DRAFT
ISSUES PAPER

Applications for authorisation
Application to vary an access code

National Electricity Code
Network Pricing Code Changes

Date:  September 1999

		

		

		

Contents
GLOSSARY	ii
1. INTRODUCTION	1
2. THE NECA REVIEW AND CURRENT NETWORK PRICING 
ARRANGEMENTS	2
2.1	BACKGROUND TO THE REVIEW OF NETWORK PRICING	2
2.2	OVERVIEW OF CURRENT NETWORK PRICING ARRANGEMENTS	3
3. FRAMEWORK FOR EFFICIENT PRICING OF ELECTRICITY NETWORKS	5
3.1	PRICING TO REFLECT NETWORK CHARACTERISTICS	6
3.2	LOCATIONAL SIGNALLING THROUGH NODAL PRICING	7
3.3	CONTROL OF NETWORK MONOPOLIES’ MARKET POWER	10
3.3.1	Regulated monopoly with annual tariffs	11
3.3.2	Tradeable rights	14
3.4	EQUITY CONSIDERATIONS	15
3.5	SUMMARY	16
4. ISSUES ARISING FROM THE CODE CHANGE APPLICATION	18
4.1	TRANSMISSION NETWORK PRICING	18
4.1.1	Existing arrangements	18
4.1.2	Who should pay transmission use of system charges	19
4.1.3	How should transmission charges be levied	21
4.1.4	Summary of proposed changes to TUOS charges	22
4.2	DISTRIBUTION NETWORK PRICING	23
4.3	PRICE NEGOTIATION FRAMEWORK AND UNBUNDLING TRANSMISSION AND DISTRIBUTION CHARGES	24
4.4	SERVICE STANDARDS	26
4.5	EMBEDDED GENERATION	27
APPENDIX 1. STATUTORY TESTS FOR AUTHORISATION AND ACCESS
CODES	28

Glossary
Code	National Electricity Code
CRNP	Cost Reflective Network Pricing
DNSP	Distribution Network Service Provider
LRMC	Long Run Marginal Cost
MNSP	Market Network Service Provider
NECA	National Electricity Code Administrator
NEM	National Electricity Market
NEMMCO	National Electricity Market Management Company
NSP	Network Service Provider
RRN	Regional Reference Node
SRMC	Short Run Marginal Cost
TPA	Trade Practices Act 1974
TUOS	Transmission Use of System
TNSP	Transmission Network Service Provider

1.	Introduction
On 26 July 1999, the National Electricity Code Administrator (NECA) lodged an application to vary the National Electricity Market (NEM) access code to take account of changes arising from NECA’s review of transmission and distribution pricing.  Subsequently, on 18 August 1999, NECA amended the application to vary the access code.  At the same time, NECA applied for authorisation of the Code changes (this was effected by varying an application for authorisation of a set of Code changes that ostensibly related to arrangements for market network service providers(MNSPs)).
At this time, the Commission is also considering applications for authorisation of several other Code changes, including further jurisdictional derogations.  Details of these applications and the Commission’s decisions can be obtained from the Commission’s web site (www.accc.gov.au/electric/fs-elec.htm).
The current applications refer to a range of matters relating to investment in, and the pricing of, the transmission and distribution networks in the NEM.  These matters have been the subject of a lengthy review of transmission and distribution network pricing which the Code required NECA to undertake.  As part of its review from December 1997 to July 1999, NECA sought submissions and held a number of public forums, published issues and options papers as well as a draft report.  The review’s final report, published on 8 July 1999, outlined NECA’s in-principle position on the range of matters considered by the review.  Subsequently, on 23 July, NECA published the proposed code changes to implement the findings of the network pricing review.
The Commission acknowledges that a lengthy review has already been undertaken to develop the proposed code changes.  Nevertheless, in assessing the applications, the Commission is required to follow a public process.  This issues paper is intended to assist interested parties to participate in the Commission’s assessment process.  First, by outlining the background to the current network pricing arrangements and the rationale for NECA’s review.  Second, by setting out a framework for efficient pricing of electricity networks.  Third, by attempting to identify the main issues of this review in a way which can be understood by a broad cross‑section of the Australian community.  The appendix to the issues paper contains the statutory assessment criteria the Commission must follow in assessing the application for authorisation and the application to vary the access code.
In seeking submissions for the Commission’s assessment of the authorisation application and the proposed variation to the access code, the Commission is seeking to avoid any unnecessary duplication of effort by interested parties.  Consequently, interested parties are invited to provide to the Commission those submissions that had been submitted to the earlier NECA process.  Interested parties are also invited to amend their earlier submissions as well as lodge a new submission.  Any new submissions should be written in the context of the Commission’s statutory assessment criteria as outlined in the appendix 1 of this paper.

