Information Guide for Standard Control Services Pricing. 1 July 2015 to 30 June 2016

Transcription

1 Information Guide for Standard Control Services Pricing 1 July 2015 to 30 June 2016

2 Revision history Version Date Summary of changes July 2015 Initial Information Guide for SCS Pricing December 2015 Clarified the fixed charge arrangements for unmetered supply tariffs Amended tariff class assignment and reassignment section to reflect the Distribution Determination and updated contact details Other minor amendments Information Guide for SCS Pricing v1.1 page 2

3 Contents 1. Introduction Overview Purpose and structure Use of terms Supporting network pricing documents Further information Regulatory framework National Electricity Law National Electricity Rules Distribution Determination Network Tariff Strategy Establishing tariffs for Standard Control Services Overview Annual revenue requirement Development of network tariffs Step B1: Zone determination Step A2: LRMC for tariff groups Step B2: Allocation of the revenue cap to zones Step C2: Allocation of designated pricing proposal charges to customers Step D2: Calculation of jurisdictional scheme amounts Step B3: Allocation of zonal costs to asset categories Step B4: Determination of groups of network users Step B5: Allocation of costs within zones to network user groups Step A6 and B6: Conversion of allocated costs into network tariffs Step C6: Designated Pricing Proposal Charges to network tariffs Step D6: Allocation of jurisdictional scheme amounts into network tariffs Tariff classes Assignment and reassignment of customers to tariff classes Notification of a tariff class assignment and reassignment Review of a customer s assigned tariff class Objections to a tariff class assignment or reassignment Network tariff reviews Distribution Loss Factors Overview DLF categories and applications Further information EG Avoided TUOS payments Information Guide for SCS Pricing v1.1 page 3

4 6.1 Methodology Appendix 1: Additional pricing information Glossary Information Guide for SCS Pricing v1.1 page 4

5 1. Introduction 1.1 Overview Ergon Energy Corporation Limited (Ergon Energy) is a Distribution Network Service Provider (DNSP) to around 725,000 customers in regional Queensland. Our service area covers around 97 per cent of Queensland and has approximately 160,000 kilometres of power lines and one million power poles. Around 70 per cent of the network s power lines are radial and service mostly rural areas with very low levels of customers per line kilometre. As a DNSP, Ergon Energy is subject to economic regulation by the Australian Energy Regulator (AER) under the National Electricity Law (the Law) and the National Electricity Rules (NER). Under the Law and NER, the AER is responsible for regulating the revenues Ergon Energy can earn, and the prices that we can charge for certain services provided by means of, or in connection with, our distribution system. In order to regulate the prices that Ergon Energy can charge for our services, the AER has classified our regulated distribution services as Direct Control Services and separately classified into Standard Control Services and Alternative Control Services. Standard Control Services are core network, connection and metering services associated with the access and supply of electricity to customers. They include network services (e.g. construction, maintenance and repair of the network), some connection services (e.g. small customer connections) and Type 7 metering services. Ergon Energy recovers our costs in providing Standard Control Services through network tariffs which are billed to retailers. Alternative Control Services are comprised of: Fee based services regulated distribution activities Ergon Energy undertakes at the request of an identifiable customer, retailer or appropriate third party which are in addition to our Standard Control Services and are levied as a separate charge. These services are priced on a fixed fee basis as the costs of providing the service (and therefore price) can be assessed in advance of the service being requested by a customer or retailer (e.g. de-energisations, re-energisations, and supply abolishment etc.). Quoted services similar to fee based services, but they are priced on application as the nature and scope of these services are variable and the costs (and therefore price) are specific to the individual retailer s or customer s needs (e.g. design and construction of connection assets for major customers, real estate development connections, special meter reads etc.). Default Metering Services relate to the provision, installation, maintenance, reading and data services of basic electricity meters (Type 5 and 6) for small to medium business and residential customers. These are the meters that measure the electricity that goes into a property, and which allow electricity retailers to bill their customers. Ergon Energy recovers our costs of providing Default Metering Services through charges based on the number and type of meters we provide the customer. A separate upfront charge for new or upgraded meters is also payable. Public Lighting Services relate to the provision, construction and maintenance of public lighting assets owned by Ergon Energy, and emerging public lighting technology. Ergon Energy recovers our costs of providing Public Lighting Services through a daily public Information Guide for SCS Pricing v1.1 page 5

6 lighting charge billed to retailers. We also charge a one-off exit fee, which is payable when a public light is scrapped before the end of its useful operational life Purpose and structure This Information Guide sets out the basis upon which Ergon Energy s revenue cap for Standard Control Services is to be recovered from various customer groups through network tariffs, as well as a description of the network tariffs that apply in The aim of this Information Guide is to assist stakeholders understand how network tariffs are calculated for all users of our distribution network for the current regulatory control period (i.e ). Information on Alternative Control Services is contained in the Information Guide for Alternative Control Services Pricing and the Price List for Alternative Control Services (see Section 1.4). 1.3 Use of terms The term network tariffs is used interchangeably with network prices and refers to tariffs for Standard Control Services. The term network tariffs is used by Ergon Energy to distinguish between our tariffs and the regulated retail tariffs (or Notified Prices) as gazetted by the Queensland Government. Where a section of this document applies to both customers and Embedded Generators (EGs) the term network user is used. Where the term customer is used in a section of this document, that section applies to customers only (i.e. it does not apply to EGs). Where the term TUOS is used in a section of this document, it includes all designated pricing proposal charges incurred for Transmission Use of System (TUOS) services as defined in the NER and set out in the Distribution Determination. 1.4 Supporting network pricing documents In addition to this Information Guide, Ergon Energy has a number of network pricing documents to assist customers, retailers and interested parties understand the development and application of tariffs and connection charges. The documents outlined in Figure 1.1 below provide further information about network tariffs, Network Tariff Codes, loss factors and detailed information about operational issues relating to Standard and Alternative Control Services Outside of our light emitting diode (LED) transition program. All customers supplied by Ergon Energy s isolated generation assets are excluded from the jurisdiction of the AER and, as such, are not included in this Information Guide. The isolated generation zone is regulated by the Department of Energy and Water Supply. These documents are available on Ergon Energy s website at: Information Guide for SCS Pricing v1.1 page 6

7 Figure 1.1: Supporting network pricing documentation Network Tariff Guide An operational document for customers, retailers and consultants, setting out the Network Tariff Codes, as well as application rules and rates for each Network Tariff Code Applies to network users connected to Ergon Energy's regulated distribution network Published annually, and updated as required Pricing Proposal Provides additional guidance on the compliance requirements of Chapter 6 of the NER, and how Ergon Energy's prices for our Standard and Alternative Control Services meet these requirements Submitted to the AER annually, and updated as required Information Guide for Alternative Control Services Pricing Sets out the basis upon which Alternative Control Services pricing is set and approved by the AER Provides details on the assignment of customers to tariff classes Published annually Price List for Alternative Control Services Sets out Ergon Energy's Alternative Control Services and the prices that apply for fee based services, Default Metering Services and Public Lighting Services Published annually, and updated as required Connection Policy Sets out when a connection charge may be payable by retail customers or real estate developers and the aspects of the connection service for which a charge may be applied Details how Ergon Energy calculates the capital contribution to be paid This policy was approved by the AER in April 2015 at the time of the Distribution Determination 1.5 Further information Network users and retailers who are uncertain about the network pricing process or their particular circumstances are encouraged to contact us for assistance: Manager Regulatory Determination and Pricing Ergon Energy Corporation Limited PO Box 264 FORTITUDE VALLEY QLD 4006 Phone: [email protected] Information Guide for SCS Pricing v1.1 page 7

8 2. Regulatory framework 2.1 National Electricity Law Ergon Energy and the AER must have regard for the revenue and pricing principles outlined in section 7A of the Law when setting revenue and pricing control regimes and the resultant prices for Standard Control Services. In summary, the revenue and pricing principles are: a regulated network service provider should be provided with a reasonable opportunity to recover at least the efficient costs incurred in providing the services a regulated network service provider should be provided with effective incentives in order to promote economic efficiency regard should be had to the regulatory asset base of a distribution or transmission system a price or charge should allow for a return commensurate with the regulatory and commercial risks involved in providing the service regard should be had to the economic costs and risks of the potential for under and over investment in a regulated distribution or transmission system regard should be had to the economic costs and risks of the potential for under and over utilisation of a regulated distribution or transmission system. 2.2 National Electricity Rules Clause of the NER requires Ergon Energy to annually submit a Pricing Proposal to the AER. The AER will only approve a Pricing Proposal, including the network tariffs Ergon Energy develops for Standard Control Services, if it complies with Chapter 6 of the NER and the AER s Distribution Determination. Ergon Energy s Pricing Proposal must include, among other things: details on the proposed tariff classes, and tariffs within those tariff classes which have been developed and constituted having regard for the various principles set out in the NER explanations of how Ergon Energy s tariff classes, tariffs and charging parameters within each tariff meet certain economic tests in the NER information of variations or adjustments to each tariff class for the upcoming year information on how TUOS charges are to be passed through to customers explanations of how Ergon Energy s tariff classes for Standard Control Services meet applicable side constraints. Ergon Energy s Pricing Proposal provides additional guidance on the compliance requirements of Chapter 6, and how Ergon Energy s network prices meet these requirements. 2.3 Distribution Determination Preliminary Determination On 30 April 2015, the AER made its Preliminary Determination for regulated distribution services provided by Ergon Energy. The Preliminary Determination effectively sets the revenue and pricing Information Guide for SCS Pricing v1.1 page 8

9 control regime that Ergon Energy must comply with in for these services. It also details jurisdictional scheme arrangements relating to the Queensland Government s Solar Bonus Scheme Substitute Determination Under transitional arrangements, the Preliminary Determination will be revoked and substituted (the Substitute Determination) by 31 October Although the Substitute Determination will not be made until after the commencement of the regulatory control period , it will be applied as from 1 July 2015, with a true-up applied to account for changes between the Preliminary Determination and the Substitute Determination. These true-up adjustments for Standard Control Services include increasing or decreasing the Annual Revenue Requirement (ARR or smoothed revenue requirement ) set out in the Post Tax Revenue Model (PTRM) for one or more remaining regulatory years of the regulatory control period by an adjustment amount. This amount is calculated as: the amount of the ARR that was approved by the AER for the first regulatory year of the regulatory control period in the Preliminary Determination, less the amount of the ARR for the first regulatory year of the regulatory control period that is determined in the Substitute Determination. 5 Further information on the true-up adjustments made by the AER is available in the Substitute Determination. 2.4 Network Tariff Strategy There has been a major shift in the way our customers use the electricity network in recent years. Strong economic growth in the early 2000s, coupled with a drop in the price of electrical appliances (including air conditioning), led to a dramatic increase in demand for electricity during peak usage periods. In more recent times, while peak demand has remained high, the economic slowdown, the growing use of solar energy and the focus on energy efficiency (as retail electricity prices have risen) has led to a drop in electricity use overall. This means our network, which we invested in heavily to respond to the growth in demand during peak times (which can occur for only a few days a year), is now not being used as effectively as it could be outside peak times. Ergon Energy is therefore restructuring the way we charge for the use of our distribution network to help ensure we maintain a viable network for our customers into the future. This process is expected to take a number of years, with the first changes implemented in To help develop the tariff changes outlined here we have consulted with a wide range of our customers and our stakeholders over the past two years. The resulting short, medium and longer term tariff development intentions have been available and progressively updated on our website since June 2013, 6 and have been subject to multiple rounds of public consultation. The tariff structures are designed to allow our customers, through their retail account, to better understand the cost associated with accessing the network and the time they use electricity. This is particularly important when making the decisions around any future investment and use of new energy-related technologies, such as on-site generation, batteries and storage, electric vehicles, home automation, and other emergent innovations NER, clause (c). NER, clause (e) Information Guide for SCS Pricing v1.1 page 9

