLF) – this is to be derived using the equation TLF = 1+(TL/Gr)
f.
Reconciliation loss factor (RLF) – this is to be derived using the equation RLF = 1+(RL/Gr)
g.
Non technical loss factor (NTLF) – this is to be derived using the equation NTLF = 1+(NTL/Gr)
Q7.
Do you agree with the methodology for the derivation of loss factors in the draft guidelines? Please give reasons for your view.
Loss Factor Review Panel 17.
A technical panel called the Loss Factor Review Panel will be established by the Commission to deal with any issues that may arise with loss factors and loss factor methodologies used by distributors.
18.
The Loss Factor Review Panel will be made up of an independent chair and two independent members with expert knowledge of the determination of losses and a Commission representative.
19.
The Loss Factor Review Panel will report to the Commission.
Distributor loss factor report 20.
Distributors must submit to the Commission their proposed loss factors for the next financial year prior to 1 March of each year regardless of any change or not. The following information must form part of a distributor’s submission: a.
a declaration that the proposed loss factors have been calculated based on the Commission’s loss factor calculation guideline;
b.
the proposed site-specific loss factors for large customers and embedded generators requiring site-specific loss factors;
c.
the network average loss factors for all other customers and embedded generators;
21.
d.
a statement of the reconciliation result in terms of over/under allocation of losses from the application of loss factors for the previous financial year; and
e.
a statement of the overall losses of the distributor’s network.
The distributor’s report must be in the CSV format specified below
Distributor four letter code assigned by the Market Administrator
Q8.
GXP losses factors applicable to
Loss category code used in the registry
Technical loss factor (TLF)
Year in which technical loss factor last calculated
Non technical loss factor calculated (NTLF)
Reconciliation loss factor (RF) calculated each year using a sliding two year window of generation and consumption
Description of customer group that loss category code is applicable to
Are there any other comments or concerns you wish to raise about the draft guidelines?
APPENDIX FIVE: QUESTIONS ON WHICH SUBMISSIONS ARE INVITED
Questions on which submissions are invited Below is a compiled list of the questions shown throughout the consultation paper and its appendices, as well as some additional questions on which the Commission invites submissions. Q1
Do you agree with the definitions and uses of reconciliation, technical and non-technical loss factors set out in this paper? Please give reasons for your view. (See paragraphs 18, 19, and 21.)
Q2
Do you agree with the criteria developed by the project team against which proposed loss factors arrangements should be assessed? Should one or more criteria be added or deleted? Please give reasons for your view. (See paragraph 42.)
Q3
Are there any options for future loss factor arrangements other than the four options identified in this paper? Please give reasons for your view.
Q4
Do you agree that Option Three should be implemented (mandatory estimation of both technical and non-technical loss factors)? Please give reasons for your view.
Q5
Are one year (for non-technical loss factors) and five years (for technical loss factors) the appropriate timeframes within which to review loss factors? Please give reasons for your view.
Q6
Do you think that the loss category code needs to be standardised? Please give reasons for your view.
Q7
Do you agree with the methodology for the derivation of loss factors in the draft guidelines? Please give reasons for your view.
Q8
Are there any other comments or concerns you wish to raise about the draft guidelines?
Q9
The calculation of reconciliation loss factors, and hence non-technical loss factors, relies on the availability of retailers' records of how much electricity has been consumed. Do distributors have access to this information from retailers?
July 2007
Purpose 1.
The purpose of this consultation paper is to obtain industry feedback on guidelines on the calculation of loss factors and the use of loss factors for reconciliation purposes.
Background 2.
The MARIA Governance Board (MGB) identified reconciliation as a strategic priority area for MARIA for 2002/03. In August 2002, the MGB appointed members to a MARIA Reconciliation Project Team (RPT) to advise the MGB on how to ensure that the reconciliation process produced accurate, complete and timely information in a cost-effective manner. The MARIA RPT undertook a fundamental assessment of the problems associated with the reconciliation process, and proposed a solution and a framework for implementing its reconciliation recommendations. This included the establishment of both an implementation team and a project reference group.
3.
The Electricity Commission (Commission) recognised the importance of completing the work previously undertaken on reconciliation and, as a result, the implementation team established under MARIA was continued as the EC Reconciliation Project Team (ECRPT), which was appointed to make recommendations to the Commission.
4.
It was recognised during the work of both the MARIA RPT and the ECRPT that there would be benefits from a consistent approach to the calculation of distribution loss factors.
5.
A series of workshops were held by the Commission in April 2005 in Auckland, Wellington, and Christchurch to assist participants with their understanding of the proposed reconciliation rules and arrangements. These workshops presented an opportunity to discuss issues raised by participants. One of the significant issues discussed was that of how loss factors are determined. Participants considered that the Commission should reinforce the need for a common methodology for calculating distribution loss factors with all distributors.
6.
New reconciliation rules have been approved, and will be implemented on 1 May 2008. It is envisaged that before this date, distributors will be required to have adopted and implemented the requirements contained in the loss factor guidelines that the Commission has developed.
7.
There is a need for a common methodology because of the importance of loss factors within the reconciliation process. Under the current Rules, incumbent retailers are exposed to the risk of incorrect calculation and application of loss factors. Under the new reconciliation arrangements, with the introduction of the concept of unaccounted for electricity (UFE), all retailers will be exposed to this risk. This change does not remove the need for loss factors, particularly in relation to the differentiation of losses between consumption groups. Accuracy
of loss factors is crucial to the accuracy of reconciliation, and the effects of this flow right through to retailer pricing.
Submissions 8.
The Commission invites submissions on the proposal by 5pm on Friday, 17 August 2007.
9.
The Commission’s preference is to receive submissions in electronic format (Microsoft Word). Submissions in electronic version should be emailed with ‘The calculation of loss factors and the use of loss factors for reconciliation purposes’ in the subject header to [email protected].
10.
If submitters do not wish to send their submission electronically, they should post one hard copy of their submission to the address below. Jenny Walton Electricity Commission Level 7, ASB Bank Tower 2 Hunter Street P O Box 10041 WELLINGTON Tel: (04) 460 8860 Fax: (04) 460 8879
11.
The Commission will acknowledge receipt of all submissions electronically. Please contact Jenny Walton if you do not receive electronic acknowledgement of your submission within two business days.
12.
Your submission is likely to be made available to the general public on the Commission’s website. Submitters should list any documents attached in support of the submission in a covering letter and clearly indicate any information that is provided to the Commission on a confidential basis. All information provided to the Commission is subject to the Official Information Act 1982.
Distribution loss factors 13.
A distribution loss factor, normally expressed as a multiplier, is used to estimate the difference between metered quantities at the input to a network and the sum of metered quantities at the meters of consumers averaged over a period of time. The loss factor is calculated as 1/(1-loss ratio) where the loss ratio equals the average proportion of losses over a network.
14.
The multipliers are used by electricity retailers (applied to half hour data) and the reconciliation manager (applied to non half hour data) to multiply the electricity volume recorded for retail consumers to determine each retailer’s responsibility for the purchase of electricity on that network. The loss factor is also used by retailers in determining their pricing plans.
15.
Although loss factors have a direct financial impact on individual consumers’ electricity costs, inaccuracies due to non-technical losses have no impact on the actual quantity of energy passing through (or to) any part of the electrical system.
16.
Large electricity distributors are required by the Electricity Information Disclosure Requirements (2004) to disclose the loss factors that apply to their networks and are also required by rule 8.1 of section VI of part G of the Electricity Governance Rules 2003 (Rules) to supply distribution loss factors for the reconciliation process to the reconciliation manager. There is currently no single industry-wide methodology for the calculation and periodic review of distribution loss factors.
17.
There are three different loss factor types, and the loss methodology guidelines define how each type is derived: a.
reconciliation loss factors;
b.
technical loss factors; and,
c.
non-technical loss factors.
Reconciliation loss factors 18.
Reconciliation losses (also known as observed or total losses) represent the difference between the delivered electricity at one point of connection and the electricity required to be injected in order to supply the delivered electricity. Hence, a reconciliation loss factor adjusts the consumption data submitted for reconciliation to produce equivalent metering data at a grid exit point (GXP). The reconciliation loss factor is comprised of two components – technical and non-technical, as discussed below.
Technical loss factors 19.
20.
Technical losses represent the electricity entering the network that is consumed during the delivery to consumers’ installations. There are two main technical components to the loss: a.
a fixed component that arises from the standing losses of the network transformers; and
b.
variable components that arises from the heating effects of the resistance in the HV and LV network conductors, zone substations and distribution transformers.
Information about technical loss factors (given accuracy limitations) may be used to: a.
value the electricity lost during delivery;
b.
allocate technical loss factors to different voltage tiers and locations; and
c.
monitor the effectiveness of changes to a distributor’s network or asset management methodology.
Non-technical loss factors 21.
Non-technical losses represent the difference between reconciliation losses and technical losses. These include metering errors, incorrect meter installations, theft, and unread meters.
22.
Information about non-technical loss factors (given accuracy limitations) may be used to: a.
value the electricity that may have been mis-allocated;
b.
allocate non-technical loss factors to different voltage tiers, locations, and customer classes; and
c.
identify areas where reduction in distribution losses may be possible by examining the reconciliation loss factor, and the accuracy of metering systems, data, or data handling techniques.
Q1. Do you agree with the definitions and uses of reconciliation, technical and nontechnical loss factors set out in this paper? Please give reasons for your view Unaccounted for electricity 23.
