CONSULTATION PAPER: TRANSMISSION PRICING. November 2013

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1 CONSULTATION PAPER: TRANSMISSION PRICING November 2013

2 Table of Contents Overview and Introduction Background and Purpose Transmission Pricing Objectives and Principles Introduction Transmission Pricing Objectives Revenue Setting Process Economically Efficient Pricing Marginal Costs Sunk Costs Two-Part Tariffs Equity and Efficiency Considerations Service Categories Transmission Pricing Principles Development of Current Transmission Pricing Arrangements Introduction Development of Transmission Pricing Arrangements Current Transmission Pricing Arrangements Transmission Pricing Consultation Cost Reflective Network Pricing Operating Conditions for Cost Allocation Process Treatment of Network Support Costs Structure and Application of Prices Prescribed Entry and Exit Services Prescribed Common Transmission Services Prescribed TUOS Services locational component Prescribed TUOS Services non-locational component Excess Demand Charge Basis for Levying Locational TUOS Charges Application of Side Constraints to Locational TUOS Prices Prudent Discounts Transparency Compliance Next Steps Attachment: Reviews on the Regulation of Transmission Services and Prices TransGrid Consultation Paper: Transmission Pricing November 2013

3 Overview and Introduction Transmission pricing is a complex matter. Prices play a part in promoting efficient outcomes. At the same time those prices must generate sufficient revenue to cover the total cost of providing transmission services, including an acceptable rate of return. There are many issues that arise in transmission pricing design, and there is no perfect methodology for determining transmission prices. Not surprisingly then, a number of detailed reviews of transmission pricing have been undertaken since the establishment of the National Electricity Market (NEM) in the mid 1990s. The current transmission pricing rules were established in Under the rules, each transmission network service provider (TNSP) must submit a Pricing Methodology with its five yearly revenue proposal. TransGrid is required to submit its next Pricing Methodology by 31 May In developing its next Pricing Methodology, TransGrid will draw on the experience gained under the current rules for the past seven years, and engage in a constructive manner with customers and other stakeholders to understand how the existing Pricing Methodology may be improved. To assist customers and other stakeholders in formulating their views, this paper discusses the economic principles and issues that must be addressed in developing efficient transmission prices. In addition, it explains the current rules and summarises a significant number of reviews that have had a bearing on the nature of transmission services, the arrangements for regulating the services, and the development of the current transmission pricing arrangements. In recent years, growth in maximum demand in New South Wales has moderated, reflecting the impacts of distributed generation (in particular solar panels) increasing energy efficiency and consumer response to increasing energy prices. Under the latest forecasts for the 10-year planning period from 2013/14 to 2022/23, the 10% probability of exceeding summer peak demand is expected to grow at an annual rate of 1%, and the winter peak demand to grow at an annual growth rate of 1.1%. These forecast growth rates are lower than last year s forecasts and lower than recent historic trends. In the context of the current and expected future changes in patterns and levels of supply and demand across the NSW transmission system, it is important to ensure that transmission prices provide efficiencies across all customer bases. In this regard, it is worth noting that the Standing Council on Energy and Resources (SCER) recently announced that it had developed proposals to change the National Electricity Rules, so that they provide better guidance for setting cost reflective network distribution prices. In making this announcement SCER said 1 : Over the longer term, more efficient pricing of networks should have significant flow-on impacts to overall electricity expenditure faced by consumers due to better utilisation of the network and deferral of peak demand driven network investment. Although SCER s rule change proposal relates to distribution pricing, SCER s observations regarding the long-term benefits of efficient network pricing apply equally to transmission. Over the past decade or so transmission prices, which comprise approximately 8% of the average consumer s electricity costs, have increased significantly as a result of substantial renewal and augmentation investment in the NSW system. The increase in the overall level of transmission prices is a separate issue to the Pricing Methodology that determines how prices are set in relation to different categories of services and across customers. This consultation paper is only concerned with the transmission Pricing Methodology. This consultation paper also includes a number of questions that are intended to assist customers and stakeholders in formulating their submissions. TransGrid is adopting an open and transparent process for canvassing views on transmission pricing, and will carefully consider the feedback from this consultation paper to assist it in developing its forthcoming Pricing Methodology for submission to the Australian Energy Regulator (AER). TransGrid also recognises that it is not practical or feasible to develop a new Pricing Methodology without first understanding its impact in terms of pricing outcomes for particular customers. TransGrid will therefore undertake significant internal work to assess the proposals and issues that are raised in this consultation exercise. TransGrid will keep customers and other stakeholders informed during this process of formulating a revised Pricing Methodology during the first quarter of SCER, Energy Market Reform Bulletin 18, 29 October 2013, available from: 3 TransGrid Consultation Paper: Transmission Pricing November 2013

4 1. Background and Purpose The current rules governing transmission pricing are set out in Chapter 6A of the National Electricity Rules (Rules). The current transmission pricing rules came into force in December 2006, following an extensive review by the Australian Energy Market Commission (AEMC). In setting the current transmission pricing rules, the AEMC limited the degree of discretion afforded to Transmission Network Service Providers (TNSPs) in setting prices. The current Rules therefore ensure that TNSPs adopt broadly consistent approaches to transmission pricing. Under Chapter 6A of the Rules, TNSPs must submit a proposed transmission Pricing Methodology to the Australian Energy Regulator (AER) as part of the AER s revenue cap determination process. Each TNSP s Pricing Methodology must conform with requirements detailed in the Rules. Following the AER s approval of a TNSP s Pricing Methodology, that methodology must be applied for the duration of the regulatory control period, which is typically five years. TransGrid will lodge its next Pricing Methodology proposal by 31 May Both TransGrid and its customers now have up to seven years experience with the existing pricing arrangements. In light of this, the purpose of this paper is to canvass the views of customers and other stakeholders on transmission pricing arrangements and to identify any opportunities for further improvement to those arrangements. Transmission pricing arrangements for generators were reviewed recently by the AEMC in its Transmission Frameworks Review. In that review, the AEMC made recommendations on how generators access the wholesale electricity market; the way network congestion is managed; and the future transmission charging arrangements for generators 3. Those recommendations are now being considered by the Commonwealth and State Governments. Given the significant work undertaken by the AEMC in relation to generator access and charging issues, these matters are not addressed in this consultation paper. Instead, the scope of our consultation is limited to transmission pricing arrangements for load only. In particular, we welcome feedback from customers regarding their experience of the outcomes delivered under the current arrangements. We are keen to receive suggestions from those same customers as to how the existing pricing arrangements might be improved to address issues of concern to them. The scope of possible future developments in TransGrid s Pricing Methodology is constrained by the requirement to comply with the Rules. Therefore, improvements that do not require amendments to the Rules can be implemented through our forthcoming Pricing Methodology. If improvements to pricing arrangements require amendments to be made to the Rules, TransGrid will promote such amendments, provided they are likely to accord with the National Electricity Objective, which is: To promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers of electricity with respect to: (a) (b) price, quality, safety, reliability and security of supply of electricity; and the reliability, safety and security of the national electricity system. 2 Transitional arrangements apply to TransGrid s forthcoming revenue cap review. We must submit a transitional Revenue Proposal relating to the 2014/15 financial year only by 31 January Under clause (h)(1), the transitional proposal does not include a proposed pricing methodology. By 31 May 2014, TransGrid must submit a full Revenue Proposal including a proposed pricing methodology for the five year period commencing in July Further details are available from the AEMC at: html 4 TransGrid Consultation Paper: Transmission Pricing November 2013