10 In broad terms, Ergon Energy introduced the following changes to network tariff structures in : extended kva as the basis for the demand tariffs to all very large energy users (energy consumption greater than 4 GWh per annum) introduced excess kvar charging for our largest customers (energy consumption greater than 40 GWh per annum) introduced an optional Seasonal Time-of-Use Demand (STOUD) tariff to all customers with energy consumption less than 40 GWh per annum reduced the number of customer specific tariffs by introducing standard tariff rates for Connection Asset Customers (CAC). It should be noted that Ergon Energy s network tariff development pathway is being deployed in an increasingly dynamic industry, regulatory and market environment. With fundamental regional Queensland market changes possible in the short to medium term, and uncertainty around the level of market and customer response to the new tariffs, a tariff development pathway that is responsive to these changes is required. While the fundamental themes, underlying drivers and future pathway of the network tariff strategy development are not expected to change, the actual rate and depth of deployment may. Our intention is to continue to consult with our customers and stakeholders, and maintain transparency of our network tariff development plans. It is important to note that as market reforms increasingly impact on the electricity supply industry, Ergon Energy s network tariff structures will evolve on a continuous basis Information Guide for SCS Pricing v1.1 page 10

11 3. Establishing tariffs for Standard Control Services 3.1 Overview Ergon Energy s Standard Control Services are regulated under a revenue cap form of price control. The revenue cap for any given year reflects Ergon Energy s smoothed revenue requirement, as determined by the AER s PTRM, plus adjustments relating to: inflation incentive schemes annual adjustment factors like Distribution Use of System (DUOS) under or over recovery adjustments other factors such as amounts associated with the occurrence of any prescribed and nominated pass through events. The resulting revenue cap is then recovered from various customer groups through network tariffs in accordance with our network tariff development process summarised in Section 3.3. Designated pricing proposal charges (or TUOS) and jurisdictional scheme amounts relating to feed-in tariff (FiT) payments made under the Solar Bonus Scheme are then allocated to customers. 3.2 Annual revenue requirement Clause 6.4.3(a) of the NER requires the ARR or smoothed revenue requirement to be determined using a building block approach. The total revenue that Ergon Energy will require each year over the regulatory control period is calculated using a build-up of operating, financing and investment costs relevant to providing our regulated services. The building block approach used to calculate the ARR is prescribed under Chapter 6 of the NER. 3.3 Development of network tariffs The development of Ergon Energy s network tariffs involves six steps: 1. the establishment of zones where customers have similar cost of supply 2. the calculation of the Long Run Marginal Cost (LRMC) for tariff groups by zone, the allocation of the revenue cap to zones, TUOS to customers so as to preserve, where possible, the transmission pricing signals and jurisdictional scheme amounts 3. the allocation of the zonal costs to the different asset categories within each zone 4. the identification of network users of similar size or similar use of assets and their assignment to various network user groups 5. the allocation of the costs within the zones to the network user groups 6. the conversion of these allocated costs into network tariffs that recover those costs and are economically efficient. The network tariffs developed for Standard Control Services are cost reflective in that there is a direct relationship between the network tariff for the service and the costs of delivering that service, derived through the methodology described in this section and depicted in Figure 3.1 below. Further explanation of each of the six steps is set out below. Additional detail on the network tariff methodology is provided in Appendix Information Guide for SCS Pricing v1.1 page 11

12 Figure 3.1: Network tariff development * Ergon Energy's ARR (prior to annual revenue adjustments) is determined by the AER using a building block approach. The building block components comprise allowances for return on assets (ROA), regulatory depreciation (depreciation), operating expenditure (opex) and a tax allowance. For pricing purposes, revenue associated with the tax allowance and other revenue adjustments (included in the building blocks or calculated in the revenue cap formula) is pro-rated across the ROA, depreciation and opex building block components Information Guide for SCS Pricing v1.1 page 12

13 3.4 Step B1: Zone determination The first step of the overall network tariff development process is to determine the number and extent of the cost zones to be used for establishing network tariffs in the most efficient and cost reflective way. The determination of zones is based on a combination of: a comparison of the distances the customers are from a Transmission Network Connection Point (TNCP) the further from the connection point the more distribution assets required minimising cross-subsidisation between the higher cost, less populated western networks, and the lower cost, more heavily populated eastern networks the further the distance and lower the population density, the more expensive the assets and higher the cost to supply identifying those geographic areas which have a similar cost to supply remote areas of western and far northern Queensland compared with the higher density eastern areas simplicity for customers and retailers to understand identifying a logical "break point" in the electrical supply network open points in the distribution system that separate different areas of supply. Three pricing zones have been delineated in the Ergon Energy area of supply, broadly based on Queensland s local government areas (LGAs), with the distribution network electrical connection being the final determinant of which zone applies. Zone pricing impacts DUOS prices only; TUOS prices are not impacted by zones. The three pricing zones 7 are: East Zone those areas where the network users are supplied from the distribution system connected to the national grid and have a relatively low distribution cost to supply West Zone those areas outside the East Zone and connected to the national grid, which have a significantly higher distribution cost of supply than the East Zone Mount Isa Zone broadly defined as those areas supplied from the isolated Mount Isa system. This zone is not connected to the national grid and, as such, would normally be excluded from the application of the NER. However, under the Electricity National Scheme (Queensland) Act 1997, the Queensland Government has transferred responsibility for the economic regulation of the Mount Isa Cloncurry supply network to the AER. The LGAs covered by each zone are detailed in Figure 3.2 below. A map depicting each zone is detailed in Figure 3.3 below 7 Areas supplied from isolated (remote) generation are not included in any of the below zones Information Guide for SCS Pricing v1.1 page 13

14 Figure 3.2: Zone coverage East The whole LGAs of: Bundaberg (R) Cairns (R) Cassowary Coast (R) Fraser Coast (R) Gladstone (R) Mackay (R) North Burnett (R) Rockhampton (R) South Burnett (R) Southern Downs (R) Toowoomba (R) Whitsunday (R) Townsville (C) Banana (S) Livingstone (S) Burdekin (S) Hinchinbrook (S) Cherbourg (S) Woorabinda (S) Yarrabah (S) West The whole LGAs of: Barcaldine (R) Blackall - Tambo (R) Charters Towers (R) Longreach (R) Maranoa (R) Balonne (S) Bulloo (S) Carpentaria (S) Cook (S) Croydon (S) Etheridge (S) Flinders (S) Hope Vale (S) McKinlay (S) Murweh (S) Paroo (S) Quilpie (S) Richmond (S) Winton (S) Wujal Wujal (S) Mount Isa Consists of the regulated network within the whole LGAs of Cloncurry (S) and Mount Isa (C), and those parts of Burke (S) and Boulia (S) supplied from the Mount Isa system. Part of the following LGAs: Gympie (R) (Ergon Energy area only) Douglas (S) (excluding areas north of the Daintree River) Isaac (R) (excluding areas west of Moranbah township) Western Downs (R) (Dalby township and Wambo district only) Central Highlands (R) (excluding Emerald and areas west of Emerald) Tablelands (R) (excluding Herberton areas not supplied by the "East" distribution system) Mareeba (S) (excluding areas not supplied by the "East" distribution system) Part of the following LGAs: Barcoo (S) (connected to national electricity grid only) Douglas (S) (north of the Daintree River only) Goondiwindi (R) (Ergon Energy supply area only) Isaac (R) (west of Moranbah township only) Western Downs (R) (excluding Dalby township and Wambo district) Central Highlands (R) (Emerald and areas west of Emerald only) Tablelands (R) (Herberton areas not supplied by the "East" distribution system only) Mareeba (S) (areas not supplied by the "East" distribution system only) Note: (R) = Regional Council, (S) = Shire Council and (C) = City Council Information Guide for SCS Pricing v1.1 page 14

15 Figure 3.3: Zone map Information Guide for SCS Pricing v1.1 page 15

16 3.5 Step A2: LRMC for tariff groups LRMC tariffs introduce new and different pricing principles to the legacy tariffs. Legacy tariffs have been developed using the cost allocation methodology. Effectively, Ergon Energy s tariffs are in transition from a backward looking accounting based interpretation of historic cost-causality to a forward looking LRMC basis incorporating effective economical pricing principles that inform efficient and optimal usage of the network. LRMC pricing principles result in a two part tariff outcome. The first part promulgates the LRMC price signal while the second part addresses residual revenue recovery. In developing the new LRMC tariffs, our objective has been to present the LRMC component through parameters which are as cost reflective as possible and aligned with enabling customer responses that support optimal use (or not) of the network. In establishing and populating the parameters to recover residual revenue, Ergon Energy has targeted minimising any distortionary impact of the non-lrmc based parameters on customer response to the LRMC signals. Therefore, Ergon Energy s tariffs have been established with a view to developing LRMC tariff parameters that customers are likely and able to respond to, while choosing and calibrating residual recovery parameters that are less likely to distort the LRMC signals, encourage inefficient use of the network, or encourage inefficient by-pass. Basically we have calibrated the LRMC tariffs to maximise response to the LRMC parameter and minimise response to the other parameters. In applying these principles in we have not adopted full incorporation of the LRMC in the LRMC parameter. Instead, we are adopting a transitional approach which is expected to see the LRMC parameter progressively become stronger while the residual components are reduced. Consistent with the above, the LRMC is recovered over a relatively short proportion of the year. The LRMC period for Ergon Energy is calibrated seasonally (December, January and February), by day of week, and by time of day. Peak times are different between the residential and business Standard Asset Customers (SAC) segments for SAC <100 MWh p.a. customers. The LRMC is calibrated in demand (kw for SAC and kva for CAC) for STOUD tariffs. A Seasonal Time-of-Use Energy (STOUE) tariff is also offered for SAC <100 MWh p.a. customers. The peak demand parameter price has not only been set with a view to customers being able to respond to the LRMC price signal, but also to ensure that the signal is active only when additional demand on the network is likely to contribute to driving future network augmentation. The role of the remaining parameters is recovery of residual revenue with as little distortionary impact on network usage as possible. The fixed, off-peak demand and volume (kwh) parameters have been calibrated to support minimal customer demand response. For Individually Calculated Customers (ICC), we have introduced an excess kvar charge. This charge is applied against kvar drawn from the network that exceeds a permissible kvar quantity. The permissible kvar quantity is derived from the authorised demand operating at a minimum compliant power factor level. Essentially this charge reinforces the price signal introduced by the change to the kva tariff, which encourages customers to improve power factor and reduce their usage of network capacity. We have amended our approach to LRMC in A summary of these changes is provided in Table Information Guide for SCS Pricing v1.1 page 16