Unaccounted for electricity (UFE) means the quantity of electricity that is the difference between: a.
the quantity of electricity injected into a local network or embedded network; and
b.
the quantity of electricity consumed within that balancing area as indicated in the submission information after application of loss factors and adjustment for installation control point (ICP) days;
as calculated per trading period by the reconciliation manager. Current rule requirements 24.
The current Rules relating to the application of loss factors are: a.
part A: “loss category” means the relevant code in the schedule published by a distributor which identifies the relevant loss factors that apply to consumption information; … “loss factor” means the factor applied to consumption information at the ICP or NSP (for an embedded network) to allow for losses within the local network or embedded network to produce equivalent consumption information at the relevant NSP;
b.
rule 5.1 of section VI of part G: 5.1.1 Half hour consumption information to be adjusted for losses
Half hour consumption information provided pursuant to rule 5.2 will be provided from a metering installation and will be adjusted [by the data administrator], as appropriate, to provide for losses within the local network; 5.1.2 Non-half hour consumption information not to be adjusted for losses Non-half hour consumption information provided pursuant to rule 5.3 will be provided from a metering installation and will not be adjusted to provide for losses within the local network. c.
rule 8.1 of section VI of part G: Each distributor will advise the reconciliation manager and the relevant data administrator and retailer of the loss factors applicable to each loss category for each of its networks.
25.
Under the current reconciliation arrangements, distributors publish loss factors that are then applied to the metered data submitted by independent (non-incumbent) retailers. Any difference between the electricity injected into a local or embedded network and the total of the loss adjusted volumes from independent retailers is UFE and is attributed to the retailer assigned as the incumbent for that network.
New reconciliation rules (from 1 May 2008) 26.
The revised reconciliation rules that will come into effect from 1 May 2008 contain the following rules relating to the application of loss factors: a.
part A: “loss category” means the relevant code in the schedule published by the registry which identifies the relevant loss factors that apply to submission information; … “loss factor” means the factor applied to submission information to obtain loss adjusted information at the relevant NSP;
b.
schedule J4 of part J: This schedule sets out the reconciliation process performed by the reconciliation manager, and includes the following rules: rule 1.3, which sets out a requirement to apply loss factors to submission information for non half hour metered ICPs which have been adjusted for ICP days; rule 1.4, which sets out a requirement to apply loss factors to submission information for half hour metered ICPs which have been adjusted for ICP days; rule 7, which relates to the application of loss factors. It provides: the registry must provide the reconciliation manager with the loss factors for each loss category … and the reconciliation manager must, after adjustment for ICP days scaling and application of profiles, apply the loss factors to all submission information.
The reconciliation manager must apply loss factors to submission information in respect of embedded networks, and submission information in respect of parent networks for the appropriate reconciliation period; c.
rule 10, of part E, which sets out the requirement that distributors’ processes be audited. It provides that: [Each] distributor’s process and procedures that must be audited include… 10.3 the creation and maintenance of loss factors;
d.
rule 24.2.2 of part E, which requires loss factor reports to be provided to the reconciliation manager as follows: A report detailing the loss factor value(s) for each loss category code as recorded by the registry in respect of all trading periods;
e.
rule 5 of schedule E1 of part E, which relates to loss factors on registry and provides: 5.1
Distributors advise loss factors
Distributors must advise the registry of the loss factors for each loss category code on the registry. 5.2
Two loss factors per month
A loss category code may have a maximum of two loss factors per calendar month. Each loss factor must cover a range of trading periods within that month such that all trading periods have a single applicable loss factor. 5.3
Distributors to advise market administrator
Distributors must advise the market administrator of their intention to add new loss category codes or to change the value or applicable time period of any loss factor, at least three months before the change is to take effect, or new code being added. 5.4
Distributors maintain loss factors
Distributors must advise the registry of any change to any loss factor on the registry at least two calendar months before the change is to take effect. 5.5
Registry to publish loss factors
The registry must publish an updated schedule of all loss category codes and associated loss factors advised by the distributor in accordance with rule 5.4 within one business day of being notified of a change. 27.
Under the new reconciliation rules, distributors will publish loss factors that are then applied to the metered data submitted by all retailers. The UFE will be allocated to all retailers at the relevant network supply point (NSP), not just to the incumbent retailer, as is done currently.
Examination of current and alternative methods for calculation of loss factors Interviews with industry participants 28.
A number of interviews were held with the industry from February to April 2007 to collect information about how losses and loss factors are currently calculated and treated by distributors, as well as any concerns that industry participants have with regard to loss factors.
29.
A number of different approaches are currently used by distributors in calculating loss factors, and a range of concerns were expressed by industry participants. The findings from these interviews are detailed in Appendix One.
30.
The key issues with current loss factor practices in New Zealand are that there is a lack of: a. visibility as to how loss factors are derived; b. monitoring of losses and loss factors; c. understanding of loss factors and the purpose they serve; d. clarity in the definition of losses and associated terminology; e. consistency in the calculation of losses and loss factors; and f. incentives for distributors to reduce losses. 1
How New Zealand distributors calculate loss factors 31.
As illustrated by the information in Appendix one, a number of approaches are adopted by distributors when calculating loss factors for their networks. These approaches range from using a legacy loss factor that was determined before the structural separation of retail and distribution businesses, to the use of a comprehensive calculation model including information about half hourly data of annual loading patterns and the determination of the source of technical losses.
32.
Many distributors do not regularly review loss factors, as shown by the widespread use of loss factors determined prior to structural separation. In addition, a number of distributors merely stated what the loss factors are, rather than providing information as to how the loss factors were determined.
33.
Another common practice is the derivation of loss factors using GXP extraction data minus consumption information at that GXP. Distributors use an average of this information to determine the appropriate loss factors. The longest period of time used by a distributor over which an average is determined is five years. This means that no efforts have been made by some distributors to attempt to estimate what the ‘technical portion’ of these losses might be.
34.
There are a limited number of distributors that determine and publish the portion of their losses that can be attributed to technical losses despite the fact that it is widely recognised that determining technical loss factors is not an
1 The issue identified in paragraph 30(f) above on identifying ways to reduce distribution system losses is outside of the scope of this paper. However, if greater transparency results from this project, this will assist the Commission in considering ways to reduce distribution system losses.
exact science. Information from Orion, Aurora, Vector, and Unison on how their technical losses are estimated is included in Appendix Two.
Australian loss factor regime 35.
In order to understand what best practice may be for the treatment of losses and loss factors, the Commission has considered how they are treated in overseas jurisdictions. Australia was the most useful jurisdiction to consider. The state regulators in Australia take different approaches to losses and loss factors (although they are all governed by the National Electricity Rules 2 ).
36.
There was a general lack of information about the treatment of loss factors in countries other than Australia. This may be a result of those countries having different settlement regimes to those in Australia and New Zealand.
37.
The Australian jurisdictions (and the relevant regulators) that the Commission has considered in detail were: a. New South Wales: Independent Pricing and Regulatory Tribunal (www.ipart.nsw.gov.au); b. and
Victoria: Essential Services Commission (www.esc.vic.gov.au);
c. Queensland: Queensland Competition Authority (www.qca.org.au). 38.
The Commission briefly considered the treatment of losses and loss factors in the Australian Capital Territory (ACT), Tasmania, and South Australia, but the loss factor arrangements are not as well-developed in these states and did not provide any additional insight. In addition, Western Australia and Northern Territory are not yet part of the National Electricity Market and therefore do not have the same obligations as other states.
39.
The Australian National Electricity Rules require that distributors (or Distribution Network Service Providers, as they are referred to in Australia) obtain the approval of the relevant state regulator for the distribution loss factors for their electricity networks.
40.
These loss factors must be determined by a methodology that is in accordance with principles set out in the National Electricity Rules. If the jurisdictional regulator has determined a methodology, then that methodology must be applied. If the jurisdictional regulator has not determined a methodology, then the relevant distributor must determine a methodology.
41.
Appendix Three sets out the requirements of the National Electricity Rules in relation to losses and loss factors in more detail, and some information on the approaches adopted by New South Wales, Victoria and Queensland. Further information is available on the methodologies used in Australia that (depending
2
A copy of the Rules is available at: http://www.aemc.gov.au/rules.php
on the arrangements recommended and approved in New Zealand) may assist distributors in their calculation of loss factors. Criteria developed to weigh up potential options 42.
The project team developed criteria to assist it in making recommendations on future arrangements for loss factors. In developing the criteria, the concerns expressed by industry participants, and the research conducted on loss factor methodologies in other jurisdictions, were taken into account.
43.
The project team was decided that the criteria against which proposed arrangements for loss factors should be assessed are as set out below. The arrangements should: a.
clarify the definition, purpose and application of different types of loss factors, so that there is a consistency understanding within the industry (including the difference between ICP- and NSP-referenced loss factors);
b.
allow the Commission to effectively and efficiently monitor distribution losses;
c.
give distributors an incentive to accurately determine the technical losses on their networks, using a recognised methodology, on a regular basis;
d.
provide a framework for dispute resolution between participants on the loss factors that should be used on a network;
e.
provide transparency of the calculation and periodic review of distribution loss factors;
f.
identify the amount of non-technical losses on a network, and encourage minimisation of non-technical losses; and
g.
ensure that the size and influence of any embedded generation is taken into account.
Q2. Do you agree with the criteria developed by the project team against which proposed loss factors arrangements should be assessed? Should one or more criteria be added or deleted? Please give reasons for your view. 44.