5 The remainder of this paper is structured as follows: Section 2 Discusses the pricing objectives, issues and principles that should be considered in designing effective transmission pricing arrangements. Section 3 Provides a brief overview of the current transmission pricing arrangements, and background information on their development. Section 4 Identifies and briefly discusses the transmission pricing issues on which customers and stakeholders may wish to comment. Section 5 Concludes the paper by describing the next steps in, and the timeline for TransGrid s consultation on transmission pricing issues. The attachment provides a summary of the numerous industry reviews that have been directly or indirectly concerned with the regulation of transmission services and transmission pricing arrangements. Throughout the paper, a number of questions are set out. These questions are intended to guide and assist respondents in framing their submissions. They are not intended to constrain the scope of responses to this paper. Submissions should be made by Friday 13 December 2013 by either: Pricing.Consultation@transgrid.com.au Website: Post: Stephen Clark Executive General Manager Network Planning and Performance PO Box A1000 Sydney, NSW, 1235 TransGrid intends to publish all submissions received on our website. If you do not want your submission to be published, please state this at the time of lodgement. Any enquiries should be directed to Warren Barat on (02) TransGrid Consultation Paper: Transmission Pricing November 2013

6 2. Transmission Pricing Objectives and Principles 2.1 Introduction This section discusses the objectives, issues and principles that may inform the design of effective transmission pricing arrangements. This section is structured as follows: Section 2.2 Discusses the transmission pricing objectives and the distinction between the revenue and price-setting processes. Section 2.3 Briefly explains the AER s revenue-setting process, which uses the building block approach. Section 2.4 Discusses the concept of economically efficient pricing, and the particular issues that arise in relation to transmission networks. Section 2.5 Sets out a number of principles that may guide the future development of transmission arrangements. 2.2 Transmission Pricing Objectives Transmission pricing has two broad objectives, which are: to provide price signals that promote efficient outcomes; and to provide TNSPs with a means of fully recovering their allowed revenues 4. While transmission pricing must satisfy these objectives, the process for determining a TNSP s total revenue requirement is separate to the price setting process as shown in Figure 1 on the next page. 4 It should be noted that TransGrid is the co-ordinating Network Service Provider for transmission services in NSW, and in that capacity it sets prescribed transmission prices annually on behalf of all NSW TNSPs. 6 TransGrid Consultation Paper: Transmission Pricing November 2013

7 Figure 1: Relationship between revenue and price setting processes This consultation paper is concerned only with the price setting process. However, it is instructive to briefly explain the basis on which the AER determines a TNSP s total revenue requirement, which we discuss next. 2.3 Revenue Setting Process Under the Rules, each TNSP s Maximum Allowed Revenue (MAR) or revenue cap is determined by the AER for a regulatory period, which is typically five years. The MAR sets out the amount that a TNSP is able to recover in each year, the Aggregate Annual Revenue Requirement (AARR). In setting the MAR, the AER applies a revenue building block approach, which is prescribed in Part C ( Regulation of Revenue - Prescribed Transmission Services ) of Chapter 6A of the Rules. Under this approach, the AARR is determined as the sum of the components of a TNSP s total annual costs for each year of the regulatory period, as shown in Figure 2. Figure 2: Revenue building blocks 7 TransGrid Consultation Paper: Transmission Pricing November 2013

8 In broad terms, the MAR provides a revenue allowance that is considered by the AER to reflect forecasts of efficient capital investment and operating expenditure, and efficient financing costs over the regulatory period. In determining a TNSP s MAR, the AER conducts a detailed, independent review of the TNSP s revenue and expenditure requirements. In conducting its review, the AER consults with stakeholders and obtains independent expert reports to advise it on technical matters, such as the TNSP s expenditure proposals. The AER's determination must be conducted in accordance with the Rules and the National Electricity Law. In particular, the AER must ensure that its decision will, or is likely to, contribute to the achievement of the National Electricity Objective, and complies with the Revenue and Pricing Principles, which are set out in the National Electricity Law. Once the MAR is set, transmission prices are then determined in accordance with the TNSP s Pricing Methodology. The Pricing Methodology must accord with the principles and other requirements of the Rules; these are set out in Part J ( Prescribed Transmission Services - Regulation of Pricing ) of Chapter 6A and the Pricing Methodology Guidelines published by the AER. The Pricing Methodology must be approved by the AER before it is applied by the TNSP. 2.4 Economically Efficient Pricing As already noted, transmission pricing has two objectives, which are: to provide efficient signals for use of and investment, in the transmission network; and to provide a mechanism by which TNSPs can recover their efficient total costs. From an economic point of view, efficient pricing is important because it provides information to producers and consumers regarding the cost of producing goods and services. As with any other good or service, if transmission prices are not cost reflective they will tend to distort the provision of transmission services, leading to a less than efficient outcome for customers. However, in practice there are considerable challenges involved in establishing economically efficient transmission pricing. The task is therefore to develop solutions which approximate the ideal of fully cost reflective pricing, bearing in mind practical considerations such as complexity and transparency. To illustrate some of the challenges, the remainder of this section discusses the concepts of marginal cost pricing; sunk costs; two-part tariffs; equity and efficiency considerations; and transmission service categories Marginal Costs In terms of providing efficient price signals, the relevant cost is the marginal cost, which is the cost of providing an additional unit of a service. In practice, marginal cost pricing is complicated because the additional unit must be defined; the incremental costs calculated; and the appropriate time horizon determined. In relation to the time horizon, marginal cost can be defined in either short run or long run terms. In the short run, the physical investment in the transmission network is fixed. The short-run marginal costs of transmission are those that vary with respect to the flows of energy over existing facilities, that is, with respect to the scheduling and dispatch of generation and load. These costs consist of: the physical energy losses incurred 5 ; and the opportunity cost of constraints on the network. Constraints are a cost to the NEM because they result in more expensive generation being used than would otherwise be the case. A competitive wholesale energy market can reflect the short-run costs of supplying energy to the customer by incorporating the cost of losses and constraints. The price of energy delivered to different parts of the network will vary depending on the losses and constraints incurred in delivering that energy. Where these costs are reflected at each point on the network, this is known as nodal pricing. However, many electricity markets, including the NEM, reflect these costs on the basis of regions, which combine a number of connection points. In contrast to short run marginal costs, long run marginal costs recognise the future costs of expanding network capacity. Long run marginal cost is therefore highly dependent upon the extent to which a network may, or may not, need to be expanded to serve the relevant marginal change in demand. When a network has significant spare capacity, long run marginal cost may be comparatively low. Conversely, long run marginal cost may be comparatively high prior to a significant expansion of capacity. 5 In the NEM design, losses are incorporated in the market settlements process and therefore do not need to be considered in network pricing. 8 TransGrid Consultation Paper: Transmission Pricing November 2013

