The National Electricity Market Code provides a valuable starting point for transmission pricing.
However, experience with the operation of similar arrangements in NSW and in other States has revealed the need for numerous changes as outlined in this submission.
The NECA Transmission Pricing Review Terms of Reference and Issues Paper have focussed on the transmission price setting process (Part C of Chapter 6). They take as given the pricing principles set out in the Code. There are, however, broader issues that must be addressed if many of the concerns about transmission pricing are to be resolved.
This submission examines the broader issues while at the same time addressing the specific matters raised by the NECA Terms of Reference and Issues Paper. The emphasis is on whether the Code requires changes and, if so, in what way. The key points of this submission are summarised below under the following headings:
1. Code Pricing Principles
2. Revenue Setting Principles
3. The Adequacy of Published Prices
4. Negotiated Pricing Arrangements
5. Related Matters:

Interconnector Pricing

State vs National Regulation

Period Between Regulatory Reviews

Embedded Generation
Furthermore, this submission assumes that transmission businesses will continue to facilitate a regulated open access regime and will not take exposure to pool price risk. Should the NECA review find that this is not appropriate the opportunity should be provided to revisit transmission pricing in the broader context of overall market redesign.
Under the National Electricity Market framework published transmission use of system charges will not signal marginal costs with precision. Concern has been raised that:

This will result in economically inefficient outcomes.

Resulting significant price differences between locations cannot be justified on the basis of economic efficiency.
This situation comes about because economic efficiency is just one of many, sometimes conflicting, transmission pricing principles set out in Section 6.2.2 of the national electricity market code. Furthermore, it has long been recognised that marginal cost pricing is not commercially sustainable for an infrastructure owner where marginal costs are below average costs. This situation is not unusual in infrastructure provision and applies to electricity transmission networks.
For this Review to be effective NECA needs to explicitly prioritise the various pricing principles.
To ensure the appropriate development of transmission networks, revenue adequacy for transmission owners ought to be clearly established as a pricing constraint rather than a
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principle. If there is a trade off to be made between the remaining pricing principles within the
Code it is between equity and economic efficiency.
NECA review findings must address the process for setting revenue caps. This is a requirement of Section 6.1.6 (b) of the Code. In particular: a) The parameters for setting transmission revenue caps need to be more specifically prescribed within the Code. b) The interaction between negotiated pricing outcomes and transmission owner revenue caps needs to be specified in a way that provides adequate incentives for transmission businesses to negotiate economically efficient outcomes. This should address:

Bypass

Stand-by

Connection of large customers and generators.
Most importantly we ask that NECA addresses the inadequacies of the framework for economic regulation of transmission within the Code. This includes the current arrangement where the
ACCC effectively has the power of veto over its own powers and responsibilities as an economic regulator.
Changes to the Code are required to: a) Provide a clear mechanism for managing annual mismatches between transmission revenue caps and the revenue recovered via transmission charges. b) Enable flexibility in setting the ratio of shared transmission network revenue recovered via postage stamping to that recovered via cost reflective network pricing. The appropriateness of the current 50/50 split varies from region to region depending on the age of networks, network topology, and the ratio of written down asset values to optimised replacement costs. c) Ensure that the stranding risk presented to transmission networks by existing large generators and large direct connect customers can be appropriately managed. d) Explicitly enable different rates of return and depreciation rates to be applied to the pricing of connection assets than those applied to other asset classes.
Changes to the level of shared network charges imposed on generators need to be carefully considered given the significant relative impact of marginal loss factors on the costs of remote generation. In addition, the Code already provides for the levying of marginal transmission costs on new generators.
There is a role for negotiated transmission charges. This is needed to minimise uneconomic outcomes that would result from inappropriate published prices and to enable appropriate pricing of differential service levels.
However, considerable amendment is required to the Code to properly accommodate negotiated network service charges. These include: a) Clarifying the relationship between negotiated prices and transmission owner revenue caps.
This must be resolved if transmission owners are to be able to negotiate sensibly.
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b) Establishing a clear and comprehensive framework for negotiation including the circumstances under which there can be departures from published prices. c) Providing scope for negotiated prices above published prices where marginal costs and transmission owner stranding risks are abnormally high. d) Clarifying that, as part of negotiated generator access arrangements, transmission businesses are not compelled to take pool price exposure unless formally agreed to by the transmission owner. e) Clarifying that generator access risk premiums are not part of the transmission owner revenue cap. f) Clarifying that generators are not entitled to “firm” access compensation unless it is explicitly incorporated into a connection agreement.
Given the importance of network interconnector capacity between regions, and differences between interconnectors and other transmission assets, a separate comprehensive review of interconnector pricing is warranted. NECA is asked to facilitate such a review with the objective of ensuring that economic interconnectors proceed, and that there is a genuine prospect of appropriate commercial returns to the providers of interconnector capacity.
Transmission assets are a key part of the national wholesale electricity market. To ensure regulatory consistency, to reduce the costs of regulation, to reduce the risk of sub-optimal network development, and to minimise the risk of regulator shopping in the wholesale market: a) All assets that perform a transmission function ought to be regulated nationally. b) The definition of transmission ought to be extended to include any network asset connected to a schedulable generator.
a) Transmission owners ought to be able to initiate a regulatory review where 5 years have elapsed since the most recent past review. b) Long term connection contracts that contain negotiated transmission pricing arrangements extending beyond the 5 year regulatory review period ought to be permitted within the Code and recognised by the regulatory regime.
It has been proposed that, where the connection of an embedded generator results in reduced transmission costs, the savings are passed through to the generator owner by the transmission owner. This includes the net present worth of deferred transmission capital expenditure.
Should this requirement be codified it ought to be qualified as follows: a) Any process to pass through transmission benefits is matched by an equivalent process to pass back any costs imposed by the embedded generator.
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b) The impacts of payments on revenue caps are clearly defined. c) Given the uncertain nature of future capital expenditure beyond a few years into the future, the capital deferment savings passed through to a generator owner ought to be limited to deferrals of capital expenditure within the current regulatory review period. d) These arrangements are properly quarantined from other types of load reductions in that load reductions are normally treated as the reverse of load increases and addressed through the published price regime. e) There is a mechanism to ensure that payments only occur when the overall economics of the project are justified ie. this form of network bypass is treated on the same basis as other forms of network bypass and is only permitted where it is demonstrably economic. f) The project proponent has responsibility for persuading the regulator that the project is economic having proper regard for any associated network asset stranding. g) The sequence of connection of embedded generators is managed carefully in that where multiple generators are seeking connection the first generator connected can have quite a different impact to subsequent generators. h) The regulator can arbitrate in the event of disputes and the criteria for arbitration are clearly defined.
In addition, it is essential that there is proper ring fencing of distribution network businesses from their embedded generator businesses.
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