17 Table 3.1: Summary of changes to LRMC Issue Changes Choice of method for calculating LRMC Costs to be included in LRMC for AIC Approach to estimating LRMC using LRIC Allocation of LRMC to peak charges Application of LRMC to tariffs Movement away from the Benchmark Cost of Supply (BCS) to the Average Incremental Cost (AIC) approach with separate verification using a Long Run Incremental Cost (LRIC) approach Consistency check against LRIC model as used by United Kingdom (UK) distributors (termed the 500 MW model) Network demand related capital costs Incremental operating and maintenance expenditure associated with the demand related capital costs A hypothetical greenfield model to supply a demand of 500 MW using modern asset replacement, operation and maintenance costs Model uses Ergon Energy s system configuration and voltage levels and achievable levels of asset utilisation Given the relatively large difference between current peak charges and LRMC based peak charges, we are proposing a transitional allocation of LRMC to the peak charge in For existing tariffs comparison with demand or peak period energy rates with a view to their progressive alignment For SAC >100 MWh p.a. application to the customer s maximum demand on potential peak days during peak times in each summer month (i.e. December, January and February) For SAC <100 MWh p.a. application to the average of the customer s demand recorded during peak times for the highest four peak demand days in the month in the STOUD tariff and equalisation of the peak and shoulder energy rates in the STOUE tariff For CAC STOUD tariffs incorporation into the peak capacity charge applied over the summer peak period Ergon Energy has applied the values contained in Table 3.2 to the peak charge: Table 3.2: LRMC charges User group Region LRMC applied per annum CAC - 22/11 kv Lines East $ / kva West $ / kva CAC - 22/11 kv Bus East $ / kva West $ / kva CAC - Higher voltages East $50.00 / kva West $ / kva East $ / kw SAC >100 MWh p.a. West $ / kw Mount Isa $ / kw SAC <100 MWh p.a. Residential East $ / kw TOU Demand West $ / kw TOU Energy West $ / kw Mount Isa $ / kw SAC <100 MWh p.a. Business East $ / kw TOU Demand West $ / kw TOU Energy West $ / kw Information Guide for SCS Pricing v1.1 page 17

18 User group Region Mount Isa LRMC applied per annum $ / kw The LRMC applied for the West Zone is impacted by the sparse footprint of customers in this zone. 3.6 Step B2: Allocation of the revenue cap to zones The second step in the network tariff development process is to allocate the revenue cap to each of the three zones. The revenue cap comprises the following components: ROA depreciation opex tax allowance together with revenue adjustments resulting from the AER s smoothing of the ARR, adjustments made for out-turn inflation, unders and overs in DUOS, shared assets and capital contributions, 8 and adjustments for the Service Target Performance Incentive Scheme (STPIS) and pass through amounts. The tax allowance and other revenue adjustments are pro-rated across the building block cost components of ROA, depreciation and opex based on each building block s share of the revenue cap. Capital contributions adjustments are allocated directly to the SAC tariff classes to which they are attributable. The final composite building block cost components are allocated to each of the three zones by apportioning each component using the following cost drivers: opex allocated on asset values, customer numbers and energy usage ROA allocated on asset values depreciation allocated on asset values. Where networks in the West Zone are supplied by shared network systems in the East Zone, the appropriate allocators are used to apportion a share of the cost to both zones. 3.7 Step C2: Allocation of designated pricing proposal charges to customers Powerlink charges are allocated on the basis that customers who are able to respond to a TUOS signal should receive that signal. Ergon Energy s network tariff calculation process passes through Powerlink charges as cost reflectively as possible. Powerlink charges Ergon Energy at an aggregated level by TNCP which means that Ergon Energy needs to devise a methodology to apportion the various components of the Powerlink charges to customers. The TUOS charges charged to Ergon Energy by Powerlink at each TNCP have four components: Entry/Exit Connection Price ($/month) Capped Customer TUOS Usage Price: Usage Capacity Price ($/kw/month of nominated demand plus $/kw/month average demand) 8 Applicable for and only, as per the Distribution Determination Information Guide for SCS Pricing v1.1 page 18

19 Customer TUOS General Prices: General Energy Charge (c/kwh of historical energy) Transmission Customer Common Service Prices: Common Service Energy Price (c/kwh on historical energy). These charges are apportioned by Ergon Energy to customers and/or customer groups on the basis of forecast ATMD with respect to the Entry/Exit Connection Price and the Usage Capacity Price, and apportioned on the basis of historical and forecast energy for the remaining components. For ICC connections on site-specific charges, Ergon Energy takes into account the fact that customers can be supplied from different connection points depending on switching arrangements. Charges will continue to be apportioned based on the actual Bulk Supply Points the connection is supplied from. A weighted average methodology is applied for each of the Transmission Connection Points so that these site-specific connections have cost-reflective TUOS charges. For CAC and SAC connections, charges for each Bulk Supply Point are allocated to one of three geographical TUOS Regions. TUOS charges are calculated based on the combined totals. This simplifies the tariffs, while still providing clear TUOS locational signals for these customers. Inter-DNSP charges In the Toowoomba area, Ergon Energy utilises network services from the other Queensland DNSP, Energex, to supply a small group of customers that cannot be economically supplied from the Ergon Energy distribution system. Energex bills Ergon Energy a network service charge for these network services. Additionally, in the Mount Isa Zone, Ergon Energy is charged for the use of the unregulated 220 kv network which supplies the Cloncurry Township. These costs are recovered by Ergon Energy as part of the TUOS charges passed through to customers. Avoided TUOS payments Where Ergon Energy is liable for an Avoided TUOS payment to an EG, the payment amount is recovered by Ergon Energy as part of the TUOS charges passed through to customers at the same connection point as the EG. 3.8 Step D2: Calculation of jurisdictional scheme amounts Jurisdictional schemes are certain programs implemented by state governments that place legislative obligations on DNSPs. Jurisdictional schemes comprise: schemes set out explicitly under clause A(e) of the NER. For Queensland, this includes the Solar Bonus Scheme, which obligates Ergon Energy to pay a FiT for energy supplied into our distribution network from specific micro-embedded generators those schemes determined by the AER to be jurisdictional schemes under clause A(l) of the NER. At the time of publishing this Information Guide, there are no jurisdictional schemes captured by this clause in Jurisdictional scheme amounts relating to the Solar Bonus Scheme are based on our forecasts of FiT payments we expect to make for the relevant year, adjusted for the time cost of money. In order to forecast payments under the Solar Bonus Scheme, we take a number of factors into account. First, we consider the number of existing inverter energy systems meter service orders that we have closed off in our financial reporting system. We then take into account the mean size of the installed solar arrays and historical monthly export in kwh per unit of installed capacity. This allows us to take into account seasonal changes in energy exports Information Guide for SCS Pricing v1.1 page 19

20 3.9 Step B3: Allocation of zonal costs to asset categories The third step of the network tariff development process is to apportion the zone costs to the different asset categories within each zone. This occurs within Ergon Energy s tariff development model, the Distribution Cost of Supply (DCOS) Model. The asset categories are: Network Operation Assets system assets associated with monitoring and controlling the distribution network from the operational control centres Network Distribution Assets system assets employed in the provision of network connection and distribution services. These assets are further categorised by voltage level as follows: o o o o o o o o o o 110/132 kv 66 kv Bus 66 kv Line 33 kv Bus 33 kv Line 22/11 kv Bus 22/11 kv Line low voltage (LV) services (LV only) meters Other Assets non-system assets (e.g. vehicles, computers, and buildings etc.). The building block costs by zone are then allocated to the asset categories in the manner described in Table 3.3 below. Table 3.3: Subdivision of cost components Opex Network Operating Costs Network Maintenance Costs Other Asset Operating Costs Associated with monitoring and controlling the distribution network from the operational control centres Not directly related to any single customer or group of customers Allocated directly to the customers based on energy usage Not applicable to EGs Associated with the repair and maintenance of the distribution network within the Preventive, Corrective and Forced Maintenance categories Allocated to the voltage level asset categories based on asset values The summation of the non-system based costs (e.g. corporate shared costs (overheads), customer services, computer systems and human resources etc.) Treated as a group as it is impractical to manage a cost allocation process for each of the specific components Allocated directly to the network users based on hybrid allocation of network user numbers and energy usage, and applied to all network users Information Guide for SCS Pricing v1.1 page 20

21 ROA Network Operation Assets ROA Network Distribution Assets ROA Other Assets ROA Allocated to the network operations asset categories on the basis of asset values Allocated to the voltage level asset categories on the basis of asset values Allocated to the other asset categories on the basis of asset values Depreciation Network Operation Assets Depreciation Network Distribution Assets Depreciation Other Assets Depreciation Allocated to the network operation asset categories on the basis of asset values Allocated to the voltage level asset categories on the basis of asset values Allocated to the other asset categories on the basis of asset values 3.10 Step B4: Determination of groups of network users In this fourth step it is necessary to determine the groups of network users that will be used to recover Ergon Energy s revenue cap for Standard Control Services. To provide the appropriate economic and cost of supply signals, four key groups of customers have been established (with multiple tariff classes within these groups). These groups are: Individually Calculated Customers (ICCs) Connection Asset Customers (CACs) Standard Asset Customers (SACs) Embedded Generators (EGs). The purpose of the above four groups is to enable network tariffs to be developed that provide individual or direct cost of supply signals to those network users where possible, while recognising that it is not possible to price every network user individually. There is a trade-off at the distribution level between the complexity of individual price calculation and the inefficiencies created through price averaging. A practical limit also arises in the number of site specific network tariffs that can feasibly be determined and administered. A description of the four network user groups and the basis of their network tariffs are provided in Table 3.4. Table 3.4: Ergon Energy s network user groups Network user ICC group Description Those customers: with energy consumption typically greater than 40 GWh per annum (p.a.), or with energy consumption lower than 40 GWh p.a. where: o a customer has a dedicated supply system which is quite different and separate from the remainder of the supply network o there are only two or three customers in a supply system making average prices inappropriate o a customer is connected at or close to a TNCP, or o inequitable treatment of otherwise comparable customers will arise from the application of the 40 GWh p.a. threshold Information Guide for SCS Pricing v1.1 page 21

22 Network user CAC group Description Those customers: with required capacity above 1,500 kva with energy consumption typically greater than 4 GWh p.a., or with required capacity below 1,500 kva where: o a customer has a dedicated supply system which is quite different and separate from the remainder of the supply network, or o inequitable treatment of otherwise comparable customers will arise from the application of the 4 GWh p.a. threshold. The CAC group is further subdivided into categories based on voltage levels as follows: 66 kv connected to either a 66 kv substation or a 66 kv line 33 kv connected to either a 33 kv substation or a 33 kv line 22/11 kv Bus connected to either a 22 kv or 11 kv substation 22/11 kv Line connected to either a 22 kv or 11 kv line. SAC EG All other load customers. This includes customers with micro generation facilities (such as small scale photovoltaic (PV) generators) that have exporting capability and an inverter capacity as per Australian Standard (AS) The SAC group is further subdivided into network tariff categories based on whether: the customer s connection is metered or unmetered the customer s consumption relates to residential or business use the customer is taking supply at high voltage or low voltage the customer s consumption is above or below 100 MWh p.a. the customer has a meter installed capable of recording demand the customer s supply is capable of being controlled by Ergon Energy. Those network users that export energy into the distribution system. EGs do not include micro-embedded generators as defined under AS4777. EGs are separated into two categories: EGs that are connected to the distribution system and only generate into the distribution system EGs that are connected to the distribution system, generate and take load from the system Step B5: Allocation of costs within zones to network user groups The fifth step of the overall network tariff development process is to allocate or assign the costs to the network user groups in the most efficient and cost reflective way Allocation of costs to ICCs For each ICC: Network Operation Asset costs (i.e. ROA, depreciation and opex) are allocated on the basis of each ICC s energy consumption Network Distribution Asset costs (i.e. ROA, depreciation and opex) for both dedicated connection assets and shared assets are allocated as follows: o the costs are broken down by voltage level asset category and allocated to each ICC separately based on the proportion of the ICC s replacement cost for that asset category to the whole-of-network replacement cost for that asset category Information Guide for SCS Pricing v1.1 page 22