9 2.4.2 Sunk Costs A further pricing issue arises because the concept of marginal cost only considers the future costs of providing an additional unit of service. Marginal cost therefore does not recognise the costs that have been incurred in providing the existing infrastructure. These costs are referred to as sunk costs because they cannot be affected by future investment or consumption decisions and in this sense are irreversible or sunk. While sunk costs should not be factored into future investment or consumption decisions, the costs must be recovered and therefore reflected in transmission prices. If this were not the case, then TNSPs would be unable to earn a reasonable return on their assets. Such an outcome would lead to dynamic inefficiency, as TNSPs would not be appropriately incentivised to invest in future transmission capacity Two-Part Tariffs One challenge in transmission pricing is to set prices that reflect marginal costs, but also provide a total revenue for the TNSP that recovers its total costs. As transmission networks tend to exhibit strong economies of scale, the marginal costs of providing transmission services tend to be lower than the average cost. In these circumstances, pricing on the basis of marginal cost will not provide sufficient revenue to recover the total costs of providing transmission services. The challenge of recovering total costs (including sunk costs) on the one hand, and providing efficient price signals on the other, was addressed by Ronald Coase in his 1946 paper, The Marginal Cost Controversy. 6 In that paper, Ronald Coase concluded that a two-part tariff should be adopted, in which there is a volumetric charge and a fixed monthly fee. The volumetric charge is set equal to marginal cost and the fixed monthly fee is set equal to each customer s share of fixed costs. In a later paper, Baumol and Bradford 7 argue that customers that have a more inelastic demand (that is, they have a greater willingness to pay) should face prices that include higher mark ups on the marginal cost. This concept is referred to as Ramsey Pricing. Two-part tariffs and Ramsey Pricing are alternative mechanisms for achieving the same objectives. As already explained, the objectives are to provide efficient pricing signals and also enable the service provider (in this case the TNSP) to recover its total costs. If either objective is not properly met, then the outcome for customers will be less than efficient. For example, if prices are significantly above the marginal costs of providing transmission services, then a customer may wish to bypass the transmission network. Such bypass will be inefficient if the costs of bypass exceed the marginal costs of providing transmission services. Inefficient bypass is detrimental to all customers, because it has the effect of increasing the average costs Equity and Efficiency Considerations Inevitably, issues of fairness or equity arise in relation to the preferred method for recovering the total costs of providing transmission services. In particular, by either charging a monthly fee or levying higher charges on those customers who have a more inelastic demand, questions of equity will arise. These issues need to be considered in the design of transmission prices. Equity and efficiency issues also arise if existing and prospective users face different charges for essentially the same service. This is an important issue in transmission pricing, where the addition of new load may lead to higher transmission investment and potentially higher costs for existing users in addition to the party causing the new investment. In this case, questions regarding equity and efficiency are intertwined. On the one hand, new users should face the marginal costs of their locational decisions. On the other hand, it is arguable that existing users do not have any property rights in relation to the existing capacity of the transmission network, and therefore it is appropriate for new and existing users to face exactly the same charges. Setting aside questions of equity, it could be argued that it is inefficient for existing users of the network to obtain transmission services at lower prices than future users. This issue is inextricably linked to questions regarding property rights, and the nature of the transmission service that is provided by TNSPs and paid for by customers Service Categories A further complicating issue in relation to transmission pricing is that there are a number of different transmission services. Apart from entry and exit connection services - which are beyond the scope of this discussion - there are transmission use of system services and prescribed common transmission services. In addition to these prescribed (regulated) services, which are provided in accordance with the commercial and technical requirements set out in the Rules, users are able to obtain negotiated transmission services that address their particular needs. 6 Ronald Coase, The Marginal Cost Controversy, Economica, Vol 13, Baumol and Bradford, Optimal Departures from Marginal Cost Pricing, American Economic Review, TransGrid Consultation Paper: Transmission Pricing November 2013

10 The transmission pricing issues described previously arise in relation to each of the different categories of transmission service. In addition, as transmission networks in different regions are interconnected, the users in one region may affect the costs of providing transmission services in another region. It is therefore important to consider the costs of providing transmission services both within a region and also between regions. This latter issue has recently been addressed through a rule change relating to inter-regional transmission use of system (TUOS) charges. 2.5 Transmission Pricing Principles As we will discuss in section 3 of this paper, there have been numerous reviews of transmission pricing arrangements in Australia and other jurisdictions. The following transmission pricing principles were developed in a review undertaken by the National Electricity Code Administrator (NECA) in 1999: Prices should reflect the level of spare capacity. Costs should not be allocated to specific customers or customer groups if the service provided delivers system-wide reliability or security benefits. Prices should signal future new investment costs. Prices should be designed to minimise bypass that would result in unnecessary duplication of assets. Account should be taken of the merits of price stability. In addition to NECA s principles, the first version of the National Electricity Rules 8 provided similar, high-level principles to guide network pricing as follows: Network prices should in principle be cost reflective. Network pricing should provide non discriminatory access to the network. Network pricing should be compatible with the electricity market design proposals to encourage and facilitate the development of these arrangements. Network prices should provide signals to optimise the cost of network development in order to minimise the cost of development and operation of the market. Pricing for interconnectors should encourage efficient market operation and provide appropriate signals for the development of new interconnectors. Prices for transmission services and distribution services should be transparent and published in order to provide pricing signals to Market Participants. It is noteworthy that these principles, while expressed at a high level, broadly reflect the transmission pricing objectives and economic concepts discussed in the section 2.3. In developing further guidance in relation to transmission pricing arrangements, it is also instructive to note the recent work undertaken by the Electricity Authority in New Zealand, which is currently reviewing Transpower s transmission Pricing Methodology. Rather than setting out transmission pricing principles, the Electricity Authority discussed its preferred approach to transmission pricing in the following terms 9: The Authority considers that an administrative approach to charging should be preferred when a market-based charge is inefficient or impracticable or does not fully recover the economic costs of transmission services. The Authority s order of preference for administrative approaches is: (a) exacerbators pay an exacerbator is a party whose action or inaction lead to cost externalities (i. e. costs on others) and who could change their behaviour if they faced the full cost of that action or inaction; (b) beneficiaries pay a beneficiary is a party for whom the private benefits of a service exceed its share of the costs and who would therefore be willing to pay for a portion of that service if that were the only means of acquiring the benefit; and (c) alternative charging options where the costs are recovered from the users of the associated services through some other mechanism, such as a low-rate, broad-based charge. 8 Effective from 1 July 2005, and adapted from the former National Electricity Code. 9 Electricity Authority, Transmission Pricing Methodology: Issues and Proposal, Consultation Paper, 10 October 2012, paragraph , page TransGrid Consultation Paper: Transmission Pricing November 2013