2.	The NECA review and current network pricing arrangements
The requirement for a review of the transmission and distribution network pricing arrangements was included in the Code at the time the initial draft was being finalised in 1996.  This section provides a summary of the rationale for including a review of the network pricing arrangements in the Code.  This section also provides a summary of the existing network pricing arrangements.
2.1	Background to the review of network pricing
The NEM was created following decisions made at the Special Premiers’ Conference in 1990. In November 1995, after a number of years of developing the wholesale market and network access arrangements, the Energy Ministers of the participating jurisdictions agreed to commence the NEM by September 1996.
With a view to facilitating the start of the NEM by that time, the Commission commenced an informal review of the Code in March 1996.  On the basis of public consultations, the Commission identified a number of concerns with the proposed market arrangements, including the then proposed arrangements for transmission pricing.  Specifically, in its Comments and issues arising paper, the Commission argued that the Code should allow the regulator sufficient flexibility to apply a range of methodologies which represent emerging best practice transmission price regulation, based on overseas and Australian experience.  In order to provide a degree of certainty about the arrangements to apply, the Commission suggested that there be a review of the options for efficient transmission pricing and regulation.
These concerns were incorporated in the October 1996 version (draft version 2.0) of the Code.  The Code required NECA to undertake a review of:
•	the pricing requirements applying to transmission networks as specified in Part C of Chapter 6 of the Code;  and
•	the appropriateness of the methodologies and regulatory principles for determining distribution network prices as set out in Part E of Chapter 6 of the Code.
As part of its formal assessment of the NEM access code, the Commission identified a number of specific deficiencies with the proposed arrangements governing the recovery of the costs of providing the transmission network.  Specifically, the Code was amended to clarify the rights of network connection applicants to by-pass existing networks and to improve the location incentives of TUOS charges by including an avoided costs test for embedded generators.  Moreover, in response to a range of other matters raised by the Commission, NECA agreed to include within the scope of its review of network pricing an examination of:
•	the locational signals resulting from the transmission and distribution pricing regimes, including the appropriate balance between cost reflective and postage stamp elements of charges and the incidence and treatment of cross subsidies;  
•	appropriate guidelines for negotiations between Distribution Network Service Providers (DNSP) and embedded generators on the pass-through of the reduction in transmission charges that arises from bringing these generators into the network;  
•	the appropriate incidence of TUOS charges, and the pros and cons of unbundling transmission and distribution use of system charges; and
•	the appropriate powers of transmission and distribution regulators in particular in relation to the development and monitoring of service charters drawn up by Transmission Network Service Providers (TNSP).
NECA commenced this review in December 1997.  The review’s final report, published on 8 July 1999, outlined NECA’s in-principle position on the range of matters considered by the review.  Subsequently, on 23 July, NECA published the proposed code changes to implement the findings of the price review.
2.2	Overview of current network pricing arrangements
The NEM has a minimalist nodal pricing system, which comprises five regional markets, each of which has a regional reference node (RRN) where the regional spot price is calculated.  Constraints and energy losses between regions are reflected in price differences between RRNs.  However, within a region, energy prices only vary as a result of energy losses between the RRN and individual connection points, not as a result of intra‑regional constraints.  Within a region, the Code allows for payments to constrained on generators and the negotiation of compensation from the TNSP to network users in the event that users are constrained off the network.
Inter-regional losses are dynamic since they are measured for each dispatch interval, whereas intra-regional losses are static since they are calculated as an average of the marginal loss factors in the previous year. All states currently have derogations in place, which give the jurisdictional regulator, rather than NEMMCO, the authority to determine intra-regional loss factors.  
Since losses increase exponentially with line flow, marginal losses will be greater than average losses if power flows increase.  By only valuing intra‑regional losses at their average level, the energy prices do not reflect the degree to which the transmission network is utilised at different times.
The current energy prices within a region therefore do not fully capture the short run marginal costs of energy transmission within a region (that is losses and constraints).  As a result, the dispatch of generation does not minimise the combined costs of generation and transmission and therefore does not send optimal signals for the efficient location of generation and load.  
However, the degree to which the current method of calculating intra-regional loss is inadequate will depend on the extent to which actual losses vary across the transmission system within each region.  Indications are that this is more of a problem in Queensland than other states in the NEM.  A consequence of the existing arrangements is that they lead to less variation in energy prices within the region, which was one of the objectives of the jurisdictions’ derogations. 
NEMMCO is currently conducting a consultation on the need to introduce time-varying intra‑regional loss factors in the NEM.  The closing date for submissions to NEMMCO’s review is 30 September 1999.  NEMMCO will also be conducting a review of regional boundaries in the NEM.
Under the current NEM arrangements, the inclusion of constraints and losses in the regional reference price leads to the accrual of inter-regional settlements residues from the difference in spot prices between RRNs.  Settlements residues also accrue from the fact that intra‑regional losses lead to a difference in energy prices between the RRN and individual connection points.  Under the current arrangements, NEMMCO conducts an auction, whereby successful bidders receive a right to a proportion of the settlements residue, with the auction proceeds being distributed to relevant TNSPs.  The remainder of the settlements residue that is not subject to the auction process is distributed according to the jurisdictions’ existing derogations.
The current arrangement for recovering the remaining costs of the transmission networks is through the application of a pricing methodology that comprises elements of postage stamping and cost reflective network pricing.  The Code currently defines a number of transmission services on which networks can levy prices, namely entry, exit, common, use of system and generator access services (see Box 1 for a summary of the existing pricing arrangements).
One purpose of the NECA review was to examine the cost recovery mechanism for these transmission services.  However, given the importance of issues such as transmission constraints and network losses in signalling the short run marginal costs of transmission, the outcomes of NEMMCO’s reviews into losses and regions will be fundamental to the establishment of a more efficient pricing regime.