23 o the costs allocated to each ICC by voltage level asset category are summed to give the total cost for each ICC Network Distribution Asset costs (i.e. opex only) for new or augmented dedicated connection assets connected under the Large Customer Connection arrangements that apply post 30 June 2010 which have been paid for upfront by the customer or alternatively assets have been gifted to Ergon Energy following construction by the customer: o o the costs are broken down by voltage level asset category and allocated to each ICC separately based on the proportion of the ICC s replacement cost for that asset category to the whole-of-network replacement cost for that asset category the costs allocated to each ICC by voltage level asset category are summed to give the total cost for each ICC Other Assets costs (i.e. ROA, depreciation and opex) are fixed for each ICC and are calculated based on the equal sharing of the total other asset costs to be allocated to all ICCs, which is in turn based on the proportion of ICC customer numbers to total customer numbers, and the proportion of ICC energy consumption to the total energy consumption of all customers Allocation of costs to CACs For each CAC: Network Operation Asset costs (i.e. the ROA, depreciation and opex) are allocated on the basis of each CAC s energy consumption Network Distribution Asset costs (i.e. ROA, depreciation and opex) for both dedicated connection assets and shared assets are allocated as follows: o o o for dedicated assets, costs are broken down by voltage level asset category and allocated to each CAC separately based on the proportion of the CAC s replacement cost for that asset category to the whole-of-network replacement cost for that asset category for shared assets, costs are broken down by voltage level asset category and allocated to each CAC separately based on the proportion of each CAC s kw demand to the kw demand for that asset category the costs allocated to each CAC by voltage level asset category are summed to give the total cost for each CAC Network Distribution Asset costs (i.e. opex only) for new or augmented dedicated connection assets connected under the Large Customer Connection arrangements that apply post 30 June 2010 which have been paid for upfront by the customer or alternatively assets have been gifted to Ergon Energy following construction by the customer: o o the costs are broken down by voltage level asset category and allocated to each CAC separately based on the proportion of the CAC s replacement cost for that asset category to the whole-of-network replacement cost for that asset category the costs allocated to each CAC by voltage level asset category are summed to give the total cost for each CAC Other Assets costs have both a fixed and variable component with each component allocated 50 per cent of each CAC s total other asset costs. The variable component is allocated to each CAC on the basis of each CAC s energy consumption Information Guide for SCS Pricing v1.1 page 23

24 Allocation of costs to SACs Unlike ICCs, CACs and EGs, costs are not allocated directly to individual SACs. Rather, they are allocated to SAC network tariff categories according to the following process: the connection asset costs for each SAC network tariff category are calculated for each asset category utilised by the SAC network tariff category based on the replacement cost of those assets the shared network costs for each SAC network tariff category are allocated based on the Any Time Maximum Demand (ATMD) of that SAC network tariff category Network Operation Asset costs are allocated to each SAC network tariff category on the basis of energy consumption Other Assets costs are allocated to each SAC network tariff category on the basis of both customer numbers and energy consumption Allocation of costs to EGs Costs are allocated to each EG in the same manner as for CACs including Network Distribution Asset costs (i.e. opex only) for new or augmented dedicated connection assets connected under the Large Customer Connection arrangements that apply post 30 June 2010 which have been paid for upfront by the customer or alternatively assets have been gifted to Ergon Energy following construction by the customer. Note however, that no Network Operation Asset costs are allocated to EGs Step A6 and B6: Conversion of allocated costs into network tariffs The sixth step in the development of network tariffs is the conversion of the allocated costs for network users to network tariffs. The network tariffs comprise a number of charging parameters, each selected and structured to provide signals to network users about the efficient use of the network and the impact of their usage on future network capacity and costs. In developing network tariffs, Ergon Energy has sought to have the charging parameters signal the impact that the network users will have on the network, while: managing the demand and volume variance risk minimising zonal boundary issues between and within network user groups avoiding any signals that may result in perverse outcomes. The charging parameters that have been adopted for are outlined in the sub-sections below Fixed charges The fixed charge has been applied to serve two broad purposes. For some customers within a tariff class, it seeks to reflect the incremental costs that arise from the connection and management of the network user. The fixed charge is also used to help recover a share of residual or sunk elements of Ergon Energy s costs. For example, for SACs <100 MWh p.a., the fixed charge also recovers a portion of the shared network costs. Fixed charges, levied on a rate per day basis, apply to all network users, but not all tariffs. In the case of the STOUD tariff for SAC <100 MWh p.a. residential and business customers, no explicit fixed charge applies Information Guide for SCS Pricing v1.1 page 24

25 However, a minimum off-peak chargeable demand of 3 kw per month is applied in the nine non-summer months. A minimum off-peak chargeable demand is also applied in the optional STOUD tariff offered to CAC customers in the nine non-summer months as follows: 22/11 kv Line 750 kva 22/11 kv Bus 850 kva Higher Voltages 1,000 kva Connection unit charges Traditionally for CACs, customer connection charges have been based on their specific connection configuration and presented explicitly through individual tariffs. In , we have represented this connection charge (same charge level) in a revised format which supports simplification and standardisation of charges to the CAC network user group. The framework proposed is based on the establishment of a standard daily connection charge which is multiplied by an individual customer number of connection units to calculate an individual customer connection charge. Customers will be individually advised of the connection unit multiplier value attributed to their National Metering Identifier (NMI) and this would remain unchanged other than for a significant change in connection arrangements. This separation of the customer s individual connection unit multiplier and a standard fixed connection charge is similar to capacity charging where each CAC customer has their individual authorised demand applied against a standard fixed capacity rate Capacity and actual demand charges Shared network costs for ICCs, CACs, SACs >100 MWh p.a. and some SACs <100 MWh p.a. are recovered through the capacity charge and/or actual demand charge components. These charges provide economic signals to the customers on the existing and future use of the shared network on the basis that customers who place greater pressure on the system incur higher charges. Each of these charges is discussed further below. LRMC/peak charge components Setting the level and structure of the peak charge component under demand based tariffs is important in terms of establishing pricing mechanisms that reflect the LRMC of supply and are effective in providing a price signal to customers to reduce demand in peak network congestion periods. Setting the peak charge based on the LRMC encourages customers to invest in demand management technologies or change their behaviour only to the extent that it is cheaper (or more valuable to the customer) than the cost to Ergon Energy of increasing network capacity. The peak components of the maximum demand tariffs in the suite of STOUD tariffs were designed based on considering alternative mechanisms for charging demand in the peak and shoulder periods. The mechanisms chosen are considered to be both cost reflective of the LRMC of the cost of supplying electricity and effective in enabling customers to respond to price signals. The peak demand charges proposed in the tariffs are based on a transitional approach to signalling LRMC. We took into account customer concerns and impacts as well as the level of uncertainty and volatility in the LRMC value when determining the peak charge to apply. In the LRMC based STOUD tariffs (applied at CAC, SAC >100 MWh p.a. and SAC <100 MWh p.a. level), actual demand charges have both a peak, and off-peak component. The peak demand charge relates to only demand during the peak periods in each month of the summer season Information Guide for SCS Pricing v1.1 page 25

26 Residual/Off-Peak charge components Regulated revenue not recovered through the LRMC related charge should be recovered in a manner that has as little influence as possible on patterns of electricity demand. Ergon Energy considered a number of choices as options to recover residual costs. These include: fixed charges ($/day) off-peak or anytime energy charge (c/kwh) off-peak network demand with or without a minimum chargeable demand ($/kw capacity). The combinations proposed across the various user groups have been selected on efficiency and effectiveness as well as ability of customers to respond. Demand charges are also utilised in the legacy tariffs available to ICCs, CACs, and SACs >100 MWh p.a. These charges are discussed further below. Capacity charges The capacity charge applies to ICC and CAC network users only. The demand used for the calculation of the capacity charge is the authorised demand or, if there is no authorised demand, the annual maximum demand in the previous full pricing period prior to the setting of prices. Under certain circumstances, where there has been a significant change in demand attributable to a network user's load change after this previous pricing period, a more recent demand may be substituted. Further, where the actual demand exceeds the authorised demand in any one month, the actual demand will be substituted for the authorised demand in the calculation of the capacity charge for that month. Actual demand charges Actual demand charges apply to all ICC, CAC and SAC >100 MWh p.a. customers and also to the SAC <100 MWh p.a. demand tariffs (Business and Residential STOUD). For the legacy tariffs the actual monthly demand is based on the highest individual demand in any single half hour in the month. For ICCs and CACs, the demand is measured in kva, and for SAC >100 MWh p.a. it is kw. In the LRMC based STOUD tariffs (applied at CAC, SAC >100 MWh p.a. and SAC <100 MWh p.a. levels), actual demand charges link to both peak and off-peak charging parameters. The peak demand charge only relates to demand during the peak periods in each month of the summer season. For SAC <100 MWh p.a. the demand is the average of an extended period of time referred to as average top four extended. For residential customers the calculation of the actual peak demand uses the customer's top four peak demand days (based on daily individual maximum half hour kw demand) in the peak window (3:00 pm to 9:30 pm). This is a separate calculation in each summer month. The demand charge will be applied to the average kw demand calculated for the total 52 half hour periods each month (i.e. 13 half hour intervals in each peak window x four (4) peak demand days). A similar approach is used for business customers except business peak days and hours apply. Excess reactive power (kvar) charges This charge applies to ICC network users only. It reinforces the kva price signal to customers operating at non-compliant power factors, encouraging these customers to improve their power factor Information Guide for SCS Pricing v1.1 page 26

27 to a compliant level and reduce their network capacity usage. The charge only impacts customers where their power factor is non-compliant and consuming a quantity of kvar which is greater than what is implicit in their capacity demand charge (the permissible kvar quantity calculated at the authorised demand and a minimum compliant power factor). Excess kvar is calculated monthly based on the amount by which a customer s individual peak monthly kvar exceeds their permissible kvars Volume charges The volume charge in part recovers costs that have been allocated on a postage stamped basis. For SACs <100 MWh p.a., the volume charge also recovers a portion of the shared network costs not included in the fixed charge. In the LRMC tariffs, the volume charge contributes to the recovery of residual revenue. The volume charge applies to the energy (kwh) metered at the customer's installation and may be based on a flat rate, an inclining block or TOU charging structure (depending on the applicable network tariff) Step C6: Designated Pricing Proposal Charges to network tariffs ICCs TUOS tariffs are customer specific and incorporate: a fixed charge ($/day) a capacity charge ($/kva of AD/month) a common services and general charge ($/day) a volume charge ($/kwh). Where the actual demand exceeds the AD in any one month, the actual demand will be substituted for the AD in the calculation of the capacity charge billed for that month. To determine the total TUOS volume charge, the metered consumption must be multiplied by the customer s Distribution Loss Factor (DLF) and then applied to the TUOS $/kwh rate. CACs TUOS tariffs are averaged at the TNCP after the allocation of costs to ICCs and incorporate: a fixed charge ($/day) a demand charge ($/kw/month) a volume charge ($/kwh). Ergon Energy combines rates in geographical regions in the East and West Zones and passes through TUOS charges to CACs in these zones, thus providing an appropriate locational signal in each region. Where the actual demand exceeds the AD in any one month, the actual demand will be substituted for the AD in the calculation of the capacity charge billed for that month. To determine the total TUOS volume charge, the metered consumption must be multiplied by the customer s DLF and then applied to the TUOS $/kwh rate Information Guide for SCS Pricing v1.1 page 27