11 In relation to the beneficiary pays approach, the Electricity Authority commented as follows 10 : A beneficiaries-pay approach to transmission charging is emerging as common practice internationally. The trend reflects moves by decision-makers to adopt a cost causation principle which will ensure that only those parties benefiting from transmission facilities are charged for the associated costs. In particular, emerging practice involves adopting a market-like approach that grants the parties benefiting from a transmission investment the ability to exercise decision rights about the investments from which they are expected to derive a benefit. In the Argentinean and New York electricity markets beneficiaries have been given decision rights over major new transmission investment through a public contest method. A similar method was developed in New Zealand in 2002 by the Transport Working Group of the Electricity Governance Establishment Board. However, the Electricity Authority also noted that an alternative charging option may be needed when a market-based charging approach or charges based on exacerbators pay or beneficiaries pay are not efficient, practicable or do not recover the full costs of transmission services. The Electricity Authority set out the following high-level principles if an alternative charging option is required 11 : The Authority considers that the key principles for identifying an alternative charging option that is efficient are that the option should: (a) minimise, to the extent practicable, any distortion from the efficient level in use of the transmission grid resulting from the imposition of the charge; (b) minimise, to the extent practicable, any distortion in grid-related investment from the efficient level resulting from the imposition of the charge; and (c) ensure the costs of providing the transmission grid, as approved by the Commerce Commission, are fully recovered so future investment is not stifled by the concerns of investors that they will not receive a return on their approved investments. TransGrid considers that the Electricity Authority s discussion of transmission pricing approaches; NECA s pricing principles; and those principles reflected in the first version of the Rules are all helpful in guiding the future development of transmission pricing arrangements in Australia. Questions for Stakeholders Do you agree with the transmission pricing objectives outlined in this section? Are there any other objectives for transmission that we have not identified? Which pricing principles or approaches do you consider should guide the future development of transmission pricing arrangements in the NEM? 10 Ibid, paragraph and , pages 42 and Ibid, paragraph page TransGrid Consultation Paper: Transmission Pricing November 2013

12 3. Development of Current Transmission Pricing Arrangements 3.1 Introduction This section provides background information on the current transmission pricing arrangements, including an overview of the numerous industry reviews relating to transmission pricing. It concludes by setting out a number of questions for respondents to consider. 3.2 Development of Transmission Pricing Arrangements Since 1999, issues relating to transmission pricing in the NEM have been the subject of over fifteen reviews. The first of these was conducted by NECA in July As already explained in section 2.5 NECA s transmission and distribution pricing review established a set of high level principles for transmission network pricing. In addition, NECA s review outlined incentive mechanisms designed to encourage improved network service provision. NECA also developed a framework for negotiated services to be provided by network service providers. In August 2001 and February 2002, two further reviews were completed. The first of these focused on integrating the energy market and network services. It led to refinements in arrangements to provide stronger incentives for TNSPs to undertake planned outages in a way that minimises their impact on the wholesale electricity market. The second review was focused on improving the efficiency and transparency of network investment decision making. A major review of transmission pricing was concluded by the AEMC in December The review largely confirmed the continued operation of the pricing methodologies established by NECA in 1999, while also providing scope for innovation in the future. A key conclusion of the review was that the causer pays principle should be central to the allocation of transmission network costs. Additionally, generator transmission use of system and deep connection charges were assessed. However, given the market circumstances at the time, it was determined that existing market mechanisms provided adequate locational signals to generators. The review s recommendations were implemented through Rule provisions, which set out detailed principles for the allocation of TNSP costs and the structuring of transmission prices. The various reviews undertaken since 2006 have focused on issues including: the establishment of arrangements for national transmission planning; the strengthening of incentives for TNSPs to deliver network services efficiently; the development of national transmission reliability standards; the management of network congestion, and in particular inter-regional congestion; the potential for refinement of intra-regional locational signals, and scope for introducing full nodal pricing having regard to the effects on energy financial markets; the establishment of a new Regulatory Test for Transmission (RIT-T), to foster further improvement in the efficiency and transparency of transmission investment; the development of arrangements allowing for Scale Efficient Network Extensions, the intent of which is to ensure that the expansion of the transmission network to connect generation clusters will be efficient; and the introduction of a new inter-regional transmission charge to be levied between TNSPs in neighbouring regions, which will: be more reflective of the actual costs incurred in providing those services; result in the costs of transmission capacity used for conveying electricity between regions being allocated to the regions that derive benefits from such capacity; and the feasibility of arrangements for offering firm generator access, which would provide generators with the ability to insure against the risk of network congestion. 12 AEMC, Pricing of Prescribed Transmission Services Rule Determination, December TransGrid Consultation Paper: Transmission Pricing November 2013

13 These reviews complement, but have not altered the transmission pricing arrangements that were put in place by the AEMC s Pricing of Prescribed Transmission Services Rule Determination in December An overview and explanation of these arrangements is provided in the next section. 3.3 Current Transmission Pricing Arrangements The material set out in this section is sourced in part from the AEMC s recent Rule Determination on inter-regional transmission charging 13. As noted in section 2.3, the total costs to be recovered through charges for prescribed transmission services are regulated under a revenue cap, which is set every five years by the AER. Pursuant to Part C of Chapter 6A of the Rules, the AER determines a MAR, which is adjusted to establish an AARR for the TNSP. The AARR is the total adjusted 14 revenue excluding operating and maintenance costs that relate to the provision of prescribed transmission services 15. There are four categories of regulated or prescribed transmission services, as follows: Entry services, which are connection services provided to generators; Exit services, which are connection services provided to Distribution NSPs and customers who are connected directly to the shared transmission network; Prescribed common transmission services; and Transmission Use of System services (TUOS). An overview of the process governing cost allocation, revenue recovery and pricing is shown in Figure 3 the next page. 13 AEMC, Rule Determination:National Electricity Amendment (Inter-regional transmission charging) Rule, 28 February 2013, pages 115 to Clause 6A (1) states that the AARR is the maximum allowed revenue adjusted in accordance with the provisions set out in clauses 6A. 7, 6A. 8, and 6A Arrangements for recovery of the TNSPs operating and maintenance costs are explained below. 13 TransGrid Consultation Paper: Transmission Pricing November 2013