Table 1 lists the main features of the loss factor regime in Australia, and how, if adopted in New Zealand, they would contribute to the achievement of the criteria listed above. The project team considered items that contributed to the criteria and included the appropriate measures in the recommended option and draft guideline.
Table 1: Assessment of features of the Australian Regime Australian feature/principle
Criteria developed by the Loss Factor Project Team Clarify the definition, purpose and application of different types of loss factors
Allow the Commission to monitor losses
Give an incentive to distributors to regularly and accurately determine technical loss factors
1. Loss factors determined for all connection points either on a site-specific basis or collectively in relation to connection point classes
Already a feature of the current New Zealand arrangements
2. Allocation of connection points to either a single transmission network connection point or to a virtual transmission node and to a class of distribution network connection points
Already a feature of the current New Zealand arrangements
3. Distributors must conduct a reconciliation between the actual and forecast losses for the previous financial year
9
4. Distributors must use the most recent actual load and generation data available for a consecutive 12month period (and adjust this data by projected load growth)
9
5. For non-site-specific connection points, determine the loss factor by using a volume weighted average of the average electrical energy loss between the transmission network connection point or virtual transmission node to which it is assigned and each distribution network connection point in the relevant class of distribution network connection points for the financial year in which the loss factor is to apply
Already a feature of the current New Zealand arrangements
6. For site-specific connection points, determine the loss factor by reference to the average electrical energy loss between the distribution network connection point and the transmission network connection point to which it is assigned in the financial year in which the loss factor is to apply
Already a feature of the current New Zealand arrangements
7. Treat flows in network elements that solely or principally provide market network services as constant
Already a feature of the current New Zealand arrangements
8. Distributor must satisfy the regulator that the levels of losses are consistent with that of a well managed network
9
9
Provide a framework for dispute resolution
Provide transparency of the calculation and review of loss factors
Identify the amount of non-technical losses on a network and encourage minimisation
Ensure that embedded generation is taken into account
9
9
9
9
9
9
9
9
Australian feature/principle
Criteria developed by the Loss Factor Project Team Clarify the definition, purpose and application of different types of loss factors
Allow the Commission to monitor losses
Give an incentive to distributors to regularly and accurately determine technical loss factors
Provide a framework for dispute resolution
Provide transparency of the calculation and review of loss factors
9. Distributor must satisfy regulator that calculation methodologies are uniform and consistent with methodologies used previously
9
9
9
9
10. Distributor must satisfy regulator that appropriate allowance has been made for theft and metering inaccuracy (and other non-technical losses)
9
9
9
9
9
9
9
9
9
9
9
9
11. If necessary, the regulator can undertake public consultation and/or engage a consultant to assist in assessing the proposed loss factors
9
12. If a distributor makes a material change in its methodology, it must give reasons for the change and explain how the proposed methodology differs from that used in the previous year 13. Regulators specify a (high-level) typical methodology to assist distributors with the calculation of loss factors
9
9
14. Regulator specifies what the distributor’s methodology paper should contain (minimum requirements)
9
9
15. Distributors’ methodologies are published
9
Identify the amount of non-technical losses on a network and encourage minimisation
9
Ensure that embedded generation is taken into account
Options for future loss factor arrangements 45.
Four different options were examined by the project team and these are outlined below. The four options fit into the following three ‘higher level’ alternatives: a.
the status quo (Option One);
b.
determination of a reconciliation loss factor (Option Two); and
c.
new definition of a reconciliation loss factor (Options Three and Four).
Option One: Status quo 46.
One option is to leave loss factor arrangements as they currently are. However, given the issues that have arisen to date with and the numbers of concerns identified by participants in Appendix Two, this option was discarded early in the process. It does not satisfactorily meet any of the criteria in Table Two.
Option Two: Determination of a reconciliation loss factor - GXP extraction data less consumption data 47.
Option Two is generally the status quo for a number of distributors. It would involve defining losses as the GXP extraction data less consumption data, and calculating a loss factor that represented these losses.
48.
There would be no distinction between technical and non-technical losses.
49.
This option would involve using an average of the differences between GXP extraction data and consumption data over a period of time to determine the loss factor (to take out the effects of seasonality).A two-year average would be appropriate, because it would smooth out extraordinary events while still providing having an up-to-date load profile.
50.
After submission data has been loss adjusted for the loss factor calculated by subtracting consumption data from GXP extraction data, any difference between this and the GXP data would be:
51.
52.
a.
allocated to the incumbent retailer under the current Rules;
b.
classified as UFE under the new reconciliation rules, and allocated accordingly.
The advantages of Option Two are as follows: a.
it is simple and mechanistic; and
b.
it is low cost, as some distributors currently use this method.
The disadvantages of Option Two are as follows: a.
the aggregated data would not enable the Commission or participants to track trends in either technical or non-technical losses; and
b.
the opportunity to provide incentives to reduce the level of non-technical losses by having a transparent process is lost.
Option Three: Disaggregation of loss factor components - estimation of both technical and non-technical losses 53.
This option would make it mandatory for distributors to estimate technical and non-technical losses. In order to do this, the following would be required: a.
a set of principles to guide distributors on how to determine technical losses and loss factors;
b.
a requirement that technical losses to be reviewed every five years, unless there is a significant change in network configuration and/or load; and
c.
54.
55.
a requirement on distributors to publish the methodology they use to determine technical losses. In terms of non-technical losses, this option would involve using an average over a period of time to determine the non-technical loss factor (to take out the effects of seasonality). The Commission considers that a two-year average would be appropriate. After submission data has been loss adjusted for the loss factors calculated at (53) and (54), any difference between this and the GXP data would be: a.
allocated to the incumbent retailer under the current Rules; and
b. classified as UFE under the new reconciliation rules, and allocated accordingly. 56.
The advantages of Option Three are as follows: a.
it identifies opportunities for reduction of losses by retailers and distributors; and
b.
UFE volumes would be more manageable.
The disadvantage of Option Three is that the process has higher costs than Option Two, given that it may involve new activity for some distributors. Option Four: Disaggregation of loss factor components - new definition of a reconciliation loss factor 57.
This option would redefine reconciliation losses as being only technical losses.
58.
It would be mandatory for distributors to estimate technical losses. In order to do this, the following would be required: a.
a set of principles to guide distributors on how to determine technical losses and loss factors;
b.
a requirement that technical losses to be reviewed every five years, unless there is a significant change in network configuration and/or load; and
c.
a requirement on distributors to publish the methodology they use to determine technical losses.
59.
60.
61.
Q3.
After submission data has been loss-adjusted for the loss factors, any difference between this and the GXP data would be: a.
allocated to the incumbent retailer under the current Rules; and
b.
classified as UFE under the new reconciliation rules, and allocated accordingly.
The advantages of Option Four are as follows: a.
it identifies opportunities for reduction of technical losses by distributors; and
b.
it is more transparent than Option Two.
The disadvantages of Option Four are as follows: a.
it does not assist with the objective to achieve the closest reconciliation between actual consumption and the loss-adjusted consumption, which the industry should be able to do, and the UFE is the “trim”. If the industry can estimate the technical and non-technical loss factors on a consistent basis, then UFE should be minimal. When it is not, then it will be clear when something out of the ordinary has occurred;
b.
the declared loss factor assists with planning, pricing and risk management and by declaring only a technical loss factor there could be a huge variance in the actual observed losses. This would create problems for this planning, pricing and risk management; and
c.
UFE volumes may be unmanageable.
Are there any options for future loss factor arrangements other than the four options identified in this paper? Please give reasons for your view.
Assessment of options against criteria 62.
In addition to the identification of advantages and disadvantages of each option above, Table 2 summarises the assessment of each of the options against the criteria identified in paragraph 43.
Table 2: Assessment of options against criteria Status quo
Determination of a reconciliation loss factor
Disaggregation of loss factor components
Criteria
Option One
Option Two
Option Three
Option Four
Clarify the definition, purpose, and application of different types of loss factors, so that there is a consistency of understanding within the industry (including the interaction between ICPand NSP-referenced loss factors)
8
8
99
9
Allow the Commission to effectively and efficiently monitor distribution losses
8
8
99
99
Give distributors an incentive to accurately determine the technical losses on their networks, using a recognised methodology, on a regular basis
8
8
99
99
Provide a framework for dispute resolution between participants on the loss factors that should be used on a network
8
8
99
9
Provide transparency of the calculation and periodic review of distribution loss factors
8
9
99
99
Identify the amount of nontechnical losses on a network, and encourage minimisation of non-technical losses
8
8
99
99
Ensure that the size and influence of any embedded generation is taken into account
8
9
9
9
Legend:
63.
99
= contributes to the criterion
9
= meets the criterion
8
= does not meet criterion
As a result of this analysis, the project team has recommended that Option Three be implemented.
Q4. Do you agree that Option Three should be implemented (mandatory estimation of both technical and non-technical loss factors)? Please give reasons for your view.
APPENDIX ONE: RESULTS OF INTERVIEWS WITH INDUSTRY PARTICIPANTS
Concerns expressed by industry participants i.
Lack of visibility of how loss factors are derived.
ii.
Lack of frequent review of loss factors.
iii.
Lack of analysis performed on loss factors.
iv.
Loss factors are not high enough, so incumbent retailers are wearing a portion of the technical loss.
v.
Lack of understanding about loss factors and their purpose.
vi.
Lack of clarity in the definition of “losses” and associated terminology.
vii.
Lack of consistency.
viii.