Box 1:	Pricing methodology for the existing transmission network services 
Currently there are five classes of transmission network services:
1.	Entry services  provided to generators at a single connection point;
	a)	a generator’s connection service charges may be specifically allocated in a contract;
	b)	if not, a generator’s entry service charges are recovered by:
	i)	allocating amongst all the generators at a particular connection point, the revenue needed to cover the entry assets at that connection point (plus an equitable amount for assets that jointly provide entry and exit services);
	ii)	a fixed annual charge;
2.	Exit services  provided to transmission network customers at a single connection point; 
	a)	a customer’s connection service charges may be specifically allocated in a contract; 
	b)	if not, a customer’s exit service charges are recovered by
	i)	allocating amongst all the customers at a particular connection point, the revenue needed to cover the exit assets at that connection point (plus an equitable amount for assets which jointly provide exit and entry services); 
	ii)	a fixed annual charge; 
3.	Transmission use of system services  provided to either generators or customers which can be allocated on a locational basis; 
	a)	in a connection agreement, generators may consent to pay some of the TUOS costs; 
	b)	50 per cent of the TUOS service costs are allocated to customer connection points; 
	i)	the revenue requirement is generated by cost reflective network prices; 
	ii)	the variable price is determined at the discretion of the NSP but must reflect the investment conditions in the network and may include any combination of:  demand based charges; energy based charges; or fixed charge. 
	iii)	the charge may relate to either the actual (metered) use or an agreed use. 
	iv)	the demand based charge is to be calculated on a customer’s maximum demand as averaged over a metered half hour period; 
	c)	any remaining anticipated revenue shortfall is allocated to customer connection points on a postage stamp basis and recovered from customers through a variable common service charge (the annual rate is the common service cost divided by the network energy delivered); 
4.	Common Services  provided to customers which cannot be allocated on a location basis (eg services to maintain power system security); 
	a)	all of the revenue needed to provide such services is allocated to connection points and customers are charged on a postage stamp basis; 
	b)	the revenue is recovered through a variable common service charge (the annual rate is the common service cost divided by the network energy delivered); 
5.	Generator Access services  is the risk premium for generators with connection agreements that include firm access compensation arrangements where the revenue is recovered from each generator in accordance with the connection agreement. 
3.	
Framework for efficient pricing of electricity networks 
As discussed in the previous section, the current arrangements for network pricing rely on:
•	energy market prices to signal the impact of network losses and constraints;
•	recovery of TNSPs’ costs through TUOS and other charges; and
•	recovery of DNSPs’ costs in accordance with individual state based arrangements.
As distribution network prices incorporate transmission prices, they are the mechanism through which efficiency signals for the transport of electricity are conveyed to end use customers.
While a comprehensive review of network pricing would have considered each of the above three elements, the terms of reference for the NECA review only referred to the latter two elements.  Nevertheless, the Commission believes that any assessment of the proposed Code changes needs to be considered in the broader context of the “best practice” arrangements for delivering efficient network prices.  Consequently, the remainder of this section discusses:  the role of prices and the characteristics of electricity networks (section 3.1); a mechanism to deliver efficient locational signals for network usage and investment (section 3.2); and a comparison of a centralised versus a more market oriented approach to dealing with market power issues (section 3.3).
3.1	Pricing to reflect network characteristics
Prices are called upon to perform a number of roles - to encourage efficient use of and investment in the transmission and distribution networks; to recover the costs of the network service provider; and to achieve equity objectives.  
Prices have an important role in economic efficiency.  In a market, prices signal the relative cost of one service compared to another, including the cost that arises when there is scarcity.  In economic terms, this is known as "opportunity cost" - it is the value of another alternative or opportunity that must be forgone because a resource is scarce, and must be rationed.  When prices are efficient, they reflect the costs of providing a service, including the opportunity cost; when prices diverge significantly from costs, they do not provide efficient economic signals.
However, the question remains, what costs should prices reflect?  To encourage efficient behaviour, the relevant cost is the marginal cost, that is, the cost of providing an additional unit of a service.  In practice, marginal cost pricing requires careful analysis of the “margin” being referred to, all the costs caused by the provision of the marginal service, and an understanding of the time horizon that is relevant for pricing purposes.
Marginal cost can be defined in either short-run or long-run terms.  Short run marginal cost (SRMC) can be defined as the opportunity cost of an incremental change in demand, holding one factor of production constant (usually capital, which determines capacity).  Long run marginal cost (LRMC) relaxes this constraint, and addresses the opportunity cost of an incremental change in demand assuming all factors of production can be varied.  
Short-run marginal costs are the place to begin for pricing, because ideally every individual consumption decision, at every instant, should reflect the marginal cost to society at that point in time, including the cost of any forgone opportunities if the service cannot be provided, that is, the cost of congestion.  However, it is not always practical to put in place a pure short-run marginal cost pricing arrangement.  
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; and
•	the ‘opportunity cost’ of constraints on the network.
Constraints are a cost of transmission 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” (see section 3.2 for more details).  However, many electricity markets, including the NEM, reflect these costs on the basis of regions, which combine a number of connection points. 
In the long run, all costs are variable.  The existing network needs to be maintained, and new network investment may be required.  Long run costs are therefore those associated with maintaining and/or expanding the network.  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 very low.  Conversely, long run marginal cost may be very high prior to a significant expansion of capacity.
3.2	Locational signalling through nodal pricing
Nodal pricing is a method of calculating energy prices at each individual node (or busbar) on the transmission system based on the short-run marginal cost of generation at that node.  A nodal pricing system also signals the short run costs of transmission, according to location and time of day, based on the difference in energy prices between nodes.  
The NEM’s current zonal pricing methodology is akin to a very small-scale nodal pricing system, with the energy price determined at a regional reference node instead of every busbar.  Indeed, some of the concerns that have been raised regarding the implementation of a full nodal pricing system are its complexity and data intensity. 
Where there is no congestion and no physical losses on the transmission network, then there are no short run costs of transmission and the price will be the same at every node as a result of unlimited trade between nodes.  However, in reality there are physical losses of energy on transmission lines and constraints can arise.  These result in out of merit order dispatch of generation. 
According to Kirchoff’s Law, electricity will not flow directly between two points if there are several possible routes.  Rather, it will follow the path of least resistance and may therefore flow along each of the available routes.  Losses and constraints therefore depend on the injections and withdrawals of power at all points on the transmission system.
These costs need to be incorporated in the algorithm for the dispatch of generation in order to ensure that the combined cost of generation and transport is the least cost option.  If, for example, line losses were not incorporated in the dispatch algorithm, a cheaper generator may be dispatched even though it is a long way from the load centre and there are large physical losses of energy.  Including losses in the dispatch algorithm recognises that it may be a lower cost option to dispatch a more expensive generator that is located closer to the load centre.  As energy flows increase along a transmission line, it increases the amount of physical energy losses, thereby increasing the MWh charge for the energy that is delivered.  However, the price at a particular node may be less than the system marginal price if the increase in flow along that line is against the prevailing flow and has the impact of reducing total line losses.
Figure 1 shows that in order to meet 95 MWh of demand at Node 2, the generator at Node 1 needs to generate 100MWh, since 5% of the power is dissipated in line losses. The cost of these losses, and hence the short run marginal cost of transmission, is reflected in the price difference between the two nodes.  In this case, the marginal cost of generation at Node 1 is $10/ MWh and therefore the total cost of supplying the additional 100 MWh of generation is $1,000.  However, the customer at Node 2 only receives 95MWh but still needs to pay $1,000 to cover the generator’s incremental costs.  The spot price at Node 2 is therefore $10.53/ MWh ($1,000/ 95MWh).  In this case, the short run marginal cost of transmitting energy from Node 1 to Node 2 is 53c/ MWh.
Figure 1:  Impact of transmission losses on nodal energy prices