14 Figure 3: Process for allocating transmission costs and determining charges 14 TransGrid Consultation Paper: Transmission Pricing November 2013

15 Step 1: Allocating Total Revenue to the Four Prescribed Services The first step in the process involves the allocation of the AARR into separate Annual Service Revenue Requirements (ASRR) for each of the four prescribed services. This allocation is based on the costs of transmission system assets directly attributable to providing each service, relative to the total costs of assets used in providing prescribed services. The assessment of costs in this process is on the basis of optimised replacement costs, so that differences in the ages of assets (and hence their written down costs) does not affect the allocation 16. The allocation of the AARR must be such that every portion of the AARR is allocated, and the same portion of the AARR is not allocated more than once. Step 2: Allocating the ASRRs The ASRRs of each of the four prescribed services represent separate cost pools for each of the services. The second step involves the further allocation of these cost pools, to enable the determination of the amounts to be recovered through transmission charges, as described below. Entry and Exit Services Prescribed common transmission services The ASRRs for the two connection services are allocated to individual connection points using the same asset-based cost allocation methodology as that used to allocate the AARR. Prescribed common transmission services provide common benefits to all transmission customers regardless of their location, such as voltage support through the use of Static VAr Compensators, which irrespective of their location, provide services to all of the interconnected network. The total cost of common services is the sum of: the prescribed common transmission service ASRR (which represents asset related costs); and the TNSP s operating and maintenance costs (which were excluded from the AARR for the purpose of determining the ASRRs). The total common service cost is recovered through transmission charges on a postage stamp basis. Transmission Use of System (TUOS) services The cost of providing TUOS services to a particular customer generally varies depending on factors such as the location of the customer and the customer s usage of the network. A portion of the ASRR for transmission use of system services is therefore allocated on a locational basis as follows: 50% of the ASRR is allocated to individual connection points based on an assessment of the customer s proportionate usage of the network. The Rules note that the Cost Reflective Network Pricing (CRNP) or modified CRNP approaches are two permitted assessment methods. The Rules allow an alternative allocation between locational and non-locational components based on a reasonable estimate of future network utilisation and the likely need for future transmission investment, and that has the objective of providing more efficient locational signals. Adjustments for any proceeds from inter-regional settlement residue auctions are made and the remaining ASRR (termed the non-locational component) is adjusted for: any over/under collections of revenue in previous periods; any amount arising from the application of clauses 6A (h) and (i) of the Rules; and to remove any intra-regional settlement residues. As explained below, the non-locational component must be recovered through charges on a postage stamp basis. 16 This reflects the general principle that the service potential of a transmission asset is generally independent of its age. 15 TransGrid Consultation Paper: Transmission Pricing November 2013

16 Step 3: Converting Allocated Costs into Prices Under the Rules, separate prices must be developed for each category of prescribed transmission services, being: (1) prescribed connection services (entry and exit); (2) prescribed common transmission services; (3) prescribed TUOS services locational component; and (4) prescribed TUOS services non-locational component. The Rules set out the following detailed principles governing the structure of prices for each prescribed service. Connection services (entry and exit) Common transmission services Transmission Use of System (TUOS) services The prices for these services must be a fixed annual amount, charged monthly. Prices must be on a postage stamp basis. This means that the price per unit is the same for all connection points and for all customers regardless of how much energy is used by the network user or the location of the user in the transmission network. Prices for the locational component must be based on demand at times of greatest utilisation of the transmission network and for which network investment is most likely to be contemplated. In addition, subject to detailed provisions set out in the Rules, prices for recovering the locational component must not change by more than 2 per cent per annum compared with the load weighted average price for this component for the relevant region. Prices for recovering the non-locational component services must be on a postage-stamp basis. At each five-yearly revenue cap review, the Rules require each TNSP to prepare a Pricing Methodology, which is to apply for the regulatory period. The Pricing Methodology must conform with the principles set out in the Rules and the AER s Pricing Methodology Guidelines. The Pricing Methodology must be approved by the AER before it is applied. Once it is approved, the TNSP must apply the Pricing Methodology to determine its transmission prices for the duration of the relevant regulatory period. Unless the Pricing Methodology is affected by a material error or deficiency, it may not be amended during a regulatory period. Our transmission pricing model is subject to biennial internal audit, to ensure compliance with the Rules and our approved Pricing Methodology. The last internal audit was completed in July Our prescribed transmission pricing and TUOS billing controls and processes are also subject to annual external audit by the NSW Audit office. The last audit was completed in April The summary set out above illustrates the limited extent to which TransGrid has flexibility in setting transmission prices under the current Rules. Questions for Stakeholders Do you support the existing approach to setting transmission prices? If not, what other arrangements would you recommend that would better promote the National Electricity Objective? Do you support the limited flexibility currently provided to TransGrid in setting transmission prices? If not, what changes would you propose? Which aspects of the current transmission pricing arrangements, if any, should be amended to provide TransGrid with greater flexibility? If increased flexibility were provided, how should it be exercised to ensure that customers are treated equitably? Are the existing arrangements that require TransGrid to submit a Pricing Methodology to the AER for approval appropriate? If not, what changes would you propose? Are the audit arrangements appropriate? If not, what changes would you propose? 16 TransGrid Consultation Paper: Transmission Pricing November 2013