28 SACs >100 MWh p.a. As is done for CACs, TUOS tariffs for this group are averaged at the TNCP after the allocation of costs to ICCs and CACs and incorporate: a fixed charge ($/day) a demand charge ($/kw/month) a volume charge ($/kwh). Ergon Energy combines rates in geographical regions in the East and West Zones and passes through TUOS charges to SACs >100 MWh p.a. in these zones, thus providing an appropriate locational signal in each region. To determine the total TUOS volume charge, the metered consumption must be multiplied by the customer s DLF and then applied to the TUOS $/kwh rate. The same SAC Large DUOS demand threshold calculation mechanism applies for TUOS charges. Where the monthly metered maximum demand is less than the demand threshold, the chargeable demand is set to zero and no demand charge is payable for that month. SACs <100 MWh p.a. TUOS tariffs for this category are an average of the remaining TUOS costs to be collected from the sum of all TNCPs and incorporate: a fixed charge ($/day) a volume charge ($/kwh). To determine the total TUOS volume charge, the metered consumption must be multiplied by the customer s DLF and then applied to the TUOS $/kwh rate. EGs For those EGs that only generate into the distribution system TUOS tariffs for generated energy do not apply. For those EGs that generate into as well as take load from the distribution system: TUOS tariffs for generated energy do not apply TUOS tariffs for load taken from the distribution system will be allocated as per the appropriate network user group (i.e. ICC, CAC or SAC). To determine the total TUOS volume charge, the metered consumption must be multiplied by the customer s DLF and then applied to the TUOS $/kwh rate Step D6: Allocation of jurisdictional scheme amounts into network tariffs The costs of the FiT payments made under the Queensland Government s Solar Bonus Scheme will be recovered from network users as a jurisdictional scheme charge as follows: Jurisdictional scheme amounts are allocated to tariff classes using a process similar to that used to allocate overhead costs in the current DUOS cost of supply model. The total revenue requirement for each tariff class is then converted to tariffs as follows: o o ICC a fixed charge ($/day) CAC and SAC a fixed charge ($/day) and a volume charge ($/kwh) Information Guide for SCS Pricing v1.1 page 28

29 4. Tariff classes 4.1 Assignment and reassignment of customers to tariff classes The AER requires Ergon Energy to comply with the procedures for assigning or reassigning customers to tariff classes 9 as per Attachment 14 of the Distribution Determination. Assignment or reassignment of customers to Ergon Energy s tariff classes can occur as a result of: customers requesting a new connection to the network existing customers applying for increased capacity on the network a change in a customer s NMI classification annual review as part of Ergon Energy s process of developing and submitting a Pricing Proposal for approval by the AER requests for a review of the assigned tariff class by either a customer and/or retailer. 4.2 Notification of a tariff class assignment and reassignment From 1 July 2015, the AER requires Ergon Energy to notify the customer s retailer of the tariff class we will assign the customer to, prior to a reassignment occurring. This information will be made available via a written notification. Subject to any appeal, the effective date will be: for tariff assignments the date the premises is energised by Ergon Energy (i.e. the NMI status is changed to Active in the market systems) for tariff class reassignments the date of the next scheduled meter read at the premises. It is important to note that a tariff class reassignment may necessitate a change to a customer s network tariff assigned to a NMI. Details of Ergon Energy s proposed new Network Tariff Codes will be included in the written notification mentioned above. Subject to any appeal, the new tariff class and new Network Tariff Code will take effect from the date of the next scheduled meter read. A retailer may request further information relating to a particular tariff class assignment or reassignment decision by contacting Network Pricing (see Section 1.5). 4.3 Review of a customer s assigned tariff class Ergon Energy does not reassign customers to tariff classes without careful review and adequate justification. Reassignment of a customer s tariff class generally only occurs in a situation where a customer alters the underlying characteristics of their connection, in terms of size or nature of usage. In addition to Ergon Energy s own review of tariff classes applying to customers, a customer and/or retailer may request a review of a customer s assigned tariff class at any time during a regulatory year. This request may occur directly through an explicit request to review a tariff class assigned to a customer, or indirectly through a request to change a network tariff assigned to a NMI. 9 A tariff class is defined under the NER and relates to a group or class of customers who are subject to a particular tariff or tariffs Information Guide for SCS Pricing v1.1 page 29

30 Ergon Energy relies on a range of information (e.g. historical consumption data) and has specific criteria for assessing the reassignment of customers to tariff classes. The criteria, by network user group, are set out in Table 4.1 below. Once a customer is identified for reassignment, the connection characteristics and the customer s expected energy consumption are used to determine the appropriate customer group, and hence tariff class, to which the customer should be reassigned. Table 4.1 : Tariff class reassignment criteria for Standard Control Services Network user group Typical characteristics of customers assigned SACs Annual consumption is expected to be below 4 GWh p.a. Criteria for reassigning customers to a different tariff class Reassigned to a different network user group: Annual consumption increases, or is expected to increase, above 4 GWh p.a., and/or A customer requests an increase in supply capacity requiring augmentation to connection assets which results in a dedicated supply system which is quite different and separate from the remainder of the supply network. Reassigned within the SAC network user group: Annual consumption of a SAC <100 MWh p.a. customer increases to over 100 MWh p.a. Annual consumption of a SAC >100 MWh p.a. customer decreases to less than 100 MWh p.a. CACs Required capacity above 1,500 kva, or Annual consumption is expected to exceed 4 GWh p.a. ICCs Annual consumption is expected to exceed 40 GWh p.a., or Their dedicated supply system is considered to be quite different and separate from the remainder of the supply network. Reassigned to ICCs: Annual consumption increases, or is expected to increase, above 40 GWh p.a., and/or A customer requests an increase in supply capacity requiring augmentation to their connection assets which results in a dedicated supply system which is quite different and separate from the remainder of the supply network. Reassigned to SACs: Annual consumption reduces or is expected to reduce below 4 GWh p.a. and their dedicated supply system is not considered to be quite different and separate from the remainder of the supply network, and/or Required capacity falls below 1,500 kva. 10 Annual consumption reduces or is expected to reduce below 40 GWh p.a. and their dedicated supply system is considered comparable with CACs at the same voltage level. The following general requirements apply to the review and amendment of a customer s tariff class assignment for Standard Control Services: Any change in an assigned tariff class will only proceed upon approval by Ergon Energy. Ergon Energy will make our determination having regard to this Information Guide, our Tariff 10 With the exception of those customers who have a dedicated supply system which is quite different and separate from the remainder of the supply network or where inequitable treatment of otherwise comparable customers will arise from the application of the 4 GWh threshold Information Guide for SCS Pricing v1.1 page 30

31 Class Reassignment Criteria (as set out above), the AER s Distribution Determination and any applicable law. Requests should be made by the customer, and are preferably made to Ergon Energy through the customer s retailer. Requests for review of a tariff class within the SAC network user group (e.g. from SAC >100 MWh p.a. to SAC <100 MWh p.a.) should be ed to Ergon Energy Network Revenue Recovery and Protection ([email protected]). All other requests for a tariff class review should be ed to Network Pricing (refer to Section 1.5 ). Subject to a change in the customer s usage or pattern of usage at the customer s premises, a further request to review and change a tariff class should not be made until a period of 12 months has elapsed from the previously approved request. Any change in the tariff class, and associated network tariff(s) will take effect from the date of the next scheduled meter read (the effective date ). Network charges under an existing network tariff within an existing tariff class will continue to be billed by Ergon Energy until the effective date. Backdating of charges prior to the effective date will not be allowed by Ergon Energy. 4.4 Objections to a tariff class assignment or reassignment If a retailer raises an objection to a tariff class assignment or reassignment for Standard Control Services, Ergon Energy will make every effort to investigate and address the retailer s concerns when the retailer first contacts Ergon Energy. In the first instance, the retailer should contact Network Pricing via (see Section 1.5) requesting a review of Ergon Energy s proposed tariff class assignment or reassignment. Ergon Energy will endeavour to inform the retailer of the outcome of our review, including a reason for our decision within five business days of receiving such a request. If the retailer is not satisfied with the outcome of this review, the objection can be escalated to the Manager Regulatory Determination and Pricing for reassessment. The retailer can request an objection to be escalated by contacting Network Pricing via . The Manager Regulatory Determination and Pricing will advise the retailer of the outcome of an escalated objection as soon as practical. Following this internal review, if the matter is not resolved to the satisfaction of the retailer, the retailer is entitled to refer the matter to: the Queensland Energy and Water Ombudsman (small customers only) the AER for resolution via the dispute resolution process available under Part 10 of the Law and clause of the NER. If the retailer s objection to a tariff class assignment or reassignment is upheld by Ergon Energy (via our internal review process) or the appropriate external body, then an adjustment will be made to tariffs as part of the next network bill. 4.5 Network tariff reviews The customer or the retailer may apply to Ergon Energy for a change to the network tariff assigned to a NMI by sending a request to Ergon Energy Network Revenue Recovery and Protection via ([email protected]). Ergon Energy will inform the customer and/or retailer within five business days of receiving such a request, of the decision taken Information Guide for SCS Pricing v1.1 page 31

32 If Ergon Energy: agrees that the network tariff proposed by the customer or retailer is applicable to the NMI, Ergon Energy will advise the retailer of the effective date of application, or disagrees that the network tariff proposed by the customer or retailer is applicable to the NMI, Ergon Energy will notify the customer and/or retailer, including a reason for the rejection. A customer and/or retailer may appeal the network tariff decision. The appeals process to follow is outlined in Table 4.2 below. Table 4.2: Network tariff appeals process Scenario The customer and/or retailer do not agree with Ergon Energy s decision to maintain the current network tariff. The customer does not agree to a network tariff change initiated by their retailer. Appeals process If it relates to a change to a network tariff within the SAC network user group: A request to review the decision should be sent to Ergon Energy Network Revenue Recovery and Protection via . This request should be sent by the customer s retailer. Otherwise: A request to review the decision should be sent to the Network Pricing via . This request should be sent by the customer s retailer. The customer should contact their retailer in the first instance. Following this, if the matter is not resolved to the satisfaction of the customer, the customer may submit a request to Ergon Energy to review the network tariff decision. o If it relates to a change to a network tariff within the SAC network user group, this request should be sent to Ergon Energy Network Revenue Recovery and Protection via . o Otherwise, this request should be sent to Network Pricing via . Ergon Energy will review an appeal and the customer s eligibility for a network tariff with regard to this Information Guide, our Tariff Class Reassignment Criteria, the AER s Distribution Determination and any applicable law. Ergon Energy will advise the customer and/or the retailer of the outcome of an appeals review as soon as practical. Any change in a network tariff assigned to a NMI will take effect from the date of the next scheduled meter read (the effective date). Network charges under the existing network tariff will continue to be billed by Ergon Energy until the effective date. Backdating of charges prior to the effective date will not be allowed by Ergon Energy. Subject to a change in usage or the pattern of usage at the customer s installation, a further request to change the Network Tariff Code assigned to a NMI should not be made until a period of 12 months has elapsed from the previously approved request for the NMI. If Ergon Energy agrees with a proposed network tariff and determines that a tariff class reassignment is also required, written notification of the new tariff class and new Network Tariff Code will also be provided to the customer and retailer prior to the tariff class reassignment occurring, in accordance with Section Information Guide for SCS Pricing v1.1 page 32