Loss factors are not seasonal, and losses are not getting apportioned across the right connection types.
ix.
Distributors are currently discouraged from putting in low loss equipment.
x.
The data that retailers are submitting to distributors is not the same as the data being submitted to the reconciliation manager, and retailers are not monitoring that these are the same This is a problem, because the distributors are calculating the loss factor on one set of data, and the UFE will be determined using another set of data.
xi.
Embedded generators do not currently see any benefit in helping to reduce losses on the distribution network.
xii.
Although embedded generators are a loss reduction element in the distribution network, if they generate more and the generation is pumped on to the national grid, this causes more losses on the distribution network.
xiii.
It is not clear how losses should be allocated given that losses are a squared function (i.e. not linear). Because they are non-linear, heavy users should be penalised more, but distributors are unsure what best practice is.
xiv.
Distributors are not responsible for all technical losses – for example, the network stops at the connection point/customer service mains – therefore losses through the service main are not the responsibility of distributor.
xv.
There is a lack of understanding of the true cost of distributed generation.
xvi.
Participants have been trying to determine a new methodology, however they are having difficulty getting meaningful results. There are a lot of assumptions that need to be made about load factors and peak loading.
Different approaches used by distributors to calculate loss factors i.
Loss factors are regularly updated and communicated to/discussed with retailers. In terms of determining loss factors: engineering calculations are completed, billing records are examined, the difference is then considered and non-technical losses are estimated.
ii.
Legacy loss factors are used – i.e. those calculated before the structural separation of retail and distribution companies.
iii.
Loss factors are not done very well, and some distributors have no historical data of load flow. Loss factors are determined by calculating the difference between GXP and metered data.
iv.
The disclosed loss factor is a legacy loss factor from when the key measure was GXP data minus sales. However, technical loss factor is estimated looking at substation losses, heating, etc.
v.
Losses on the network are used to pro-rata total losses to customers according to size – those down to 11kV take a share of losses on upstream; large industrials have a slightly higher contribution to losses because of short runs of low voltage (LV), but are closer to 11kV transformers; and then tail end customers contribute to losses right down to LV. Technical losses are distinguished, but non-technical losses are built into published loss factors.
vi.
Loss factors are based on information from about six years ago.
vii.
Take what retailers report and use a five-year average.
viii.
Loss factors have not changed since structural separation, and some factors are purely technical, while others represent total losses.
ix.
Representative customers are identified and the average load for each customer is calculated and the average losses are weighted. A percentage is then added on for non-technical losses. In the past, calculations were done on transmission and subtransmission configurations, but there is no incentive to do this any longer.
x.
Use a 12-month rolling average of total losses.
xi.
Use estimated loss factors for mass market (derived before structural separation), and calculate accurate technical loss factors for larger customers (usually a dedicated line, so easier to determine). A three-year rolling average is used.
Suggestions made by participants in terms of improvements that could be made i.
Require publication of the methodology used and a mandated review period.
ii.
Introduce a regime that means distributors have an incentive to get the loss factor correct.
iii.
If loss factor is found to be incorrect, then require distributors to do the washup calculation for the time period for which the loss factor was incorrect.
iv.
Require publication of technical and non-technical losses.
v.
Require distributors to reassess loss factors when the network changes, at the time that it happens.
vi.
Develop loss factor guidelines.
vii.
Require independent audits (and if audit reveals deficiencies, then Commission mandates methodology).
viii.
Introduce a “compliant” methodology as a default.
ix.
Put incentives in place for distributors to minimise losses, bearing in mind other regulations.
x.
Should continue the current practice in relation to technical losses and global reconciliation and the differences exposed between total losses and technical losses
xi.
If global reconciliation is introduced, either specify what the technical losses (and technical loss factors) are, so that the rest can be classified as UFE; or have a watchdog that is keeping an eye on the levels of losses.
xii.
Establish a Loss Factor Review Panel so that if an issue arises with a loss factor, then it could go to this group for advice and resolution.
xiii.
Once there is global reconciliation, the loss factor should just be a technical loss factor and everything else can be classified as UFE.
xiv.
In terms of embedded generation: the loss factor should be defined as whatever it would be without the embedded generation, and then the embedded generator should receive some ‘reward’ for reducing losses.
xv.
A simple methodology with one loss factor for half hour and one for non half hour should be introduced.
xvi.
If there is a national standard, then the standard needs to allow for embedded generation, not be heavily computer-powered, and the loss factor should not need to be updated too regularly.
xvii. There should be a disciplined, engineering basis for technical loss factors and they should be reviewed annually. xviii. An acceptable methodology to use before global reconciliation should be introduced. A two-year rolling average should be used, but the data used needs to be at least seven months old. xix.
Greater consistency should be introduced in relation to the data retailers give to distributors.
Concerns raised by participants in terms of improvements to loss factor arrangements i.
Benchmarking between networks would be inappropriate, given different networking configurations. There would be changes in efficiency over time, depending on the network’s investment plan.
ii.
Any regime introduced may become a “stick to beat distributors with”.
iii.
Having to develop a new methodology would be a new activity and so this would mean an increase in costs for distribution companies.
iv.
There would be an impact on costs for consumers if there are increased compliance costs.
v.
A cost-benefit analysis should be conducted. This has been ignored in the past and the view is that the ‘headroom’ is running out for some distributors, i.e. distributors do not have the time nor the resources to conduct one.
vi.
Engineering calculations to determine technical losses are too difficult. A lot of computing power would be needed and the results may not be accurate.
APPENDIX TWO: CALCULATION OF TECHNICAL LOSSES AND LOSS FACTORS BY NEW ZEALAND DISTRIBUTORS
Orion 1.
Orion has derived its loss factors in light of the following: 3 a.
Orion has two different sub-networks, with distinctly different loading patterns – Zone A, urban winter-peaking and Zone B, rural summerpeaking;
b.
losses depend on loading level. Different factors apply by season and by time of day (day/night) according to the differences in average loading levels. Orion also has substantial numbers of night-only loads, which are supplied when the loading levels are low. Specific profiles apply;
c.
losses depend on the part of the network involved in distribution. The factors are higher for distribution to general connections, where the complete network is involved, than for major customer connections, where the LV network is not involved;
d.
losses depend on the voltage level where the metering is connected, low voltage (LV) or high voltage (HV). The key difference is the losses in the distribution transformer. Different sets of loss factors apply for major customer connections, depending on the voltage of metering.
2.
Orion has a comprehensive calculation model, with half-hourly data of annual loading patterns, which has been used to determine all of its published loss factors. Orion has derived the set of factors in order to provide reasonable accuracy in accounting for the key influences on losses.
3.
Orion publishes the following information in its Quality of Supply Statement:
Orion Network: Sources of technical losses Source
Urban
Rural
Subtransmission lines and cables
0.5%
1.0%
District (power) transformers
0.5%
0.5%
11kV lines and cables
1.5%
3.5%
Subtotal subtransmission + 11kV
2.5%
5.0%
Distribution transformers
1.2%
1.2%
230/400V lines and cables
1.3%
0.3%
Subtotal Low Voltage (LV)
2.5%
1.5%
Loss ratio totals
5.0%
6.5%
4.
Orion has used its losses model to consider the marginal losses that occur during peak loading. The basis of the losses model is LL=LNL + LFL x P^n (LL = Loss Load; LNL=Loss at no load; LFL=Loss at full load; P=Normalised load power; n=Exponent in range1-2).
5.
Orion considers its technical loss ratio for its urban network to be 5% +/-1%.
3
“Review of Loss Factors”, Neville Ross, Commercial Contracts & Pricing Manager, Orion, 08/09/2004
Aurora 6.
Aurora notes that there are two main technical components to distribution losses: 4 a.
a fixed component due to the standing losses of the zone substation and distribution transformers; and
b.
variable components arising from the heating effects of the resistance in the delivery conductors. The resistive losses are proportional to the square of the load current and occur in the 66kV, 33kV, 11kV and 6.6kV and LV network conductors and in the zone substations and distribution transformers.
7.
Aurora notes that other components of loss arise from time to time including metering errors, theft, and sales. These are included in the overall calculated loss determined from the sales reports received from retailers. Hence, the loss ratio reported for information disclosure purposes is determined by subtracting metered data provided by retailers from grid exit point (GXP) data. Aurora notes that in its information disclosure document, it is unable to audit the metered data and has little confidence in the accuracy, and suggest that the ratio should be treated with great caution. 5
8.
Aurora’s methodology for determining loss factors is as follows:
9.
a.
the average of the last five years loss percentage for the distribution network (as declared for information disclosure purposes) is calculated;
b.
kWh lost is determined for the year;
c.
the total ‘fixed’ annual losses from zone substation and distribution substation transformers are determined;
d.
the total fixed annual losses are subtracted from the total kWh lost to determine the variable losses;
e.
variable losses are allocated to each half hour of the year using the total network demand for each half hour;
f.
the fixed component is added back on to give the kWh loss for each half hour; and
g.
from this the loss factor is calculated for each half hour.
The loss factor includes both technical and non-technical loss factors, Aurora attempts to differentiate the losses , however, the variable losses determined do include a portion of non-technical errors.
Vector 10.