Node 2

Node 1

Generation | 100MWh | Demand | 95MWh
Price/ MWh | $10.00 | Cost/ MWh | $10.53
Revenue | $1 000 | Total cost | $1 000

It is also important to incorporate constraints and system security requirements into the dispatch algorithm so as to recognise the costs that arise from the need to dispatch a generator out of merit order.  Such network constraints can occur as a result of thermal constraints on the amount of power transferred, reactive power constraints, spinning reserve constraints and security constrained dispatch (eg to satisfy the n-1 security criterion).
Figure 2 shows that if there is a thermal transmission constraint between nodes 1 and 2, then a portion of the demand at Node 2 will need to be satisfied by the dispatch of the higher cost generator at Node 2.  The marginal cost of generation at Node 2 is therefore $30/ MWh compared to $20/MWh if there were no constraints or losses.  Again, the short run marginal cost of transmission is reflected in the difference between the energy spot prices at Node 1 and Node 2, that is $10/ MWh.
Figure 2:  Impact of constraints on nodal energy prices

Demand
100MWh
100MWh

Demand
80MWh

NODE 2

NODE 1

Transmission constraint = 50 MW

Generator A
300 MW
SRMC: $20/MWh

Generator B
300 MW
SRMC: $30/MWh

As well as delivering energy and transmission prices, a nodal pricing system can indicate whether investment in new network capacity is an economically viable alternative to the ongoing costs of congestion.  That is, investment in new capacity will only be considered viable if the future costs of physical losses and the costs of network constraints exceed the cost of augmenting the network.
Under a fully developed nodal pricing system, decisions to invest in new transmission capacity are based on the value of avoiding future losses and transmission constraints.  If nodal pricing and so SRMC pricing is introduced into and existing system, however, there are no future costs to avoid.  Thus, these sunk costs of an existing network cannot be recovered by a system of nodal pricing alone.  This is particularly so where there is spare capacity and the short-run costs of electricity transmission are limited to the value of losses, and are therefore likely to be relatively low.  However, where capacity is constrained, the short-run costs of transmission can be very high, due to the need to use more expensive generation in one area, rather than import cheaper generation from another.  At the extreme, the short-run cost of transmission will rise to VOLL (the value of lost load) if the network is congested, and if there is no local generation available. 
3.3	Control of network monopolies’ market power
Effective competition provides firms with an incentive to provide services of the type and quality demanded by customers, at the lowest cost, and ensures that profits do not exceed those necessary to sustain the provision of the service.  The threat of competition can also act as an effective constraint on the ability of firms to extract excess profits.  Economic theory demonstrates that competition leads to efficient allocation of society's scarce resources. 
The conditions required for a competitive market are unlikely to apply to the provision of electricity transmission and distribution services, which are generally accepted to be natural monopolies.  Where firms hold significant market power, they are able to raise prices in order to maximise profits.
Like other infrastructure businesses, electricity networks are characterised by a high proportion of costs that are fixed in the short term, with assets that have long lives and network investments that tend to be lumpy.  As a consequence, these network characteristics generate:
•	economies of scale  where it can be less expensive to meet demand through a single high capacity line rather than through a number of low capacity lines;  and
•	economies of scope  where it can be less expensive to supply two (or more) products together rather than separately.  Where transporting electricity to different locations is viewed as different products, an electricity network can be viewed as a multi-product firm.  It possesses economies of scope when it is less expensive to supply an additional location through an extension to an existing network rather than by supplying it through a new or duplicated network.
A key objective of the NEM has been to introduce competition and to limit the scope of the networks’ natural monopoly.  This objective has been pursued both through the structural separation of generation, transmission and distribution and through the access regime.  The access regime does this by requiring the networks to negotiate connection, subject to certain terms and conditions, with generators, consumers or other networks.  The access regime attempts to limit the ability of networks to extend their market power into those functions and services that could be supplied on a contestable basis.  In this way, the access regime attempts to limit the networks’ market power that derives from economies of scope.
Firms providing services that have significant economies of scale, a high proportion of sunk costs, and long-lived assets typically look to support their investments with long-term contracts with their customers, so as to provide reasonable assurance that their investment costs will be recovered.  
However, where there are a large number of customers, or where customers are unwilling to commit to long term contracts because they are unsure of their future requirements, it may not be feasible to underwrite new investment through long term contracts.  In the context of a regulated firm, there are two broad approaches to ensuring that new investment costs can be recovered:
i)	through a regulatory mechanism that recognises the need for a long-term commitment to the recovery of costs, in return for the business investing in long-lived assets.  Customers may then be charged regulated annual tariffs, with a limited penalty for ceasing to use the facilities;
ii)	the investment can be underwritten by the creation of property rights for use of the facility, in return for long term contributions to the investment cost.  Where the business is a monopoly, regulation will still be required to ensure an efficient level of investment.  If the property rights are tradeable, the holders have flexibility to trade these rights when they no longer want to use them.
While annual tariffs are a more common form of regulation, increasing attention is being given to the potential for tradeable property rights to underwrite the cost of providing infrastructure, to provide efficient signals for its use, and signals for future expansion requirements.
These two approaches to regulation and cost recovery are considered in the following sections.  The approach taken has important implications for other aspects of the market and regulatory framework, such as the responsibility for network planning and investment decisions.
3.3.1	Regulated monopoly with annual tariffs
A central element of the access regime is a regulatory regime to set network revenues and/or prices.  Economic regulation aims to prevent the use of market power to impose excessively high prices or poor quality of service on customers.  In doing so, it aims to ensure efficiency through:
•	providing incentives for the service provider to be efficient in its operation and maintenance of and investment in the network; and
•	ensuring that prices reflect the economic value of providing the service, and thereby providing incentive for efficient use by customers.
In addition to efficiency, there are a range of other regulatory objectives, including simplicity, transparency and equity, which regulators must have regard to.  With respect to setting the revenue cap the Commission has produced a Draft Statement of Regulatory Principles (this document is also available from the Commission’s web site).
NECA’s review, and proposed code changes, examined the process by which network’s translate the revenue cap into transmission and distribution network charges.  In doing so, NECA considered the efficiency implications of its proposals.
As discussed above, it is generally accepted that an efficient price will be one that reflects the costs of supply (including opportunity cost where supply is constrained), in particular the short run marginal cost (SRMC).  However, with electricity networks the average costs of production will tend to be declining reflecting the economies of scale.  Where this leads to spare capacity, the SRMC of supply will be low if not negligible.  