33 5. Distribution Loss Factors 5.1 Overview DLFs are calculated annually by Ergon Energy in accordance with requirements of the NER in order to determine the amount of energy dispatched to supply customers. They are approved by the AER and published by the Australian Energy Market Operator (AEMO) on their website. Every NMI has a DLF code which is associated with the location of the metering point. The DLF is a multiplier used to convert the actual metered energy into the equivalent energy passing through the appropriate TNCP by allowing for the distribution network losses that are incurred between the meter and the TNCP. The DLF is applied to the metered consumption for the calculation of TUOS volume charges. DLFs are generally assigned on the basis of the standard metering voltage for the type of connection. However, a specific loss factor may be applied where there is a unique network supply configuration. 5.2 DLF categories and applications Table 5.1 outlines the DLF categories used by Ergon Energy and their applications. Table 5.1: DLF categories and applications Category Description Application Sub-transmission Bus Sub-transmission Line 22/11kV Bus Applicable to connection points that are High Voltage metered at a Subtransmission Bus with a voltage greater than 30 kv. Applicable to connection points that are High Voltage metered at a Subtransmission Line with a voltage greater than 30 kv. Applicable to connection points that are High Voltage metered at a 22/11 kv Bus with a voltage less than 30 kv and greater than 1,000 volts. NMIs that are supplied from a zone substation by dedicated, greater than 30 kv lines and metered at or immediately adjacent to the zone substation would be eligible for a Subtransmission Bus DLF. Zone substations are defined as substations where the voltage level is stepped down from a voltage greater than 30 kv. The Sub-transmission Line DLF will apply to all NMIs that are: connected to high voltage subtransmission lines (greater than 30 kv) metered at the same voltage as the line is energised. If customers believe that the NMI would qualify for a high voltage Bus DLF rather than a high voltage Line DLF they should submit details justifying their claim to Ergon Energy. As an example, NMIs supplied from a zone substation by dedicated 22/11 kv lines and are metered at or immediately adjacent to the zone substation would be eligible for a 22/11 kv Bus DLF. As per Sub-transmission Bus application above Information Guide for SCS Pricing v1.1 page 33

34 Category Description Application 22/11kV Line Low Voltage (LV) Bus Low Voltage (LV) Line Applicable to connection points that are High Voltage metered at a 22/11 kv Line with a voltage less than 30 kv and greater than 1,000 volts. Applicable to connection points that are Low Voltage metered at a Low Voltage Bus with a voltage less than 1,000 volts. Applicable to connection points that are Low Voltage metered at a Low Voltage Line with a voltage less than 1,000 volts. The 22/11 kv Line DLF will apply to all NMIs that are: connected to high voltage distribution lines metered at the same voltage as the line is energised. NMIs which are supplied from a distribution substation on their site (owned or leased) and metered at the low voltage level are eligible for a LV Bus DLF. All NMIs not covered by any of the above categories. If customers believe that the NMI would qualify for a LV Bus DLF rather than a LV Line DLF they should submit details justifying their claim to Ergon Energy. 5.3 Further information Further information on Ergon Energy s methodology for calculating DLFs is available on our website: Detailed information about the purpose and application of DLFs may also be obtained from the AEMO website: Information Guide for SCS Pricing v1.1 page 34

35 6. EG Avoided TUOS payments Clause 5.5(h) of the NER requires DNSPs to calculate "avoided charges for the locational component of prescribed TUOS services", and clause 5.5(i) requires DNSPs to calculate the amount to be passed through to an EG. This is done by: 1. determining the charges for the locational component of prescribed TUOS services that would have been payable by the DNSP for the relevant financial year if the EG had not injected any energy at its connection point during that financial year determining the amount by which the charges calculated in subparagraph (1) exceed the amount for the locational component of prescribed TUOS services actually payable by the DNSP, which amount will be the relevant amount for the purposes of paragraph (h) [clause 5.5(h)]. 12 Avoided TUOS payments are made by Ergon Energy to EGs who have sought access to Ergon Energy s distribution network under clause 5.5 of the NER, who have a generator Connection Agreement with Ergon Energy and who are registered as a Generator Rules Participant. Costs related to payments to EGs for Avoided TUOS are not part of Ergon Energy's ARR and therefore are required to be recovered under the TUOS recovery process, as per Section Methodology As noted in Section 3.7, Ergon Energy makes Avoided TUOS payments to EGs that have: sought access to Ergon Energy s distribution network under clause 5.5 of the NER a generator Connection Agreement with Ergon Energy registered as a Generator Rules Participant. We use the below methodology to comply with the NER: 1. determine the amount of energy sent out by the EG in the relevant financial year (kwh) 2. convert this to an equivalent amount of energy at the TNCP, by adjusting the export energy by the DLF of the EG 3. determine the net generator output (i.e. the generator output that is utilised by the local distribution network, by subtracting the actual metered energy that flows back into the transmission network at the TNCP) 4. add the net generation output to the TNCP actual metered data for the financial year 5. determine the TUOS that would have been charged if the generator was not connected, by recalculating the customer TUOS usage charges (demand and energy) 6. subtract the actual TUOS payment from the amount calculated in step 5 7. arrange payment of the resultant value from step 6 to the EG. Powerlink s charge structure is such that the only locational signal is the TUOS Locational Charge monthly average demand component, which Ergon Energy converts into a volume dollars/kilowatt hour charge Clause 5.5(i)(1)(i) of the NER. Clause 5.5(i)(2) of the NER Information Guide for SCS Pricing v1.1 page 35

36 Avoided TUOS payments to EGs following the end of the relevant financial year will be made as agreed between Ergon Energy and the particular EG and may be: a lump sum payment by cheque a lump sum credit against future Network Charges accounts staged payments or credits over a future period. Costs related to payments to EGs for Avoided TUOS charges are not part of Ergon Energy's ARR and therefore are required to be recovered under the TUOS recovery process Information Guide for SCS Pricing v1.1 page 36

37 Appendix 1: Additional pricing information Pricing Principles Philosophy Ergon Energy s tariff setting objective is to ensure that the ARR is fully recovered from network users in a manner that is: economically efficient equitable provides price stability transparent practical easily understood. The distribution network pricing methodology has been developed to meet the objectives by adopting the following pricing principles: Network tariffs should recover no more than the allowable regulated revenue cap from the forecast customer base in any one year. The recovery of the revenue cap is achieved through the allocation of costs to tariff classes such that the resulting revenue from the application of network tariffs equals no more than the revenue cap. Network tariffs should be determined using a well-defined and clearly explained methodology. The purpose of this Information Guide is to define and explain the methodology that Ergon Energy uses to establish network tariffs. Network tariff development should incorporate an analysis of the cost of service provision that includes: - definition of the network user classes to which distribution services are provided - segregation of network costs by voltage level and location - allocation of the network costs to network user classes and voltage levels - translation of allocated costs into service prices. Ergon Energy conducts an analysis of our network user and cost base to establish tariff classes and network tariffs that are an equitable reflection of the network users use of the existing network and specific dedicated assets, while minimising the inefficiency of price averaging. Network tariffs should signal the economic costs of service provision and promote the efficient use of the network, by: - being subsidy free (i.e. between avoidable cost of supply and stand alone cost of supply) - having regard to the level of available service capacity - signalling the impact of additional usage on existing and future investment costs. Network tariffs for the different tariff classes are designed, within the constraints imposed by the type of metering, to provide signals to the network users on the impact of existing and future network capacity and costs Information Guide for SCS Pricing v1.1 page 37

38 Provided that economic costs are recovered, network tariffs should be responsive to the requirements and circumstances of network users by: - being a fair and equitable distribution of costs - being perceived by network users as an equitable reflection of the network users' utilisation of the network assets - discouraging uneconomic bypass of the distribution network - allowing for negotiation, where appropriate, to better reflect the economic value of specific services. Network tariffs reflect the standard level of electricity supply in terms of asset used, quality, reliability and security available to network users at their point of connection to the network. Information should be disclosed on tariff classes, network tariff levels and structures, underlying costs, price derivation methods and rationale, and medium term price paths to ensure: - current and potential network users are able to understand the basis for prices and take account of network tariffs in their consumption, investment and location decisions - interested parties are able to better assess the range of economic opportunities for meeting network user requirements that may reduce network users costs and lead to more efficient outcomes. This Information Guide, and our other network pricing documentation, provides sufficient information on the methodology that Ergon Energy uses to establish network tariffs to be transparent to network users. Development of network tariffs should ensure maintenance of price stability and certainty. It is intended that there is transparency of future network tariffs for network users to make informed investment decisions. In restructuring our network tariffs, Ergon Energy seeks to balance the rate of the structural change with individual customer cost impacts. The inevitable change associated with the development of network tariffs is managed by: on-going customer and stakeholder consultation transparency and communication of future structural change intentions placing constraints on annual individual customer network tariff increases. Underlying service classifications, cost data, cost allocations and other elements that contribute to pricing decisions should be periodically reviewed and updated where relevant to reflect industry developments and changes in network user requirements, expectations and preferences, methods of service provision and costs. Ergon Energy is currently undertaking a more detailed review of our Network Tariff Strategy. There has been a major shift in the way our customers use the electricity network over recent years. Strong economic growth in the early 2000s, coupled with a drop in the price of electrical appliances, led to a rapid increase in demand for electricity during peak usage periods. In more recent times, while peak demand has remained high, the economic slowdown, the growing take up of solar energy and the focus on energy efficiency (as electricity prices have risen) has led to a drop in electricity use overall. This means our network, which has been invested in heavily to respond to the growth in demand during peak times (which can occur for only a few days a year), is now not being utilised as fully as it could be outside of peak times. To respond to this, and other considerations, we are restructuring our network tariffs. This process is expected to take a number of years, with the first changes occurring in Further information on our future network tariff structure reform is detailed on our website at Information Guide for SCS Pricing v1.1 page 38