4
Vector has three measures of losses: 6 a.
technical losses (line resistance, transformer resistance, harmonic currents, unbalanced loading and high resistance joints);
b.
observed losses (technical losses, plus non-technical losses such as metering errors incorrect meter installations, and theft); and
“Aurora Energy Ltd Loss Factors”, 1 October 2006, http://www.electricity.co.nz/download/2006_LossFactors.pdf 5 2006 Information Disclosure, Aurora Energy Ltd, http://www.electricity.co.nz/download/ID06.pdf 6 Auckland Network Loss Factor Review, Daniel Gill, Tim Jackson and Ashok Parsotam, Vector, 01/11/04
c.
published losses (a weighted average of the losses based on the loss factors published on the registry).
11.
Vector identifies two key components of technical losses, and these are defined the same as done by Aurora in paragraph 6.
12.
Vector notes that technical losses on the Auckland network range between 4% and 5%, and that the reason these are lower than those in other lines companies is due to Vector’s higher customer population and energy density.
13.
Vector’s methodology for determining loss factors is as follows: a.
network power and energy losses are estimated for every month of the previous calendar year;
b.
DigSILENT Powerfactory network modelling software is used to calculate losses in the sub-transmission and 11kV distribution networks (to LV terminals of distribution transformers) – load data from SCADA tables is used for these calculations;
c.
The following methodology is used: i.
conductor temp = 20 deg C;
ii.
all loads are balanced across 3 phases;
iii.
average values for transformer load and no load losses are used for transformer loss calculations;
iv.
losses in 11kV distribution network calculated based on feeder maximum demand load scaling since actual loads at distribution transformers are either not recorded or not available at this stage;
v.
the network topology of the network model is assumed to be static, i.e. switching and changes in the normally open points in feeders are not modelled to reflect changes in few feeder loads. The error in the overall loss estimate due to this assumption is relatively small;
vi.
only direct current (DC) resistance is taken into account. The true network loss is caused by alternating current (AC) current. Although the 50 Hz AC current is dominant in the sub-transmission and the 11kV networks, harmonic currents are increasing in the LV network which tends to further heat conductors and increase AC resistance of lines and cable and distribution transformer windings. Therefore losses would be marginally higher than estimated by using only DC resistance of conductors;
vii.
losses in street light supply cabling are not included in the estimate;
viii. estimated technical losses include a 10% allowance for above mentioned factors which could not be modelled explicitly; and ix.
losses in the LV lines and cables are estimated based on historical calculations.
Unison 14.
7
Unison notes 7 that technically, loss categorisation is performed by looking upstream from loads to differentiate between the connectivity of loads to
“System Loss Allocation”, Unison, 7 March 2007
different network component types which are responsible for different losses. Once deemed to connect, directly or indirectly, to a particular network component type, all loads connected will be treated as if supplied from an equivalent circuit, where all loads share the energy loss across that equivalent circuit. The loss of an equivalent circuit of a particular component type is the sum of all losses across all components belonging to that group type. 15.
The apportionment of the share of losses between loads is based on the energy metering information at the customer’s connection. The factors of physical locations of loads and different load profiles are not taken into account. The apportionment of variable losses involves two terms: the mutual and self terms, while the apportionment of fixed losses is performed linearly.
16.
The fixed losses on Unison’s network assets are caused by following components:
17.
a.
33/11kV transformer no-load losses (estimated from the average representation of loss in kW per MVA transformer capacity based on test certificates of a sample of transformers – the losses are recorded when the transformers are tested on nominal tap and energised to nominal voltage); and
b.
11kV/400V transformer no-load losses (determined using an empirical formula).
The variable losses on Unison’s network assets are caused by following components: a.
33kV line copper losses;
b.
11kV line copper losses;
c.
33/11kV transformer copper losses;
d.
11kV/400V transformer copper losses;
e.
low voltage network losses;
f.
customer service mains losses; and
g.
contact losses.
33kV and 11kV line losses 18.
Line losses are determined by running a non-linear load flow with all the relevant network components being modelled in the equivalent steady-state. Theoretically, an accurate evaluation of steady-state line losses would require numerous runs of load flow with ample data samples for every nodal load in the network. Unfortunately, Unison suggests this is not possible with most distribution utility computation resources. Under this circumstance, the load flows are run under the equivalent root mean square (RMS) loading. Generally, the RMS equivalent method provides good estimations if the nodal load profiles are strongly correlated.
11kV/400V transformer copper losses 19.
The full-load copper losses of a transformer are determined from the empirical formula: L=-2.8143ln(r)+24.691 watts.
LV distribution losses
20.
21.
With respect to determining LV distribution losses, a distinction is made between LV distribution and LV service mains. All the LV distribution cannot yet be practically modelled at this stage, so Unison has made some assumptions in order to estimate these losses: a.
suburban areas contribute to most LV distribution losses;
b.
a sample of randomly chosen suburban distribution substation LV reticulation areas are modelled in each city of Napier, Hastings, Rotorua and Taupo;
c.
to estimate losses, it is assumed that each ICP has a coincidental demand of 3.5kW is chosen as a typical value found as the after diversity load for 20 or more domestic consumers.
The above assumptions give an annual 26.1% load factor and a 0.11 loss load factor. A simple load flow model of the LV feeders is obtained from the sample substation, and the load flow model is run and the value of losses obtained. These losses are calculated as a percentage of the consumption per consumer.
Service mains and contact losses 22.
According to Unison, an accurate assessment of service mains losses is currently not feasible and therefore estimations are used. Contact losses are also estimated, using a formula.
Miscellaneous losses 23.
Unison call the non-technical losses on the network (meter error, theft, etc), ‘miscellaneous’ losses, and note that they represent the difference between the sum of the above losses and the actual system loss.
APPENDIX THREE: THE AUSTRALIAN LOSS FACTOR REGIME
National Electricity Rules 1.
The requirements of the National Electricity Rules (NER) are: a.
Loss factors must be determined for all connection points either on a sitespecific basis, or collectively in relation to connection point classes. Site specific loss factors will be determined for a connection point: i.
for an embedded generating unit with actual generation of more than 10MW;
ii.
for an end-user with actual or forecast load of more than 40GWh or an electrical demand of more than 10 MW;
iii.
for a market network service provider; and
iv.
between two or more distribution networks.
b.
Allocation of connection points to either a single transmission network connection point or to a virtual transmission node and to a class of distribution network connection points.
c.
The principles that must be applied to the methodology are as follows: i.
the total amount of energy calculated in relation to a distribution network (as adjusted for losses by the relevant loss factor) for a particular financial year is as close as reasonably practicable equal to the total metered or estimated energy flowing through all connections points in the distribution network and the total (actual) electrical energy losses incurred on the distribution network in the financial year;
ii.
the extent to which the objective above has been achieved must be demonstrated through a reconciliation based on the previous financial year’s adjusted gross energy and loss factors, i.e. by a reconciliation between the aggregate adjusted gross energy at all customer connection points on the distribution network in the previous financial year (applying the loss factors set for that previous year) and the sum of the total metered energy at those points in that year plus the total (actual) losses incurred on that network in that year;
iii.
for non-site specific connection points, determine the loss factor by using a volume-weighted average of the average electrical energy loss between the transmission network connection point, or virtual transmission node to which it is assigned, and each distribution network connection point in the relevant class of distribution network connection points for the financial year in which the loss factor is to apply;
iv.
for site specific connection points, determine the loss factor by reference to the average electrical energy loss between the distribution network connection point and the transmission network connection point to which it is assigned in the financial year in which the loss factor is to apply;
v.
the most recent actual load and generation data available for a consecutive 12 month period must be used to determine the average electrical energy losses referred to above, adjusted if necessary to take into account projected load and or generation growth in the financial year in which the distribution loss factors are to apply; and
vi.
treat flows in network elements that solely or principally provide market network services as invariant.
2.
Once Australian distributors have determined the loss factors, distributors must submit them to the appropriate regulator for approval in time for the National Electricity Market Management Company Ltd (NEMMCO) to publish by 1 April of each year. 8
3.
The New South Wales and Queensland regulators have not determined a loss factor methodology. Each distributor in these states must therefore develop, publish, and maintain a methodology in accordance with the NER.
4.
In Victoria, however, distributors have adopted a common methodology with some small difference, which take into account any individual features of the different networks and data management systems. The methodology was developed by the Victorian Distribution Loss Factor Working Group (made up of the five distributors and the former Victorian Power Exchange, with the involvement of the regulator).
New South Wales Regulator requirements 5.
As well as the principles outlined in the NER, the Independent Pricing and Regulatory Tribunal (IPART) has determined that distributors must satisfy the tribunal that: 9 a.
the levels of losses are consistent with that of a well-managed network;
b.
calculation methodologies are uniform and consistent with methodologies used previously; and
c.
appropriate allowance has been made for theft and metering inaccuracy.
6.
IPART may also undertake public consultation and engage a consultant to assist in assessing the proposed loss factors. If a distributor makes a material change in its methodology, it must give reasons for the change and explain how the proposed methodology differs from that used in the previous year.
7.
IPART specifies a typical methodology to assist distributors with the calculation of loss factors, namely:
8
a.
review the historical energy consumption of the entire network;
b.
review the historical actual overall energy losses of the entire network based on the total energy purchased, the total metered energy sale, estimated un-metered energy sales and allowances for theft and faulty metering equipment;
These can be found at http://www.nemmco.com.au/transmission_distribution/171-0014.htm “Assessment and Approval Process of Distribution Loss Factors proposed by DNSPs for 2007/08”, IPART, December 2006 9
8.