In these circumstances, the natural monopolist’s profit maximising position would be to constrain the network’s capacity in order to raise prices (and profits) well above the socially optimal level.  Equally, if the network were forced to charge prices that reflected SRMC, it would be unable to earn sufficient revenue to recover the network’s fixed or capital costs.  While this situation may reflect economically efficient principles in a static sense, it is unlikely to be efficient in a dynamic setting where the network would be expected to undertake further investment, either to meet a growing demand or to replace existing capital.
As a result, it is generally accepted that it is difficult for a natural monopolist charging a regulated annual tariff to set prices that simultaneously meet all of the economic efficiency criteria.  Nevertheless, there has been a considerable discussion in the economic and regulatory literature of a second best pricing rule;  that is, a pricing rule for a natural monopoly that is minimally distorting.  The suggested alternatives include:
•	Government subsidy  the natural monopolist charges the short run marginal cost of supply and the extent of the firms losses are recouped through a government subsidy.  While the pricing and output decisions of the natural monopolist would be efficient, inefficiencies are introduced because of the need for the government to raise tax revenue to fund the subsidies.
•	Average cost pricing  the natural monopolist sets prices equal to the average cost of supply in order to earn a normal rate of return on the funds invested.  This pricing rule is sub-optimal to the extent that prices will be above (and output below) the economically efficient levels (ie SRMC).  However, this outcome is less distortionary than the monopolist’s profit maximising pricing and output decisions.
•	Long run marginal cost pricing  the natural monopolist sets charges to reflect both variable and capital cost, where the capital costs relate not to the costs of existing capacity but to the costs of future investments.  Efficiency principles also require that the LRMC price be levied only on utilisation at the time of the system peak (ie coincident peak) and not for off peak consumption.  
•	Price discrimination  the natural monopolist can segment the market and charge different prices to consumers in each of the market segments.  This pricing rule can be efficient to the extent that the marginal unit of output will be sold at a price reflecting SRMC.  For this to be successful, the monopolist has to prevent consumers in one market segment from “reselling” to consumers in another market segment.  
•	Ramsey pricing  an example of price discrimination where customers are charged a mark-up over the SRMC price to achieve a pre-determined revenue target.  In order to minimise distortions, the extent of the mark-ups vary inversely with the price sensitivity of each customer or customer class;  that is, customers whose demands are price insensitive (ie inelastic) face the largest mark-ups over the SRMC price, and price sensitive customers face only a small (or no) mark-up.
•	Two part tariffs  consist of a usage charge and a fixed access fee that is unrelated to usage.  The usage charge can be used to recover variable costs and the access fee can be used to achieve a revenue target.  This pricing regime can be minimally distorting provided the variable charge is set equal to the SRMC price and that the access fee is not set so high that it discourages usage by consumers that would have been willing to pay the SRMC price.  To reduce the likelihood of “inefficient” consumption, the access fee can be varied between customer classes (ie price discrimination).  The concept of the two‑part tariff can be extended into multi-part tariffs (eg a number of access and usage charges) and into self-selecting tariffs where customers can choose between a high access fee and low utilisation charge or a low access fee and high utilisation charge (eg akin to car rental charges with a range of per day and per kilometre rates).
Monopolists, such as electricity transmission networks, produce a number of services, including the transport of electricity between generators and load centres at different points across the network.  In these circumstances, there will be some costs that can be directly attributed to the provision of a particular service yet there will be other (joint or common) costs that are used to produce a number of services.  The above approaches can also be used to allocate the common or joint costs across the range of network services in a minimally distorting fashion.  
However, for the multi-product firm, the monopoly pricing problem has added complexity, as the directly attributable and common costs should be allocated in a way that avoids cross-subsidies.  A subsidy free set of prices can be defined as one where the monopolist breaks even and:
•	no group of consumers pays more than its stand alone cost;  and
•	each group of consumers pays at least its incremental cost
For some electricity networks, the ratio of common costs to attributable costs can be high, as it is often not possible to attribute specific assets to particular users.  For instance, electricity may not flow across a network according to some “contract path” but will follow multiple routes along the path of least resistance.  Consequently, the subsidy free pricing rule leads to a large degree of indeterminacy as there can be any number of cost allocation methodologies that lead to subsidy free prices.  
Nevertheless, it remains important that a monopolist charge subsidy free prices where some of their services can be supplied on a competitive basis.  For example, a load centre can receive its electricity supply either from a remote generator supplying via a transmission and distribution network or from an embedded generator via a distribution network or via a direct connection.  In these circumstances, the cross subsidies may encourage inefficient behaviour if it stimulates activity that would not take place in a subsidy free environment, eg new investments, patterns of demand, entry to or exit from an industry.
The pricing regime of electricity networks is further complicated by the existence of costs or benefits that are external to the network itself (often described as externalities).  Some of these externalities impact on the cost of producing a good or service while others impact on the cost of consuming a good or service.  The operations of the network will only be efficient if these externalities are included in its production decisions and reflected in its pricing regime.
Common production externalities reflect the impact of the network on the environment.  Many of these externalities would be included in the production decisions of the networks through their compliance with State and Commonwealth environment laws and through their responsibilities with respect to Environment Impact Statements prior to any network augmentations.  
As discussed in the nodal pricing section above, the common consumption externalities reflect the increase in physical losses as additional energy flows across the networks.  These additional flows can also create network constraints which, when they are binding, will cause some low cost generation to be constrained off in the exporting region and some higher cost generation to be constrained on in the importing region.  These network losses and constraints both add to the cost of meeting the demand for electricity and largely make up the SRMC of using the network.  This can be further complicated when the pattern of generation and demand leads to loop flows on the network that can create (positive or negative) externalities.
3.3.2	Tradeable rights
An alternative approach to underwriting network investment is to allow investors to fund the investment, in return for rights to the transmission network.  This approach relies on price signals to identify the costs of congestion and losses.  These costs are revealed through price differences in wholesale energy prices at different nodes on the network.  Network users can then compare the costs they will incur in the future through losses and congestion, to the cost of new investment.  When the cost of new investment is less than the future costs of congestion and losses, network users have an incentive to sponsor augmentation.