39 The economic signals present in the structure of TUOS charges should be preserved when allocating transmission charges to distribution customers to enable customers to interpret, and respond to, those economic signals. TUOS charges are calculated and levied by Powerlink to Ergon Energy. Within the constraints of metering type and/or network price, the economic signals inherent in the transmission price structure are passed directly through to the customers to the maximum extent possible given the practical constraint of using average prices for groups of similar customers. Since customers of Ergon Energy are supplied across a geographically diverse transmission system, the transmission prices vary markedly between TNCPs. For this reason, Ergon Energy separates the DUOS charges and TUOS charges into discrete components enabling customers to identify the contribution of the transmission charges to their overall use of network costs. Cost allocators for Network Use of System services There are a range of cost allocators that can be used in the DCOS model adopted by Ergon Energy. The selection of the appropriate allocator is based on the ability of that allocator to reflect the relationship between various costs and what causes those costs to occur. The range of possible allocators includes: number of customers any time energy period energy (time-of-use) ATMD period demand (time-of-use) coincident demand replacement cost of assets. The customer numbers and usage are identified for each zone from an interrogation of the customer information system based on the customer s geographic location. The values of the assets for each zone are determined from an interrogation of the asset management database that was used to provide information required by the AER for input into the Preliminary Determination. Ergon Energy has adopted the following allocators in the DCOS model: number of customers any time energy ATMD replacement cost of assets. The reasoning behind the selection of these allocators is as follows: Number of customers. This allocator is appropriate for those costs that are dependent upon or driven by the number of connected customers. Ergon Energy has a number of costs that are customer number based, including a significant proportion of the overhead costs of the business that are driven by the number of staff and systems required to serve the customer base. Any time energy. This is used to allocate those costs that are related to the size of the customer but not specifically to the demand that customer places on the network (e.g. network operating costs). In addition, consistent with the recovery mechanisms used in the electricity market, costs that cannot be directly related to a product or service are recovered through the use of any time energy prices (e.g. some overhead costs). A portion of TUOS is also allocated to customers on Information Guide for SCS Pricing v1.1 page 39

40 an any time energy basis for those energy related TUOS charge components billed to Ergon Energy by the TNSP so as to retain the transmission pricing signals in customer tariffs. ATMD. This method of allocation is used for the shared system costs. The basis for this is that network development in each part of the network is driven by peak demand in that part of the network. For example, in a domestic area, the shared network capacity is based on the peak domestic demand that generally occurs for Ergon Energy in the late afternoon and early evening during the summer. By contrast, in commercial/industrial areas, the shared network capacity is generally determined by summer working day peak demands. These individual demands throughout the network combine to form an overall coincident system peak demand. However, the coincident demand is more relevant to transmission network capacity than distribution. While the ideal cost allocation mechanism would be based on a real time model which constantly monitors the network demands at specific locations, such an approach is not achievable at present and ATMD provides a simple and reasonable basis for apportioning system usage related costs. It reflects the fact that demand is the primary driver of shared network costs. A portion of TUOS is also allocated to network users on an ATMD basis for the demand related TUOS charge components applied to Ergon Energy by the TNSP so as, once again, to retain the transmission pricing signals in network user prices. Replacement cost of assets. The replacement costs of the assets are used as allocators to apportion ROA, depreciation and opex costs across the various cost categories. The replacement costs are not used directly to calculate the value of any of the costs within the price allocation model. The replacement costs are used to allocate the ROA, depreciation and opex costs because the replacement costs are relatively stable over time whereas the depreciated values change. If the depreciated values were used, the network user prices would vary up and down depending on when old assets were replaced with new assets. The actual age and value of the assets used to supply a network user is not relevant to the prices charged for that network user because Ergon Energy is required to maintain supply to the network user in accordance with statutory and NER requirements, irrespective of the type or age of assets deployed. An example of replacement costs used in the allocation of opex is shown below. Opex allocation for voltage level = Total opex $ allowance x RC of assets for voltage level RC of total assets Where RC = replacement cost Information Guide for SCS Pricing v1.1 page 40

41 System opex System depreciation System ROA Common services Admin Other TUOS ARR cost components to DCOS cost categories The DCOS cost categories are the categories used in Ergon Energy s pricing model to allocate the allowable costs to the various customer classes. Table A1.1 shows how the allowable ARR and TUOS cost components are divided into the various cost groups for further allocation to the DCOS cost categories. Table A1.1: ARR cost components to DCOS cost categories DCOS cost categories Revenue cap components Cost groups Distribution system charges TUOS Opex Section 3.6 Network Operating Network Maintenance Other Asset Operating ROA Section 3.6 Network Operation Assets Network Distribution Assets Other Assets Depreciation Section 3.6 Network Operation Assets Network Distribution Assets Other Assets TUOS Section 3.6 TUOS charges Allocating revenue to DUOS network tariffs In , Ergon Energy started a process of rebalancing and restructuring our network tariffs. This has changed the approach to determining rates for individual tariff parameters to facilitate greater alignment with the long run marginal cost (LRMC). In the case of existing tariff structures, this involved rebalancing the weighting of parameters to initially focus on the adjustment of demand charges towards alignment with LRMC. These adjustments were small and were undertaken within constraints related to maximum levels of impact on individual connections. The rebalancing and restructuring process has continued in All optional tariffs adopt the LRMC approach Information Guide for SCS Pricing v1.1 page 41

42 Conversion of Powerlink cost categories to TUOS prices Table A1.2 shows the allocation of the Powerlink price components to the customer price component for TUOS recovery. Table A1.2: Conversion of Powerlink cost categories to TUOS prices TUOS network price components Powerlink cost category Entry/exit connection price ($/day) Capped customer TUOS usage prices Usage capacity price Demand component ($/kw) Average demand component ($/kw) Customer TUOS general price General energy price ($/kwh) Transmission customer common service price Common service energy price ($/kwh) Ergon Energy charge structure ICC Fixed charge ($/day) CAC SAC >100 MWh p.a. SAC <100 MWh p.a. a Capacity charge ($/kw/month or $/kva/month) ICC CAC SAC >100 MWh p.a. SAC <100 MWh p.a. Common services and general charge ($/day) ICC CAC SAC >100 MWh p.a. SAC <100 MWh p.a. ICC Volume charge ($/kwh) CAC SAC >100 MWh p.a. SAC <100 MWh p.a. Notes: a) A fixed charge does not apply to Volume Night Controlled, Volume Controlled and Unmetered Supply network tariffs Information Guide for SCS Pricing v1.1 page 42

43 ICC CAC SAC >100 MWh p.a. SAC <100 MWh p.a. Volume Controlled Volume Night Controlled Unmetered (incl. Street lights) EG (Generation only) Price components for network users Table A1.3 shows which price components are applicable to each class or category of network user prices. Table A1.3: Network price components Network user classes to which network price component is applicable Network price component Description Fixed charge ($/day) Connection Unit Charge ($/connection unit/day) Capacity charge c ($/kw/month or $/kva/month) Excess Reactive Power Charge ($/kvar/month) Common service and general charge ($/day) Actual demand c charge ($/kw/month or $/kva/month) Volume charge ($/kwh) Distribution system charge Reflective of the costs associated with the connection assets (entry and exit services) and network user management services. TUOS A portion of the allocated TUOS costs. Distribution system charge Reflective of the costs associated with the connection assets not otherwise paid for upfront. Distribution system charge Reflective of the network capacity required by the network user on a long term basis and levied on the basis of an AD. TUOS A portion of the allocated TUOS costs. Distribution system charge Reflective of the impact on network capacity at peak monthly demand. TUOS only A portion of the allocated TUOS costs. Distribution system charge Reflective of the costs of network capacity availability and limitations. Distribution system charge Recovery of costs not directly allocated or associated with network drivers, through a non-distortionary basis. The charge also includes costs that are proportional to the size of the customer, such as customer management. a a b d Information Guide for SCS Pricing v1.1 page 43

44 ICC CAC SAC >100 MWh p.a. SAC <100 MWh p.a. Volume Controlled Volume Night Controlled Unmetered (incl. Street lights) EG (Generation only) Network user classes to which network price component is applicable Network price component Description TUOS For ICCs, CACs and SACs >100 MWh p.a., a portion of the allocated TUOS costs and for SACs <100 MWh p.a., the remaining portion of allocated TUOS costs. Notes: a) There is no fixed charge for CAC and SAC Small Seasonal TOU Demand tariffs. An off-peak minimum chargeable demand applies. b) The fixed charge for unmetered supply tariffs is $/day/device. c) Capacity and demand charges in the ICC and CAC user groups are in kva and for SAC Large these charges are in kw. d) For SAC <100 MWh p.a., Actual Demand Charges apply to Seasonal TOU Demand tariffs only Information Guide for SCS Pricing v1.1 page 44

45 Glossary Abbreviations AEMO ACS AER ARR ATMD BCS CAC DCOS DLF DNSP DUOS EG Ergon Energy Excess kvar GWh IBT ICC kv kva kvar kw kwh Law LRIC LRMC MWh NER NMI Opex p.a. PTRM PV ROA SAC SCS STOUD Australian Energy Market Operator Alternative Control Services Australian Energy Regulator Annual Revenue Requirement Any Time Maximum Demand Benchmark cost of supply Connection Asset Customer Distribution Cost of Supply Distribution Loss Factor Distribution Network Service Provider Distribution Use of System Embedded Generator Ergon Energy Corporation Limited Excess reactive power charge Gigawatt hour Inclining Block Tariff Individually Calculated Customer Kilovolt Kilovolt-ampere Kilovolt-ampere reactive Kilowatt Kilowatt hour National Electricity Law Long Run Incremental Cost Long Run Marginal Cost Megawatt hour National Electricity Rules National Metering Identifier Operating expenditure Per annum Post Tax Revenue Model Photovoltaic Return on assets Standard Asset Customer Standard Control Services Seasonal Time-of-Use Demand Information Guide for SCS Pricing v1.1 page 45

46 STOUE STPIS TAR TNSP TOU TUOS Seasonal Time-of-Use Energy Service Target Performance Incentive Scheme Total Annual Revenue Transmission Network Service Provider Time-of-Use Transmission Use of System Definitions Actual demand charge Alternative Control Service Annual revenue adjustment Annual Revenue Requirement (ARR) Any time energy Any Time Maximum Demand (ATMD) Australian Energy Regulator (AER) Avoided TUOS Business customer Capacity charge A type of charge (charging parameter) included in Ergon Energy s network tariff structures to signal the effect demand has on the shared network and system augmentation. The demand used in the calculation of the charge is the maximum demand recorded in any half hour period each month. A distribution service provided by Ergon Energy that the AER has classified as an Alternative Control Service under the NER. Includes fee based services, quoted services, Public Lighting Services and Default Metering Services. Annual adjustments made to Ergon Energy s smoothed revenue requirement for Standard Control Services revenue for matters such as out-turn inflation, allowed rate of return, STPIS, pass throughs, and the difference between forecast and actual revenue received for DUOS charges, capital contributions and shared assets. The revenue determined by the applicable PTRM. Is the amount of energy consumed by the customer irrespective of the time of day. Is the maximum half hourly demand for a customer that occurs at any time within a specified period. The AER is an independent statutory authority that is part of the Australian Competition and Consumer Commission. The AER is responsible for the economic regulation of electricity networks in the NEM. It also monitors the wholesale electricity and gas markets and is responsible for compliance with and enforcement of the National Electricity Law and Rules, National Gas Law and Rules, and the National Energy Retail Law and Rules. The amount paid to an eligible EG for the locational component of prescribed TUOS services that would have been payable by Ergon Energy to a TNSP had the EG not been connected to the distribution network. The methodology Ergon Energy uses to comply with the NER is set out in the Information Guide for Standard Control Services Pricing. Means a customer who is not a residential customer (as defined in the Queensland Electricity Distribution Network Code (EDNC)). A type of charge (charging parameter) included in Ergon Energy network tariff structures. The capacity charge is reflective of the costs associated with the network capacity required by a customer on a long term basis. It is similar to the actual demand charge, but more effectively takes into account the impact low load factor customers have on system augmentation. The demand used for the calculation of the charge is the authorised demand, or if no authorised demand, an annual maximum demand Information Guide for SCS Pricing v1.1 page 46