9.
c.
forecast the total energy consumption for the next financial year;
d.
forecast the overall energy losses based on historical data, planned changes to network configurations, customer load patterns (‘top-down’);
e.
compare the forecast ‘top-down’ overall losses with the calculated ‘bottom-up’ estimation of total energy losses by multiplying the individually forecast energy consumptions of site-specific customers and the forecast consumptions of all other customers by the estimated loss factors; and
f.
adjust the estimated loss factors by scaling so that the total ‘bottom-up’ losses equal the ‘top-down’ forecast of overall energy losses.
IPART also specifies that the distributor’s methodology paper should contain: a.
how the distributor determined the proposed loss factors;
b.
how the methodology used by distributors complies with the NER; and
c.
the information required for the assessment of the proposed loss factors, namely: i.
detail that the loss factors are forward looking estimates;
ii.
reconciliation of forecast and actual losses;
iii.
how the distributor estimated losses (total technical and nontechnical losses, network losses by voltage level);
iv.
how the distributor allocated losses at each voltage level; and
v.
comparison of current and proposed loss factors.
IPART commissioned a consultant (Intelligent Energy Services) to determine and explain a standard and compliant methodology for the calculation of loss factors. The report can be viewed at: http://www.iprt.net/papers/IES_DLF0904.pdf
NSW Distributor: EnergyAustralia 10.
The steps taken by EnergyAustralia for the calculation of its non-site-specific loss factors are as follows (more detail can be obtained at http://www.ipart.nsw.gov.au): 10 a.
reconciliation of the previous financial year by subtracting ‘purchases’ from ‘sales’;
b.
estimation of losses for the year in which the loss factors are to apply using the most recent data available. This data is adjusted to reflect factors such as anticipated seasonal load variability and to account for any differences demonstrated by the previous financial year’s reconciliation;
c.
determination of the volume weighted average of the average electrical energy loss for connection points – an engineering calculation is done to determine the anticipated losses for each asset category. Once this allocation takes place, any remaining proportion of losses is allocated to unread meters and accrual. This accrual is allocated to the LV network.
10 ‘Distribution Loss Factor Calculation Methodology Paper’, EnergyAustralia, February 2007 (http://www.ipart.nsw.gov.au/files/EnergyAustralia%20DLF%20methodology%20February%202007%20v1.1.P DF)
Distribution losses for non-site-specific connection points are considered in categories, related to the functional part of the network, and are estimated using the following approaches: Loss element
Series loss
Shunt loss
Transmission (parallel 132 kV)
Transformer substation and typical shunt
Radial 132 kV network
Negligible
132/66 and 132/33 substations
TPRICE simulation
Transformer substation and typical shunt
ST networks
Negligible
Zone substations
Transformer substation and typical shunt
HV network
Sample studies, peak and loss load
Negligible
Distribution substations
Transformer count, load and loss load
Transformer substation and typical shunt
LV network
Loadflow on a sample LV networks
Negligible
Meters and load control
Negligible
Device count typical shunt
Non technical losses
Residual calculated purchases less sales
Series (or copper) losses occur in the network connection between generator(s) and load(s) due to the resistance to electrical flow and vary with the power supplied to the load. Series losses tend to follow a “square law”, in that the series loss in a simple network is proportional to the square of the current supplied to the load. Shunt (or iron) losses are a “leakage” of energy (mainly associated with the connection of transformers and other equipment to the network) and occur regardless of the flow of power to the load.
d.
a portion of each asset class’s losses is then allocated to customer classes. For example, a certain amount of losses relates to 33kV underground and overhead feeders. Some of those losses are caused by domestic customers load further below in the network. The allocation of asset losses to customer class is carried out based on a pro rata energy allocation as well as considering each customer class peak, shoulder and off peak energy mix and their average power factor. Having carried out this allocation, the calculation of loss factors at this point is then a simple case of taking the losses, dividing by the total energy for that customer class and adding one; and
e.
EnergyAustralia make the point that the year-on-year variation of (purchases-sales) is significant, due to the effect of seasonal loading, particularly relating to the winter/summer cycle of heating/cooling load for SME and domestic customers. The other key effect in this instability is related to comparing “entering” energy, measured up to the hour, against ‘exit’ energy, smeared across a quarterly billing cycle. This makes it difficult to determine loss factors which provide a result that seeks to ensure that the total amount of energy calculated in relation to a distribution network (as adjusted for losses by the relevant loss factor) for a particular financial year is as close as reasonably practicable equal to the amount of electrical energy flowing through all connection points in the distribution network and the total electrical energy losses incurred on the distribution network in the financial year. For this reason, Energy Australia applied a methodology from 2000 to 2004 whereby the
distribution losses were calculated on the basis of a five-year rolling average. For 2005, this method was modified to be carried out on a three year rolling average. This methodology was accepted by IPART and the consequent loss factors were approved by IPART. In calculating loss factors from 2006 to 2007 however, EnergyAustralia moved away from the rolling average methodology as this approach had shown not to be responsive enough and had introduced a consistent under signalling of losses from 2001 to 2005. To address the under signalling, rather than an average, the most up to date full year losses for FY04 of 5.32% was used as a basis for calculating loss factors for 2006 (extra billing data demonstrated an overall loss factor of 5.36% for 2004). This methodology was accepted by IPART and the subsequent loss factors were approved. 11.
12.
The method EnergyAustralia use to calculate its site-specific loss factors is as follows: a.
EnergyAustralia calculates site-specific loss factors using the cost allocation software TPrice. TPrice is used in the National Electricity Market (NEM) for the allocation of transmission costs and the calculation of Transmission Loss Factors by NEMMCO.
b.
EnergyAustralia uploads the full topology of the network down to the 11kV busbar of each zone substation and then also down to each customer of greater than 10MW usage, in to TPrice. This covers line impedances, connections, transformer impedances, and standard operating conditions. Each customer’s load profile from metering data is uploaded, and each zone substation has a deemed load profile applied and uploaded in to TPrice as well. TPrice then runs a loadflow for each hour of the year. Any loadflow must calculate losses as part of its calculation of energy flows, since a loadflow cannot converge to a solution without all power flows balancing.
c.
TPrice then collates the results and calculates the total losses attributable to each large customer. It does this by allocating upstream shared losses on a total energy basis. For example, consider a substation that a large customer connected but with other load connected as well. Consider that TPrice has determined electrical losses on the substation of 100MWh over the year and substation saw 20,000MWh of load pass through it during the year. The large customer connected downstream used 500MWh, then the losses through the zone substation attributed to the large customer are: 100MWh x 500/20,000 = 2.5MWh. This method is applied to all upstream assets such that the large customer receives a portion of losses all the way along the supply chain.
d.
For information about calculation of subtransmission network series losses, subtransmission network shunt losses, high voltage network series losses, distribution substation series losses, and meters and load control device shunt losses see EnergyAustralia’s distribution loss factors methodology paper (found at http://www.ipart.nsw.gov.au).
EnergyAustralia defines non-technical losses as including fraud, and metering, data and information system deficiencies. EnergyAustralia uses approximately 150 compact recording instruments (theft monitors). These are installed in the street to check the meter readings at premises under investigation. Recently, this process was expedited by taking special meter readings at such premises,
allowing many checks to be completed in a matter of weeks rather than a full three-monthly billing cycle. EnergyAustralia suggests that non-technical losses are simply the left over portion of losses that cannot be attributed to the electrical network. Once technical losses have been determined, it can be expected that a small amount of overall system losses is unaccounted, and must therefore be attributed to fraud, meter reading errors and other minor billing errors. All non-technical losses are assumed to take place on the low voltage network and therefore are attributed to this class of customer. Victoria Regulator requirements 13.
The Victoria regulator, the Essential Services Commission (ESC), specifies the methodology to be used by distributors in Victoria. Details of this methodology can be found at http://www.esc.vic.gov.au/NR/rdonlyres/76075646-8A4C40E6-9BCDD2D203A05C1B/0/GLGuidanceDLFcalculationmethodology20070207.pdf, The steps that distributors in Victoria must follow are set out below.
14.
For site-specific loss factors for large customers, the following method is used:
15.
a.
calculate all upstream losses from the site-specific customer’s point of supply to the transmission network connection point (being the relevant terminal station);
b.
determine the total energy sales at each segment of the distribution network upstream from the customer;
c.
determine the fraction of the total upstream energy sales associated with the site-specific customer. This can be calculated by dividing the energy sales of the customer by the total energy sales at each segment of the distribution network upstream;
d.
multiply the percentages calculated in (c) by the energy losses calculated in (a) to determine the amount of losses at each segment that are attributable to the site-specific customer. Add these together to get the total distribution network losses attributable to the site-specific customer;
e.
calculate the site-specific loss factor as: 1 + (the total energy losses attributable to the site-specific customer) / (total energy sales to the sitespecific customer);
For network average loss factors for general customers and small embedded generators, the following method is to be used: a.
distribution losses are grouped into five major segments of the distribution network. Customers should pay for the losses based on which of the five segments are used to supply their power;
b.
the five network segment categories are: i.
Category A: Sub-transmission feeders operating at 66 kV or 22 kV (note: 1 kV = 1000 Volts);
ii.
Category B: Zone substations operating at 22 kV, 11 kV or 6.6 kV;
iii.
Category C: HV distribution feeders operating at 22 kV, 11 kV or 6.6 kV;
Category E: Distribution substations operating at 240/415 V; and
v.