17 4. Transmission Pricing Consultation The purpose of this section is to identify and briefly discuss the transmission pricing elements on which customers and stakeholders may wish to comment. However, it should be noted that customers and stakeholders are invited to raise any issues in relation to the existing transmission pricing arrangements. 4.1 Cost Reflective Network Pricing As noted in section 3 of this paper, the Rules provide for TNSPs to calculate the locational component of the transmission use of system charge using the Cost Reflective Network Pricing (CRNP) methodology, the modified CRNP, or some other basis that provides a reasonable estimate of the proportionate use of the relevant transmission assets. It is noted that whilst the Rules do not mandate the use of CRNP, in the period since the 1999 NECA transmission pricing review, no other methodology has been used by TNSPs in the NEM. The CRNP methodology allocates a proportion of shared network costs to individual customer connection points. TransGrid applies the CRNP methodology using the T-PRICE cost reflective network pricing software, which is used by most TNSPs in the NEM. The CRNP methodology requires three sets of input data, which are: an electrical (load flow) model of the network; a cost model of the network; and an appropriate set of load and generation patterns. In contrast to the principle of marginal cost pricing, the CRNP methodology is designed to allocate the full costs of assets to users. As a consequence, the application of this methodology may generate usage prices that exceed the avoidable cost of the service. This, in turn, may lead to inefficient outcomes because network users consumption and investment decisions may be based on network price signals that are not cost reflective. To address this concern, the current rules only apply CRNP (or modified CRNP) to 50% of the costs that could be allocated on a locational basis. As noted in section 3.3, the remainder of the locational costs, which are not recovered through CRNP, together with common services costs (which it is not possible to allocate on a locational basis), are recovered using postage stamp charging. A question arises as to whether the 50% allocation of costs using the CRNP methodology provides a price signal that reasonably equates to the long run marginal costs. A further issue arises in relation to whether the CRNP or modified CRNP methodology should be adopted. The modified CRNP adjusts the asset costs by a factor that reflects the current level of utilisation. As a consequence, and in contrast to the CRNP methodology, the modified CRNP methodology recognises that transmission prices should be lower in locations where there is spare capacity, and higher in locations where capacity is scarce. The modified CRNP methodology is therefore more closely aligned with the economic principles discussed in section 2 of this consultation paper. TransGrid currently employs the standard CRNP methodology, rather than the modified CRNP. The relative merits of the standard and modified CRNP methodologies were considered in the AEMC s recent Rule change proposal in relation to inter-regional TUOS charges, as follows 17 : A further consideration for the Commission was whether cost reflective network pricing or modified cost reflective network pricing should be used for the purposes of calculating the charge. Modified cost reflective network pricing can be considered to be more reflective of long run marginal costs, because it discounts transmission charges based on the level of excess transmission capacity in different parts of the network. This should encourage more efficient locational decisions, because consumers will have incentives, all other things equal, to locate in areas where there is spare capacity. 17 AEMC, National Electricity Amendment (Inter-regional transmission charging) Rule 2013, Rule Determination, 28 February 2013, pages 24 and TransGrid Consultation Paper: Transmission Pricing November 2013

18 However, modified cost reflective network pricing would also be more complicated to apply than the standard cost reflective network pricing approach, as a certain level of subjectivity would be required to establish line ratings under a range of operating conditions for shared parts of the network contributing to inter-regional flows. These line ratings would be used by the transmission networks service provider as part of the process to determine the level of utilisation on a line. On balance we consider that the subjectivity inherent in such a process is unlikely to outweigh the benefits the modified cost reflective network pricing approach would deliver for calculating an inter-regional charge. This was supported by modelling done by ROLIB Pty Ltd, which illustrated that the use of cost reflective network pricing versus modified cost reflective network pricing would not lead to significant differences in the quantum of cost allocations, primarily because excess capacity is expected to be a factor on radial transmission lines in parts of the network more remote from inter-regional transmission assets. The AEMC also stated 18 : It can be expected to be administratively onerous for those transmission businesses using standard cost reflective network pricing intra-regionally to apply a modified cost reflective network pricing method to calculating an inter-regional transmission charge. This is because collecting and applying asset utilisation data is complex and time consuming. For transmission businesses that have never used modified cost reflective network pricing, there will also be the time and costs associated with the adjustment to the new process. TransGrid notes that the cost reflectivity of the modified CRNP methodology depends on the accuracy of the subjective assessments made in assigning a utilisation level to each and shared network asset. TransGrid has not modelled the pricing impacts of adopting a modified CRNP methodology. Questions for Stakeholders Should the existing arrangements for determining locational based transmission use of system charges be amended and, if so, how? Should TransGrid continue to apply the CRNP methodology or should it move to modified CRNP, or some other method? 4.2 Operating Conditions for Cost Allocation Process The choice of operating conditions is important in developing prices using the CRNP or modified CRNP methodologies. In an earlier version of the Rules, guidance was provided in relation to the selection of operating conditions. In particular, the operating conditions to be used were required to include at least 10 days with high system demand to ensure that loading conditions, which impose peak flows on all transmission elements, are captured. Schedule 6A. 3. 2(3) of the current Rules is less prescriptive, requiring that the allocation of dispatched generation to loads be over a range of actual operating conditions from the previous financial year, and that the range of operating scenarios is chosen so as to include the conditions that result in most stress on the transmission network and for which network investment may be contemplated. The use made of the network by particular loads and generators will vary considerably depending on the load and generation conditions on the network. For this reason a number of operating scenarios are examined with different load and generation patterns. In selecting those operating scenarios it is important to recognise that the operating conditions that impose most stress on particular elements may occur at times other than for system peak demand. The T-PRICE software (used by TransGrid) automatically captures the peak loading conditions on network elements from the sample of operating conditions analysed. TransGrid, therefore, uses the full year of operating data (i.e. 365 days of half hourly data) to avoid the need for judgement concerning an appropriate set of operating conditions. 18 AEMC, National Electricity Amendment (Inter-regional transmission charging) Rule 2013, Rule Determination, 28 February 2013, page TransGrid Consultation Paper: Transmission Pricing November 2013

19 In accordance with clause 2.2(f) of the AER s Pricing Methodology Guidelines, where actual operating conditions from the previous complete financial year are unavailable for a connection point, as would be the case for a new connection point or material changes in customer requirements at a connection point, an estimate of demand must be used instead. TransGrid derives this estimate from information obtained from the relevant transmission network customer via the connection application and connection amendment processes set out in Chapter 5 of the Rules. Question for Stakeholders What operating conditions should be used for modelling purposes, and how should the pricing outcomes from these different conditions be taken into account in determining the applicable transmission prices? 4.3 Treatment of Network Support Costs Network support refers to a service provided by a third party that obviates or defers the need for investment in the transmission network. TransGrid will procure network support services where these services provide a more costeffective means of meeting our customers requirements. The Rules currently provide no guidance in relation to how network support costs should be reflected in transmission prices. TransGrid s current Pricing Methodology converts the network support costs to an equivalent asset replacement cost. This notional asset is added to the asset replacement cost of the transmission assets these services support. TransGrid currently recovers these costs on a locational basis as part of its CRNP methodology. The rationale for TransGrid s current approach is that the alternative network augmentation costs would be recovered on a locational basis, and therefore it is appropriate for network support costs to be similarly recovered. On the other hand, unlike the cost of a transmission asset, the costs of network support services may depend on the extent to which these services are required during the year. Therefore, expressing network support costs as an asset value will inevitably involve estimations and assumptions. It could be argued, therefore, that it is better to treat network support costs as an operating cost, and recovered as part of the common service charge, in accordance with clause 6A (f). Question for Stakeholders Should TransGrid continue to recover network support costs on a locational basis by converting the cost to an equivalent asset value, or should these costs be treated as an operating cost and recovered through the common service charge? 4.4 Structure and Application of Prices The current Rules provide some guidance in relation to the structure of transmission prices, but also provide some flexibility for TNSPs. In this section we discuss the Rules requirements in relation to the structure of prices and TransGrid's current methodology Prescribed Entry and Exit Services Rule 6A (c) states that prices for prescribed entry services and prescribed exit services must be a fixed annual amount. In accordance with this Rule requirement, TransGrid s prescribed entry and exit service costs are recovered as a fixed annual charge on a fixed $/day price basis, billed monthly Prescribed Common Transmission Services Rule 6A (d) states that prices for prescribed common transmission services must be on a postage-stamp basis. In accordance with this Rule requirement, TransGrid s Pricing Methodology recovers the costs of providing prescribed common transmission services on the basis of contract agreed maximum demand or historical energy. These charging arrangements are identical to those relating to the recovery of the non-locational component of prescribed TUOS, which are described in more detail in section on the next page. 19 TransGrid Consultation Paper: Transmission Pricing November 2013