To give users an incentive to underwrite network investments, they must be able to capture the benefits of reduced congestion and losses.  These benefits can be defined and allocated through transmission rights.  Financial transmission rights (also known as transmission congestion contracts) give the holder the financial benefit of the link as if it were uncongested, whether or not it is congested in practice.  They do this by giving the holder a right to any future difference in the pool price between the two nodes or price regions (for a certain capacity).  Where they are tradeable, property rights can ensure that a facility is used efficiently, by those who value it most highly.
Economic regulation still plays an important role where a system of tradeable rights is introduced, both in defining the framework, and in ensuring that any "market failures" are adequately addressed.  The regulator will be responsible for:
•	defining and allocating the financial rights to the link;
•	ensuring that ‘externalities’ are properly accounted for, eg, network effects; 
•	ensuring that efficient investment occurs when there are economies of scale;
•	acting as a ‘back-up’ to the market where it does not deliver efficient investment, eg, within the meshed network, or where benefits are widespread; and
•	retaining a right of veto over investments where they are not economic.
However, in this framework prices for the network are set primarily via markets, through short-run energy prices in the wholesale market, in the underwriting of new investment, and in the trading of transmission rights.
3.4	Equity considerations 
In addition to providing signals for efficient levels of consumption and production, the prices charged by the electricity utilities have often been used to achieve social objectives.  In part, these social objectives have been achieved by employing uniform pricing policies.  Such prices ignore the fact that the costs of supplying consumers across the network will vary from one location to another.  Electricity pricing has also been used to achieve state development objectives where major industrial loads have been encouraged to locate in a particular region on the basis of a significant discount on the price paid by the majority of electricity consumers.
Traditionally, the costs of uniform tariffs and the discounts to price sensitive loads has been met by the remaining electricity consumers.  For instance, prior to the major reform of the electricity industry in Victoria, the Industry Commission estimated the extent of the cross-subsidies between the major customer classes (see Table 1).
Table 1:  Estimated levels of cross-subsidy in electricity supply – Victoria:  1987‑88
Customer class | Total revenue 1987-88 | Cross-subsidy^1
| $m | % | $m
Domestic | 725.5 | -24.4 | -177.0
Community service | 13.4 | -2.7 | -0.4
Commercial & industrial | | |
Small | 464.8 | 34.1 | 158.5
Medium | 276.1 | 25.9 | 71.5
Large | 244.0 | 12.7 | 31.0
Farm | 47.6 | -120.0 | -57.1
Public lighting | 35.5 | 10.4 | 3.7
Smelters | 146.1 | 0.0 | -
Other HV supply | 210.4 | -14.2 | -29.9
Source:	Industry Commission 1991, Energy generation and distribution, report no: 11, AGPS, Canberra, Vol. II, p. 173.
Notes: 1.	A minus sign indicates that a customer class paid less than its cost of supply, while the remaining customer classes paid more than their cost of supply.
In the face of competition, it is not possible to meet social objectives by cross‑subsidising one group of customers at the expense of another group.  In a competitive market, it would be expected that the cross-subsidies would be competed away.  New entrants, not burdened with the uniform pricing requirement, would begin to supply the lower cost customers at prices reflecting their costs of supply and not including a share of the costs of the higher cost customers.  It would be expected that this process would continue until the incumbent had lost all of their low cost customers and were only supplying their high cost customers at a price that no longer included a subsidy element.
To this extent, it could be expected that some of the cross-subsidies estimated by the Industry Commission in 1991 would have been competed away with the introduction of competition into generation and retailing.  Similarly, it also could be expected that there remains some element of cross-subsidy in the monopoly transmission and distribution networks.  
There are other ways to meet social objectives other than from cross-subsidies.  However, the governments of the participating jurisdictions have not made a commitment to these alternatives or to implementing efficient prices for the transmission and distribution networks.  To this extent, therefore, there will be a trade-off between the efficiency and equity objectives for the pricing of electricity networks.  In turn, this trade-off will have an efficiency impact on the competitive sectors of the electricity industry (ie generators) and on electricity consumers;  in particular, the most price sensitive generators and consumers.
3.5	Summary
The Code incorporates elements of both of the regulated and decentralised planning approaches described above; it is, in effect, a hybrid approach.  It envisages that network service providers will be subject to a regulated revenue cap and subject to an incentive-based price control, with customers paying tariffs for use of the network.  This revenue cap incorporates the recovery of the costs of the existing network assets (which are largely "sunk", ie, have no alternative use), and arrangements for recovering the costs of future regulated network augmentation. 
However, the Code also provides for the development of market-based network investment via “entrepreneurial” interconnectors, with associated rights to transmission links.  Furthermore, the wholesale market incorporates (to some extent) short-run costs of transmission, with energy prices that vary as a result of losses and network constraints.
The hybrid nature of the current NEM arrangements raise questions such as:
•	Are the costs of past investment allocated in a way that does not distort incentives for future use of and investment in the network?
•	Are the short-run costs of transmission adequately reflected in the current wholesale arrangements, or is there potential for more accurate reflection of losses and constraints (for example through nodal pricing, tradeable congestion contracts and more accurate measurement and pricing of network losses)?
•	To what extent are there "market failures" which mean that reliance on market incentives alone may result in inefficient network pricing and investment?  Can these be addressed by improvements in the market design, or is there a continuing need for some form of centralised decision-making and regulation? 
•	Where the costs of transmission are signalled both in the wholesale market, and in network charges, is there potential for "over-signalling" the costs imposed by different network users?  If so, how can this be avoided?
Given the scope of its terms of reference, the NECA review and Code change proposals have focused mainly on the question of the structure and incidence of regulated network tariffs once the network’s allowed revenue has been determined by the regulator.
The discussion in this section of the paper suggests that consideration should also be given to the wider question of whether the proposed changes are consistent with the evolution of a more efficient, competitive and decentralised national electricity market.
It also suggests two general criteria against which proposed changes to the Code should be assessed in addressing this broader question:
First, have the proposed network pricing arrangements been designed to ensure that the combination of pricing signals provided by the wholesale market (ie losses and constraints), together with those provided by regulated network tariffs, result in efficient signals for the use of and investment in the network.
Second, has adequate consideration been given to the role which market-based prices and tradeable property rights should play in the future network pricing arrangements in the NEM and what should be the continuing role of centralised decision-making and tariff regulation in that context.