Category E: Low voltage (LV) feeders operating at 240/415 V;
c.
a customer connected to the low voltage network utilises all upstream assets, causing electrical energy losses in each network segment upstream of its connection point. Customers connected to sub-transmission feeders, however, only cause losses on the sub-transmission network;
d.
each customer should be categorised as A through to E depending on the customer’s connection point to the network and the location of the metering point;
e.
energy losses can be calculated for each network segment. Once the losses in each segment are determined, the total losses attributable to a customer class can be determined by combining all upstream losses from the customer’s point of supply to the terminal station (transmission network connection point) similar to the calculation process of sitespecific loss factors. Distribution loss factors (DLF) are then calculated for each category A to E;
f.
16.
iv.
i.
DLF-A is the distribution loss factor to be applied to a second tier customer or market customer connected to a sub-transmission line (at 66 kV or 22 kV);
ii.
DLF-B is the distribution loss factor to be applied to a second tier customer or market customer connected to the lower voltage side of a zone substation at voltages of 22 kV, 11 kV or 6.6 kV;
iii.
DLF-C is the distribution loss factor to be applied to a second tier customer or market customer connected to a distribution line from a zone substation at voltages of 22 kV, 11 kV or 6.6 kV;
iv.
DLF-D is the distribution loss factor to be applied to a second tier customer or market customer connected to the lower voltage terminals of a distribution transformer (at 240/415 V);
v.
DLF-E is the distribution loss factor to be applied to a second tier customer or market customer connected to a low voltage line at 240/415 V; and
separate loss factors must also be calculated for each of the DLF categories A to E depending on whether the length of the subtransmission line supplying the customer is ‘short’ or ‘long’. This creates a total of ten loss factors per distributor. A short sub-transmission line is defined as a radial sub-transmission line where the route length of the line is less than 20 km; or a sub-transmission line in a loop where the total route length of all lines in the loop is less than 40 km. All other long sub-transmission lines are defined as ‘long’.
For site-specific loss factors for large embedded generators, the following method is to be used: a.
model the operations of the generator based on historical record or other relevant information available;
b.
determine the relevant forecast network losses by modelling the distribution network between the generator’s connection point and the
transmission network connection point for each modelled operating period of the generator; c.
calculate the annual overall loss factor utilising a volume weighting factor based on the forecast average electrical energy loss for each modelled operating period of the generator in the financial year in which the loss factor is to apply.
17.
The ESC noted that a consistent approach to the choice of weighting factor is essential to achieving consistency in regulation and to provide a level playing field for competition in embedded generation. In the past, the ESC has approved some site-specific loss factors for embedded generators where losses have been expressed as a percentage of consumer sales, that is: loss factor = 1+losses/sales. This is consistent with how network average losses are weighted when determining loss factors for small embedded generators and general customer loads, and is appropriate when the volume of sales is very much larger than the generator’s output volume.
18.
However, a problem arises when the output volume of the generator is larger than the energy consumed by customers in that part of the network between the generator and the transmission connection point. In such circumstances, there is a net export of energy from the generator into the transmission network connection point and the loss factor could be less than zero. As a loss factor represents losses in a network and losses are always present to some extent; it is evident that a loss factor must always be a positive number and therefore expressing losses as a percentage of sales in some circumstances is not an appropriate approach.
19.
The ESC requires that the loss factor be determined using the following formula: 1 + Losses/ (magnitude of sales less generation). This volume weighting is consistent with treating a generator as a negative load in network load flow modelling and allows a consistent approach to be adopted and an appropriate loss factor to be developed in all likely operating conditions.
Queensland Regulator requirements 20.
In Queensland, the approach adopted by the Queensland Competition Authority (QCA) has been to engage independent advice to assess the distributors' methodologies (particularly their load flow calculations). The QCA revisits this assessment every three years. In intervening periods, the QCA audits the calculated loss factors submitted by the distributors to ensure these are calculated consistent with the approved method. The QCA told us that as part of this process they have not encountered any problems of note.
Queensland distributor: Energex 21.
11
The methodology used by Energex 11 for site-specific customer calculations is as follows:
http://www.energex.com.au/network/deregulation/distribution_loss_factor_methodology.html
22.
a.
regardless of whether a full re-calculation of loss factors is being undertaken (every third year), or only a review, the methodology for determining loss factors for site-specific customers is identical;
b.
site-specific loss factors are calculated using load flow analysis based on the customers forecast demand data and network load data for the year in which the loss factors are to be applied. The analysis involves load flow studies on the directly connected network between the customer connection point and the transmission network connection point. The directly connected network is defined as all network which will experience a change in power flow due to a change in customer loads. In addition, iron losses of the transformers included in the directly connected network are calculated and apportioned based on the ratio of customer load and network load flowing through the transformer; and
c.
Energex uses the marginal loss factor methodology to calculate sitespecific loss factors. This process involves determining the losses for the customer by assessing the relativity between the change in system load associated with a change in the customer's load.
The methodology used for the calculation of average loss factors is as follows: a.
average loss factors are calculated for each significant supply level in the network, with loss factors for major customers being calculated individually in order to determine the losses directly attributable to their loads. The average loss factors categories applied by Energex are: i.
132/110 kV Network;
ii.
33 kV Network;
iii.
11 kV bus;
iv.
11 kV line;
v.
LV bus; and
vi.
LV line;
b.
the method used to calculate average loss factors is to carry out a series of load flow studies to determine the losses at the coincident network peak, followed by the application of calculated Loss Load Factors (LLFs) to obtain the actual losses;
c.
the transmission and subtransmission systems are modelled using appropriate load flow packages. Losses on the 11 kV distribution system are calculated using forecast feeder peak demand data and feeder length data which is obtained from Energex’s corporate database. Losses at the LV bus are calculated based on the average impedance of distribution transformers, and losses in the LV network are calculated as the difference between the total losses (calculated by the difference between total purchases and total sales), and the losses resulting from the higher voltage network studies;
d.
the loss factors for the network are then calculated based on the formula: Loss factor = [losses (GWh) for section of network – ICC losses]/[sum of sales (GWh) for all sectors downstream and including that sector (excluding sales to ICCs)]
ICC = Individually Calculated Customers (all customers of greater than 10 MW demand or 40 GWh annual consumption). Feedback from Australian Regulators and Distributors 23.
The project team also received feedback from a few participants from Australia on the loss factor arrangements in Australia. Most participants that responded were largely happy with the arrangements. Some of the observations made were: a.
it might be worth investigating under what circumstances a distributor should be asked to create additional classes to increase differentiation (apparently there were some requirements that were removed from the Australian rules);
b.
one distributor said that it is not feasible to use the ‘most recent twelve months’ worth of data as they need to wait three to six months for all the meters to be read;
c.
in terms of site-specific loss factors, quite a few customers that were on site-specific loss factors went back to average loss factors after the introduction of the 10MW / 40GWh rule (i.e. that site-specific loss factors be calculated for end users with actual or forecast load of more than 40GWh or an electrical demand of more than 10 MW). It worked out well for the customer as they always ended up with a lower loss factor. It was one distributor’s view that it made the rules open to gaming, for example, a new mine in the middle of nowhere may avoid having to pay as much by splitting its proposed connection point into two;
d.
in terms of the site-specific method, one distributor did not think that the generic load loss factor method was accurate enough, especially where there were different load profiles. They felt that the calculation should be done half hour by half hour (the problem being that this requires specialist software to perform loadflow network simulation for every half hour in the year).
24.
One of the state regulators told the project team that there was some discussion between the jurisdictional regulators three or four years ago that there should be national consistency to avoid potential distortions in price signals on account of the use of different DLF methodologies across jurisdictions. It was decided, however, that this was not considered necessary. The current approach was deemed adequate for achieving the aim of capturing and allocating losses.
25.
In terms of the idea of adopting a more prescriptive approach than that adopted in Australia, one of the state regulators noted that in their experience, the only concern would be whether differences in distribution network characteristics should give rise to different approaches in the derivation of losses. Also, there was a concern that such an approach might not provide incentives (and conversely penalties) to promote more efficient losses and whether these should be included into the efficiency or regulatory mechanism.
APPENDIX FOUR: GUIDELINES ON THE CALCULATION AND USE OF THE LOSS FACTORS FOR RECONCILIATION PURPOSES
Guidelines on the calculation and the use of loss factors for reconciliation purposes v1.0 Version
Date issued
Comments/amendments made
1.0
15 June 2007
Draft for consultation
These guidelines have been produced to promote understanding and encourage consistency in the calculation methodologies and processes surrounding distribution loss factors. The general approach set out in this information guide in no way reduces the requirement upon participants and comply with their obligations under the Electricity Governance Rules 2003 (Rules). These guidelines do not necessarily reflect the Electricity Commission’s (Commission) views about the Rules.
Background 1.
As required under the Government Policy Statement on Electricity Governance, the Commission should, whenever possible, use its powers of persuasion and promotion, and provision of information to achieve its objectives rather than recommending regulations and rules.
2.
These guidelines are therefore recommended for use by distributors when calculating and publishing distribution loss factors for the purposes of reconciliation.
Defined terms 3.