20 4.4.3 Prescribed TUOS Services locational component In accordance with Rule 6A (e), prices for recovery of the locational component of the prescribed TUOS charges is based on demand at times of greatest utilisation of the transmission network and for which network investment is most likely to be contemplated. In particular, TransGrid s locational costs are recovered on the basis of a maximum monthly demand charge on a $/kw/month basis. The demand based locational TUOS price at each connection point is calculated by dividing the amount to be recovered by the average of the forecast monthly maximum demands in each month at that connection point in the previous financial year. The forecast monthly maximum demands take forecast system load growth into account. Under this approach, therefore, the locational TUOS prices are based on the forecast, not the historical, average of the monthly maximum demands. Where there are both customer loads and generator auxiliary loads at a connection point, rates are set on the basis of the full load at the connection point, even though the generator does not pay usage charges. It is worth noting that TransGrid s previous Pricing Methodology recovered the locational component of TUOS via two forms of demand charge: 50% via an energy based rate (cents/kwh) applicable to the actual monthly peak and shoulder energy (kwh) consumptions at each connection point; and 50% via a demand based rate ($/kw/month) applicable to the actual monthly maximum demand (kw) at each connection point. From 1 July 2010, TransGrid modified its approach by recovering the locational costs only on the basis of a maximum monthly demand charge Prescribed TUOS Services non-locational component Rule 6A (f) requires that prices for recovering the adjusted non-locational component of prescribed TUOS services must be on a postage-stamp basis. In accordance with this provision, TransGrid s adjusted non-locational component of the prescribed transmission use of system charges is determined on the basis of contract agreed maximum demand or historical energy and is calculated annually as follows: An energy based price that is a price per unit of historical metered energy or current metered energy at a connection point expressed as c/kwh. A contract agreed maximum demand price that is a price per unit of contract agreed maximum demand at a connection point expressed as $/kw/month. The energy based price and the contract agreed maximum demand price are determined so that: A transmission customer with a load factor in relation to its connection point equal to the median load factor is indifferent between the use of the energy based price and the contract agreed maximum demand price; and The total amount to be recovered through the non-locational component of prescribed TUOS services does not exceed the allocated costs. When applying the energy based price, the prescribed TUOS non-locational component charge for a billing period is generally calculated for each connection point by multiplying the energy based price by the metered energy off-take at that connection point in the corresponding billing period two years earlier. When applying the contract agreed maximum demand price, the prescribed TUOS non-locational component charge for a billing period will be calculated for each connection point by multiplying the contract agreed maximum demand price by the contract agreed maximum demand for the connection point (prevailing during the billing period concerned and expressed in $/kw/month) and multiplying this amount by the number of months in the billing period. The energy based price or the contract agreed maximum demand price that applies for the adjusted non-locational component of prescribed TUOS services at a connection point will generally be the one which results in the lower estimated charge for that prescribed transmission service. However, if the customer has elected not to use the contract agreed maximum demand price option, or has not entered into an agreement with TransGrid which specifies the level of the contract agreed maximum demand, then the energy based price applies Excess Demand Charge For those customers who have chosen to have their TUOS non-locational and prescribed common transmission service charges set and applied on the basis of contract agreed maximum demand, TransGrid calculates an excess demand charge that will apply if the nominated demand is exceeded. The rate to be used in calculating the excess demand charge is set out in formal agreements with the customer, preferably in the relevant connection agreement, and therefore may be different for different customers. It should be noted that the Rules provide no guidance in relation to the setting of the excess demand charge. 20 TransGrid Consultation Paper: Transmission Pricing November 2013

21 4.4.6 Basis for Levying Locational TUOS Charges The locational TUOS charge (that is, the total dollars) payable at each connection point is calculated as the locational TUOS price multiplied by actual monthly maximum demand. This ensures that the total locational TUOS charges paid reflect actual use of the network. In this way, customers who reduce (or increase) their demand in response to the locational TUOS price signal see the impact of such decisions on the charges they pay. AEMO (the Victorian TNSP) has recently proposed a change to its Pricing Methodology, under which the locational TUOS charge would be based on actual demand from the most recent completed period, being year t-2. Under this proposal, customers facing demand based locational charges will know with certainty the price and quantity, and therefore the total charge, for the year ahead. AEMO has made this proposal because it would avoid the need for annual reconciliation for customers with demand based locational charges between the forecast and actual demand 19. It is understood that in Victoria, this reconciliation can lead to significant adjustments to charges over the summer quarter. From an economic point of view, AEMO s proposed charging arrangement is, arguably, not ideal because customers will not be able to affect their charges in the current year by altering their behaviour. By the same token, however, customers charges in two years time will reflect their usage of locational TUOS services today, as historic demand feeds through to the calculation of future charges Application of Side Constraints to Locational TUOS Prices Under clause 6A (f) of the Rules, prices for recovering the locational TUOS price must not change by more than 2 per cent per annum compared with the load weighted average locational TUOS price for the relevant region, subject to the particular exceptions set out below. In its 2006 review of transmission pricing, the AEMC decided to retain the pre-existing 2 per cent side constraint on any given locational price compared with the average load-weighted locational price for the relevant region(s). The AEMC explained in its draft decision that this approach would address concerns regarding the potential impact on charges if this constraint was removed 20. It its final decision, the AEMC noted that there may be cases where it is appropriate to relax the side constraint due to step changes in demand. The AEMC s final Rule allows the side constraint to be relaxed in these circumstances, providing that the transmission customer has requested a renegotiation of its connection agreement and the AER approves the TNSP s treatment of that customer. The AEMC also stated that this flexibility should allow larger price increases as well as decreases, such as where a load customer closes down part of its operations 21. The existing side constraint provisions ensure that changes in locational TUOS prices at each connection point are closely aligned with the average change, unless there is a material change in demand at that connection point. This approach may provide customers with confidence that they are not exposed to unusual outcomes from load flow changes that may affect the cost allocation using the T-PRICE software. Questions for Stakeholders Are TransGrid s existing pricing structures appropriate? What changes, if any, should be adopted in TransGrid s forthcoming Pricing Methodology proposal? What changes, if any, should be made to the existing Rules to provide better pricing outcomes for customers? For example, should arrangements be put in place to allow customers greater certainty regarding the future path of transmission prices? Would such an arrangement be appropriate given the objectives of economic efficiency and equity? Should the current side constraint on locational TUOS prices be retained, or altered in some way, and if so, how? 19 Under TransGrid s pricing methodology, any over or under recovery of prescribed revenue arising from variances between actual demand and the demand used for calculating prices, will be addressed by way of an under or over recovery adjustment when calculating prices for the following financial year. 20 AEMC, Draft National Electricity Amendment (Pricing of Prescribed Transmission Services) Rule 2006 Draft Determination, page Rule Determination for National Electricity Amendment (Pricing of Prescribed Transmission Services) Rule 2006, page TransGrid Consultation Paper: Transmission Pricing November 2013