4.	Issues arising from the code change application
This section of the issues paper attempts to identify a number of key issues that interested parties may choose to respond to in preparing submissions to the Commission’s assessment of the proposed Code changes.  Interested parties should not feel constrained to addressing only those issues raised in this paper.  Rather, interested parties should feel free to raise any issue relevant to the Commission’s assessment of these proposed Code changes.
In raising issues, the Commission has drawn on the Commission’s statutory assessment criteria (appendix 1) and on the framework for efficient network pricing (section 3).  To assist interested parties, the Commission has attempted to summarise the existing arrangements (section 2) and the main findings of the NECA review.  The Commission has also attempted to summarise the proposed Code changes.
This section commences with a discussion of the main focus of the NECA review of transmission and distribution pricing review, namely the pricing arrangements for transmission networks (4.1).  This section then goes on to discuss distribution network pricing (4.2), negotiated prices and unbundling (4.3), service standards (4.4) and embedded generation (4.5).
4.1	Transmission network pricing
4.1.1	Existing arrangements
The Code currently defines a number of transmission services on which networks can levy prices, namely: entry, exit, common, use of system and generator access services (see Box 1 for a summary of the existing pricing arrangements).  
The pricing arrangements for entry, exit and common services largely remain unchanged by the NECA review.  On the basis of the proposed Code changes, generator access services would be removed as one of the classes of transmission services that make up the network’s aggregate annual revenue requirement (ie cl. 6.3.1(a)(5) of the Code is deleted).  Nevertheless, it remains as a service that a network can negotiate to provide to a generator or a MNSP (cl. 6.4.5).  Provision of the service is on the basis of the network’s reasonably incurred costs in order to establish compensation arrangements for constraining-off or constraining-on other generators (cl. 5.5(f)(4)-(6)).  This service is in addition to the other services that a generator or MNSP can negotiate with a network but which form part of the network’s aggregate annual revenue requirement. 
Issues for the Commission
•	Are the proposed Code changes sufficient to encourage networks to negotiate and provide generator access services?
•	Is there sufficient clarity to distinguish between the unregulated generator access services and the regulated generator negotiated use of system service (and any associated assets and revenues)?