The following defined terms are used in these guidelines: “loss category code” means the relevant code in the schedule published by the registry which identifies the relevant loss factors that apply to submission information; “loss factor” means the factor applied to consumption information at the ICP or NSP (for an embedded network) to allow for losses within the local network or embedded network to produce equivalent consumption information at the relevant NSP; “non-technical loss factor” means, a loss factor that represents the difference between reconciliation losses and technical losses. These losses represent inaccuracies caused by measurement and data handling and include metering and reading errors, incorrect meter installations, theft, and unread meters. Identification and quantification of this component, facilitates
investigation into these inaccuracies, and a subsequent reduction in the loss factor; “technical loss factor” means a loss factor that represents the electricity that is consumed during the delivery to consumers’ installations. The technical loss factor represents There are two main technical components to the loss: •
a fixed component that arises from the standing losses of the zone substation and distribution transformers; and
•
variable components arising from the heating effects of the resistance in the delivery conductors. The resistive losses are proportional to the square of the current and occur in the high voltage (HV) and low voltage (LV) network conductors, the zone substations and distribution transformers;
Identification and quantification of this component, facilitates investigation into improvements that are available to these components, and a subsequent reduction in the loss factor; “reconciliation loss factor” means, a loss factor that represents the difference between the delivered electricity at one point of connection and the electricity required to be injected into any other point of connection in order to supply the delivered electricity. This loss factor is used in: •
the reconciliation process by the reconciliation manager to allocate volumes of electricity at grid exit points to participants (both buyers and sellers from/to the clearing manager; and
•
the retail pricing process by retailers for electricity purchases and in the case of grid exit point (GXP) charging networks, the calculation of network charges.
Distributor loss factor obligations 4.
Distributors must calculate and publish reconciliation loss factors for each loss factor code in the registry each year.
5.
Distributors must calculate and publish on their website both technical and non-technical losses and loss factors for each loss factor code that they have used in the registry each year.
6.
Technical loss factors will be reviewed every five years (unless there is a significant change in network configuration and/or load in which case the review will be re-run), although they will still need to be reported each year to the Commission.
7.
Non-technical loss factors will be reviewed every year (using a sliding window of two years’ generation and consumption information), and reported each year to the Commission.
8.
Distributors will submit to the Commission the technical and non-technical and reconciliation loss factors (the format for this is detailed further below), and the loss factor methodology used to determine loss factors for the next financial year, prior to 1 March of each year.
9.
Distributors will satisfy the Commission that the levels of losses are consistent with those of a well-managed network.
10.
Should the Commission disagree with the loss factors calculated, the Commission will refer the issue to the Loss Factor Review Panel (LFRP), who will provide advice to the Commission on the distributor’s compliance with these guidelines. In the event that the Commission considers that the loss factors are not calculated in accordance with the guidelines, the distributor will re-calculate the loss factors.
Q5.
Are one year (for non-technical loss factors) and five years (for technical loss factors) the appropriate timeframes within which to review loss factors? Please give reasons for your view.
Retailer loss factor obligations 11.
In order to enable distributors to accurately calculate loss factors, retailers shall provide the following to distributors by 31 July each year, for the 12 month period to 1 April of that year: a.
Prior to 1 May 2008 – annual billing information, normalised, and summarised by network supply point; and
b.
After 1 May 2008 - annual summarised reconciliation manager submission information by network supply point and loss category code.
Creation and population of loss category codes on the registry 12.
Loss factor codes are used in the installation control point (ICP) records on the registry to indicate to retailers, data administrators and the reconciliation manager which loss factors apply for settlement purposes. Retailers also use this code for the allocation of retail tariffs.
13.
Loss factor codes need to be unique to each loss factor, and the numbering system employed by distributors is to ensure that these codes are unique. The number of characters must not exceed that allowed by the registry.
Q6.
Do you think that the loss category code needs to be standardised? Please give reasons for your view.
Distributor loss factor methodology obligations 14.
Distributors will submit to the Commission the technical, non technical and reconciliation loss factors calculated (format noted below) and the loss factor methodology used to determine loss factors for the next financial year prior to 1 March of each year.
15.
The loss factor methodology applied by distributors in accordance with paragraph 8 must meet the following criteria: a.
Site-specific loss factors will be determined for a connection point: i.
for an embedded generating unit with actual generation of more than 10MW;
ii.
for an end-user with actual or forecast load of more than 40GWh or an electrical demand of more than 10 MW;
iii.
for a market network service provider; and
iv.
between two or more distribution networks.
Site-specific loss factors may be calculated for generation or consumption at levels lower than the above at the discretion of the distributor. b.
Different loss factors will be calculated for different voltage levels (as the distributor deems appropriate).
c.
Distributors will conduct load flow studies to assist in determining technical loss factors.
d.
The average used to determine reconciliation loss factors will be two years.
e.
The total amount of energy calculated in relation to a distribution network (as adjusted for losses by the relevant loss factor) for a particular financial year will be as close as reasonably practicable equal to the total metered or estimated energy flowing through all connections points in the distribution network and the total (actual) electrical energy losses incurred on the distribution network in the financial year.
f.
Distributors will demonstrate the extent to which the objective above has been achieved through a reconciliation based on the previous financial year’s adjusted gross energy and loss factors, i.e. by a reconciliation between the aggregate adjusted gross energy at all customer connection points on the distribution network in the previous financial year (applying the loss factors set for that previous year) and the sum of the total metered energy at those points in that year plus the total (actual) losses incurred on that network in that year.
g.
For non-site-specific connection points, the loss factor is to be determined by using a volume weighted average of the average electrical energy loss between the transmission network connection point or virtual transmission node (or in the case of embedded networks the gateway meter point/points) to which it is assigned and each distribution network connection point in the relevant class of distribution network connection points for the financial year in which the loss factor is to apply.
h.
For site-specific connection points, the loss factor is to be determined by reference to the average electrical energy loss between the distribution network connection point and the transmission network connection point to which it is assigned in the financial year in which the loss factor is to apply.
i.
Distributors are to use the most recent actual load and generation data available for a consecutive 24-month period to determine the average electrical energy losses referred to above, adjusted where necessary to take into account projected load and or generation growth for the year in which the distribution loss factors are to apply.
Derivation of losses 16.
Losses and loss factors are to be derived as follows for each network area:
a.
Gross electricity (Gr) flow is to be determined using the immediate past 24 months embedded generator and customer point of connection injection and consumption information for an electrically connected network area.
b.
Technical losses (TL) – this is to be the determined for an electrically connected network area by load flow studies as determined above, allocated to each loss category code.
c.
Reconciliation losses (RL) – this is to be derived from the immediate past 24 months injection and consumption information for an electrically connected network area, allocated to each loss category code.
d.
Non Technical Losses (NTL) – this is to be derived using the equation NTL = RL - TL
e.
Technical loss factor (TLF) – this is to be derived using the equation TLF = 1+(TL/Gr)
f.
Reconciliation loss factor (RLF) – this is to be derived using the equation RLF = 1+(RL/Gr)
g.
Non technical loss factor (NTLF) – this is to be derived using the equation NTLF = 1+(NTL/Gr)
Q7.
Do you agree with the methodology for the derivation of loss factors in the draft guidelines? Please give reasons for your view.
Loss Factor Review Panel 17.
A technical panel called the Loss Factor Review Panel will be established by the Commission to deal with any issues that may arise with loss factors and loss factor methodologies used by distributors.
18.
The Loss Factor Review Panel will be made up of an independent chair and two independent members with expert knowledge of the determination of losses and a Commission representative.
19.
The Loss Factor Review Panel will report to the Commission.
Distributor loss factor report 20.
Distributors must submit to the Commission their proposed loss factors for the next financial year prior to 1 March of each year regardless of any change or not. The following information must form part of a distributor’s submission: a.
a declaration that the proposed loss factors have been calculated based on the Commission’s loss factor calculation guideline;
b.
the proposed site-specific loss factors for large customers and embedded generators requiring site-specific loss factors;
c.
the network average loss factors for all other customers and embedded generators;
21.
d.
a statement of the reconciliation result in terms of over/under allocation of losses from the application of loss factors for the previous financial year; and
e.
a statement of the overall losses of the distributor’s network.
The distributor’s report must be in the CSV format specified below
Distributor four letter code assigned by the Market Administrator
Q8.
GXP losses factors applicable to
Loss category code used in the registry
Technical loss factor (TLF)
Year in which technical loss factor last calculated
Non technical loss factor calculated (NTLF)
Reconciliation loss factor (RF) calculated each year using a sliding two year window of generation and consumption
Description of customer group that loss category code is applicable to
Are there any other comments or concerns you wish to raise about the draft guidelines?
APPENDIX FIVE: QUESTIONS ON WHICH SUBMISSIONS ARE INVITED
Questions on which submissions are invited Below is a compiled list of the questions shown throughout the consultation paper and its appendices, as well as some additional questions on which the Commission invites submissions. Q1
Do you agree with the definitions and uses of reconciliation, technical and non-technical loss factors set out in this paper? Please give reasons for your view. (See paragraphs 18, 19, and 21.)
Q2
Do you agree with the criteria developed by the project team against which proposed loss factors arrangements should be assessed? Should one or more criteria be added or deleted? Please give reasons for your view. (See paragraph 42.)
Q3
Are there any options for future loss factor arrangements other than the four options identified in this paper? Please give reasons for your view.
Q4
Do you agree that Option Three should be implemented (mandatory estimation of both technical and non-technical loss factors)? Please give reasons for your view.
Q5
Are one year (for non-technical loss factors) and five years (for technical loss factors) the appropriate timeframes within which to review loss factors? Please give reasons for your view.
Q6
Do you think that the loss category code needs to be standardised? Please give reasons for your view.
Q7
Do you agree with the methodology for the derivation of loss factors in the draft guidelines? Please give reasons for your view.
Q8
Are there any other comments or concerns you wish to raise about the draft guidelines?
Q9
The calculation of reconciliation loss factors, and hence non-technical loss factors, relies on the availability of retailers' records of how much electricity has been consumed. Do distributors have access to this information from retailers?