22 4.5 Prudent Discounts The Rules provide arrangements enabling a TNSP to agree a prudent discount on the TUOS and prescribed common transmission service charges to a particular customer. The rationale for providing a prudent discount is that in the absence of such a discount the customer may inefficiently bypass the transmission network, and the remaining customers may be worse off as a result. The Rules enable the discounted amount to be recovered from other customers. As explained above, the overall effect is to leave customers no worse off compared to a situation where the prudent discount is not provided and the customer bypasses the network. Currently, TransGrid has a very small number of customers receiving prudent discounts. Question for Stakeholders What, if any, changes should be made to the existing prudent discount provisions in the Rules? 4.6 Transparency Transparency enables customers to understand how transmission prices are calculated and to manage transmission costs by responding to the pricing signals. As noted by the AEMC 22 : Transparency makes future prices more predictable, which allows long-term decision making (e.g., choice of location) by consumers in response to those anticipated prices. More broadly, transparency of regulatory arrangements also underpins confidence in and credibility of regulatory arrangements. There are two aspects of transparency that are relevant to the rule change request: (a) network prices and the methodology used to arrive at those prices should be easy to understand by consumers; and (b) the methodology used to arrive at those prices should be applied in a consistent fashion. TransGrid concurs with the AEMC s observations in relation to transparency. In particular, we recognise the importance of providing information to customers in relation to the derivation of transmission prices, and to provide customers with the means to better manage their transmission costs. Question for Stakeholders What additional information should TransGrid provide to improve the transparency of transmission prices and to better enable customers to respond to the pricing signals? 22 AEMC, National Electricity Amendment (Inter-regional transmission charging) Rule 2013, Rule Determination, 28 February 2013, page TransGrid Consultation Paper: Transmission Pricing November 2013

23 4.7 Compliance In order to monitor and maintain records of its compliance with its approved Pricing Methodology, the pricing principles for prescribed transmission services, and part J of Chapter 6A of the Rules, TransGrid: maintains the specific obligations arising from part J of the Rules in its compliance management system; maintains electronic records of the annual calculation of prescribed transmission service prices and supporting information; and periodically subjects its transmission pricing models and processes to functional audit by suitably qualified persons. Questions for Stakeholders What, if any, additional information should be provided to customers to demonstrate TransGrid s compliance with the approved Pricing Methodology? In light of the information presented in this Consultation Paper, and your own commercial experience, how might the existing transmission pricing arrangements be improved? Please indicate whether you consider that the changes can be made within the framework provided by the existing Rules, or whether a Rule change would be required. 23 TransGrid Consultation Paper: Transmission Pricing November 2013

24 5. Next Steps As already noted, TransGrid is encouraging feedback on the current transmission pricing arrangements and how they may be improved in the future. TransGrid recognises and advises that by virtue of any changes to the existing arrangements, there will be an impact to customers. The overarching test, therefore, is whether the proposed change will likely contribute to the achievement of the National Electricity Objective, which is to promote the efficient use of and investment in the transmission network for the long term interests of consumers. TransGrid also recognises that the scope of some proposals may require a change to the National Electricity Rules. TransGrid is prepared to advocate Rule changes, providing that these changes contribute to the achievement of the National Electricity Objective. Potential changes to TransGrid s current Pricing Methodology, such as the adoption of a modified CRNP methodology, for example, is likely to require significant internal work before being adopted. For these types of changes, TransGrid will examine the practicalities of implementing the proposed changes, including any transitional arrangements. TransGrid envisages the following timeframes and milestones for developing its Pricing Methodology 23 and introducing any Rule change proposals. Date Milestone 8 November 2013 TransGrid publishes the Transmission Pricing Consultation Paper. 13 November 2013 TransGrid holds workshop with interested parties to allow questions and discussions. 13 December 2013 Closing date for feedback from customers and other stakeholders. December 2013 January 2014 End of February 2014 End of May 2014 TransGrid evaluates changes proposed by customers and other stakeholders. TransGrid provides feedback to customers and other stakeholders. TransGrid develops its proposed pricing methodology. TransGrid develops Rule change proposals as required. Question for Stakeholders Do you support TransGrid s suggested approach and milestones for developing its forthcoming pricing methodology? If not, what changes would you suggest? 23 The pricing methodology will apply for the five year period commencing on 1 July TransGrid Consultation Paper: Transmission Pricing November 2013

25 6. Attachment: Reviews on the Regulation of Transmission Services and Prices The table below lists the reviews that have addressed issues relating to transmission pricing, the regulation of transmission revenues and the role of transmission in the National Electricity Market. The table also provides a brief summary of the outcomes of each review. It is noted that some of these reviews focused on issues relating to transmission charges for generators. As explained in section 1, these matters are beyond the scope of our present consultation. In addition, some of the reviews were focused on matters relating to revenue determination and revenue regulation, rather than transmission pricing. As explained in section 2.3, revenue determination and transmission pricing are separate matters. Nonetheless, for completeness the key outcomes of those reviews are summarised below. Table 1: Development of transmission pricing arrangements Date July 1999 August 2001 February 2002 Milestone Transmission and Distribution Pricing Review (NECA) Principles for transmission network pricing were outlined. Incentive mechanisms to encourage improved service provision were outlined. A framework for negotiated services with network service providers (NSPs) was developed. Review of the scope for integrating the energy market and network services: Stage 1 (NECA) The review made the following recommendations. Transmission NSPs (TNSPs) required to provide rolling 12 month programmes of planned network outages. Assessments of the market value of trade forgone because of network outages to be published. Contractual obligations were placed on TNSPs against network performance targets. Network and Distributed Resources Code changes Determination (ACCC) Improvements were made to the arrangements governing: the planning and approval of new transmission investments; and the consultation and dispute resolution processes relating to network augmentation proposals. 25 TransGrid Consultation Paper: Transmission Pricing November 2013