47 Capital contribution Charging parameter Connection Connection Asset Customer (CAC) Connection assets Connection point Connection Unit Customer Demand Distribution Cost of Supply (DCOS) Model Distribution network Distribution Use of System (DUOS) charge East Zone Electricity Market Embedded Generator (EG) Energy A capital contribution is a prepayment for the provision of direct control services. A capital contribution may be charged to a customer if the new connection or modification for an existing connection is required to the network to accommodate the connection/modification. Ergon Energy s Connection Policy sets out circumstances in which a capital contribution may be required and details how the capital contribution to be charged to a customer is calculated. The constituent elements of a tariff (as defined in the NER). The physical link to or through a transmission network or distribution network. Means a customer classified as a CAC in accordance with the definition in our Pricing Proposal. Typically reflects those customers with required capacity above 1,500 kva, or with electricity consumption greater than 4 GWh (but less than 40 GWh) per year. Those components of a transmission or distribution system which are used to provide connection services. Connection assets are those assets required to connect an electrical installation to the shared network and are all the assets from the connection point back up to and including the network coupling point. The agreed point of supply established between Network Service Provider(s) and another Registered Participant, Non-Registered Customer or franchise customer. Introduced to the CAC class in to allow standardisation of this user group to be undertaken. A customer specific value based on Ergon s investment in connection assets to that customer. A person or entity that receives, or wants to receive a supply of electricity for a premises, or any other distribution service from Ergon Energy. The amount of electricity energy being consumed at a given time measured in either watts (W) or volt amperes (VA). The difference between the two is the power factor. The Ergon Energy model used to allocate costs to network users and convert the revenue cap and transmission related costs (or designated pricing proposal charges) into network tariffs. The electrical system used to transport electricity from the high voltage transmission network connection point to distribution network users. Component of the network tariffs which covers costs associated with connection services and/or use of the distribution network for the conveyance of electricity (i.e. Standard Control Services). Those areas where the network users are supplied from the distribution system connection to the national grid and have a relatively low distribution cost to supply. The local government areas covered by the East Zone are located in the Information Guide for Standard Control Services. Means the National Electricity Market (NEM) as administered by AEMO. Means a network user classified as an EG in accordance with the definition in our Pricing Proposal. EGs are those network users that export energy into the distribution system, except for micro-embedded generators that have been classified as a SAC (such as small scale PV generators). The amount of electricity consumed by a consumer (or all customers) over a period of time. Energy is measured in terms of watt hours (Wh), kilowatt hours (kwh), megawatt hours (MWh) or gigawatt hours (GWh) Information Guide for SCS Pricing v1.1 page 47

48 Excess reactive power charge (Excess kvar) Fee based services Preliminary Determination Fixed charge Gigawatt hour (GWh) High Voltage (HV) Inclining Block Tariff (IBT) Individually Calculated Customer (ICC) Isolated generation Jurisdictional scheme amount kva kvar kw Load factor Low Voltage (LV) Charge applied against the kvar used by a customer that exceeds what they would be entitled to use at their minimum compliant power factor at authorised demand. A type of Alternative Control Service which Ergon Energy undertakes at the request of an identifiable customer, retailer or appropriate third party which is in addition to our Standard Control Services and is levied as a separate charge. The costs of providing the service (and therefore price) can be assessed in advance of the service being requested by a customer or retailer. The AER s Preliminary Determination sets the revenue and pricing control regime that Ergon Energy must comply with for the first year of the current regulatory control period (i.e ). A type of charge (charging parameter) included in Ergon Energy network tariffs which is levied on a fixed dollar amount per day. 1,000,000 kilowatt hours. Refers to parts of the network that are 11 kv or above. A type of network tariff where the price per kwh increases as consumption thresholds are crossed during a particular time period. Means a customer classified as an ICC in accordance with the definition in our Pricing Proposal. Typically reflects those customers with electricity consumption greater than 40 GWh per year, or where a customer s circumstances and connection arrangement mean that average prices are meaningless or inappropriate (e.g. only two or three customers in a supply system, or the customer is connected close to a Transmission Connection Point). Those areas supplied from Ergon Energy s isolated generation assets, except for the Mount Isa system. Includes communities in Western Queensland, the Gulf of Carpentaria, Cape York, various Torres Strait Islands, Palm Island and Mornington Islands. These areas are not subject to economic regulation by the AER, but are regulated by the Queensland Government. In respect of a jurisdictional scheme, the amounts a DNSP is required under the jurisdictional scheme obligations to: (a) (b) (c) (d) pay to a person pay into a fund established under an Act of a participating jurisdiction credit against charges payable by a person, or reimburse a person, less any amounts recovered by the DNSP from any person in respect of those amounts other than under the NER (as defined in the NER). 1,000 Volt-Ampere which is a measure of the apparent power flow which is a measure of the total capacity required to supply a customer s load. 1,000 Volt-Ampere reactive which is a measure of reactive power. The excess kvar charge is applied against kvar drawn from the network that exceeds the minimum compliant power factor level. 1,000 Watts which is a measure of the real component of power being consumed by the consumer s load. Measure of the percentage of time a load is used in any given period. Loads used 24 hours per day, 7 days a week have a load factor of 1 or 100 per cent. Refers to the sub 11 kv network Information Guide for SCS Pricing v1.1 page 48

49 Major customer Major Customer Connection arrangements Major Customer Connection service Maximum demand Megawatt hour (MWh) Mount Isa Zone National Electricity Rules (NER) National Metering Identifier (NMI) Network capacity Network tariff Network user Permissible kvar quantity Power factor Premises Public Lighting Services Are Individually Calculated Customers (ICCs), Connection Asset Customers (CACs) or Embedded Generators (EGs). Refers to the arrangements applying from 1 July 2010, where new or augmented connection assets are paid for or contributed by the major customer (i.e. not included in the network tariff). Is a type of quoted price service which relates to the design and construction of connection assets for major customers. The maximum demand recorded at a customer s individual meter or the maximum demand placed on the electrical distribution network system at any time or at a specific time or within a specific time period, such as a month. Maximum demand is an indication of the capacity required for a customer s connection or the electrical distribution network. 1,000 kilowatt hours Those areas supplied from the isolated Mount Isa system. This zone is not connected to the national grid and would normally be excluded from the application of the NER. However, under the Electricity National Scheme (Queensland) Act 1997, the Queensland Government has transferred responsibility for the economic regulation of the Mount Isa-Cloncurry supply network to the AER. The local government areas covered by the Mount Isa Zone are located in the Information Guide for Standard Control Services. Rules made under the National Electricity Law which govern the operation of the NEM. A unique number assigned to each metering installation. The maximum demand (kw) that the distribution network can provide for at any one time. Refers to the price (or tariff) that Ergon Energy sets to recover costs associated with the customer s connection and use of the distribution and transmission network. Network tariffs comprise DUOS and TUOS components. There are four network user groups included in Ergon Energy s network tariff structures Individually Calculated Customers (ICCs), Connection Asset Customers (CACs), Standard Asset Customers (SACs) and Embedded Generators (EGs). For the purposes of our network pricing documents, the term network user refers to both a customer and an EG. The permissible kvar quantity is the kvar quantity associated with authorised demand at minimum compliant power factor. The ratio of kw to kva at a metering point during a defined period. Means premises owned or occupied by the customer. A type of Alternative Control Service. Relates to the provision, construction and maintenance of public lighting assets owned by Ergon Energy, and emerging public lighting technology. Ergon Energy recovers our costs in providing this service through a daily public lighting charge which we bill to retailers. We will also charge an exit fee, when public lights are scrapped before the end of their useful lives (outside of the LED program) Information Guide for SCS Pricing v1.1 page 49

50 Quoted services Regulatory control period Regulatory year Residential customer Revenue cap Side constraint Standard Asset Customer (SAC) Standard Control Service Substitute Determination Summer Tariff class Threshold demand Time-of-Use (TOU) Transmission Use of System (TUOS) charge Unmetered A type of Alternative Control Service. Similar to fee based services, but they are priced on application as the nature and scope of these services is variable and the cost (and therefore price) is specific to the individual retailer s or customer s needs. The regulatory control period is a five (5) year period set down by the AER. The current regulatory control period is to Is a specific financial year within a regulatory control period. Means a customer who acquires electricity for domestic use (as defined in the Queensland EDNC). The TAR plus any unders or overs adjustment needed to move the balance of the DUOS unders and overs account to zero. Refers to the percentage by which the expected weighted average revenue to be raised from a Standard Control Service tariff class is allowed to increase by between regulatory years. Side constraints are intended to set a limit (or constraint) on the level of distribution price increase to be experienced by customers from one year to the next within a regulatory control period. Means a customer classified as a SAC in accordance with the definition in our Pricing Proposal. Typically reflects those customers with annual electricity consumption below 4 GWh per year. Includes customers with micro generation facilities (such as small scale PV generators) that have an exporting capability and an inverter capacity as per AS4777. A distribution service provided by Ergon Energy that the AER has classified as a Standard Control Service under the NER. Includes network services, some connection services (including small customer connections) and Type 7 metering services. Ergon Energy recovers our costs in providing Standard Control Services through the DUOS component of network tariffs which are billed to retailers. The AER s Substitute Determination revokes and substitutes the Preliminary Determination. It sets the revenue and pricing control regime that Ergon Energy must comply with for the current regulatory control period, as well as any true-up adjustments required to affect any changes between the Preliminary and Substitute Determinations. The months of December, January and February. A class of customers for one or more direct control services who are subject to a particular tariff or particular tariffs (as defined in the NER). The amount by which a SAC >100 MWh p.a. customer s metered monthly actual kw maximum demand is adjusted for the purposes of calculating the demand component of their network tariff. The actual demand charge tariff charging parameter ($/kw/month) is applied to the higher of metered monthly demand less the applicable threshold, or zero. A type of network tariff where the price per kwh varies according to when the consumption occurs. The TOU tariff may apply a different price during Peak, Shoulder and Off-Peak periods. Component of the network tariff which passes through costs associated with use of the transmission network. This includes designated pricing proposal charges as defined under the NER plus charges levied on Ergon Energy in relation to Chumvale and nonregulated Powerlink connection points. A customer who takes supply where no meter is installed at the connection point Information Guide for SCS Pricing v1.1 page 50

51 Volume charge West Zone A type of charge (charging parameter) included in Ergon Energy network tariffs which in part recovers costs that have been allocated on a postage stamped basis. The volume charge is calculated using the customer s metered energy (kwh) consumption and may be based on a flat rate, an inclining block or TOU charging structure (depending on the customer s applicable network tariff). Those areas outside the East Zone and connected to the national grid, which have a significantly higher distribution cost of supply than the East Zone. The local government areas covered by the West Zone are located in the Information Guide for Standard Control Services Information Guide for SCS Pricing v1.1 page 51

52 Contact information Manager Regulatory Determination and Pricing Ergon Energy Corporation Limited PO Box 264 FORTITUDE VALLEY QLD 4006 Telephone: Contact information Manager Regulatory Determination and Pricing Ergon Energy Corporation Limited PO Box VALLEY 264 QLD FORTITUDE VALLEY QLD 4006 Telephone: Contact information Manager Regulatory Determination and Pricing Ergon Energy Corporation Limited