The main changes to network pricing relate to the Transmission Use of System (TUOS) charges.  These changes fall into two categories, namely:  who should pay the charges and how the costs are allocated amongst the network users.
4.1.2	Who should pay transmission use of system charges
Currently the Code levies all of the TUOS charges onto customers (load), whether it is a distribution network or a major industrial load.  This arrangement has been criticised on the basis the network pricing regime provides generators with little incentive to locate close to load or to take into account the cost of the network used to transport their output to the major load centres.
The NECA review recognised that there is a mismatch between those who benefit and those who pay and that this leads to inefficient investment and inappropriate locational decisions.  In addressing this issue, the Code changes propose differing responses to paying for the existing network and to paying for any new network investment (ie investments beyond 1 July 2000).
Existing network
The NECA review concluded that, internationally, there is no consistent treatment of the recovery of the (sunk) costs of the existing networks.  The review also concluded that marginal cost pricing is consistent with maintaining the existing locational signals through loss factors and constraints.  Consequently, NECA claimed that the generators already indirectly contribute to the cost of the existing network through the settlements surplus.
On this basis, the review concluded that the existing arrangements for recovering the sunk network costs are sound and that there would be no demonstrable material net benefit from change.
Issues for the Commission
Economic efficiency criteria argue that the sunk costs of an existing network should be recovered in a way that does not impact on current and future behaviour.  However, in practice, it is unlikely that this objective can be achieved.  Consequently, economic efficiency criteria require that sunk costs be recovered in a minimally distorting fashion in line with the principles discussed in section 3 above.
NECA’s proposed framework for recovering the costs of the existing network consists of allocating these costs to network users and allowing price sensitive customers to negotiate discounts.
•	Do interested parties believe that recovering the costs of the existing network from network customers minimises the distortions from recovering sunk costs?  
•	Would the recovery of a proportion of the sunk costs from generators be less distortionary than the framework proposed in the NECA review?
•	Could the framework for recovering sunk network costs from customers also be applied to generators?  That is, allocate a proportion of existing network costs to generators and allow individual, price sensitive generators, to negotiate discounts.
New investment
The NECA review argued that, when considering new investments, network planners are required to take into account the needs of generators (eg reduced losses and constraints) and of demand side (eg improved system reliability and security).  NECA also indicated its preference that future network investments be undertaken on a non-regulated, market basis and that regulated outcomes should mirror the outcomes of a competitive market.
Reflecting these views the review concluded, and the Code changes propose, that in future all the beneficiaries of new investment in the transmission network should contribute to that investment in proportion to their estimated share of the benefits.  NECA argued that there should be scope for the beneficiaries of the investments to agree to the appropriate sharing of the costs of new investments.  
On this basis, the Code changes propose a framework where, as part of the investment assessment process for large investments (larger than $10 million), the networks would be required to assess and consult on the relative benefits to generators and other network customers.  In the event of a dispute, the parties can seek recourse to the Code dispute resolution procedures.  For smaller investments, the allocation of new investment costs would be determined at the time of the five yearly revenue cap determination.
Issues for the Commission
•	Do interested parties believe that NECA’s proposals introduce more “market like” disciplines into network’s investment planning processes?
•	Are NECA’s proposals likely to be consistent with the future directions of network pricing in the NEM (such as nodal pricing and transmission congestion contracts which are the subject of a new review by NECA)?
•	Are NECA’s proposals sufficient to get market participants to reveal the extent of the benefits they will receive from a new network investment?
•	Alternatively, are the proposed new network investment arrangements likely to illicit behaviour where market participants will act in a strategic manner by denying they receive benefits from a new investment in the anticipation that the investment will go ahead and be paid for by other network users?
•	Will regulatory responsibilities be fragmented if the code’s dispute resolution procedures are used to arbitrate disputes between networks and connected users?  If so, do interested parties believe the ACCC’s regulatory powers should be extended to allow it to arbitrate such disputes?
Interested parties might also like to comment on a number of aspects of the administrative simplicity of the NECA proposals.  For instance, an ACCC staff paper has proposed a revised augmentation test criterion where networks will need to demonstrate that new network investments generate net public benefits over and above that which would be delivered by committed, anticipated or modelled projects.  All comparisons would be made on the basis of efficient costs, not pool price outcomes, in order to avoid any market power concerns.  Pool modelling would be used to identify the longer term alternatives (ie the modelled projects) on the basis of projected trends in demand, generation and pool prices.  In addition, NECA have proposed extending the use of pool modelling in order to determine the relative benefits that individual generators and customers receive from a new investment in the network.  Network users would contribute to the costs of the new investment in line with their anticipated benefits.
Interested parties might like to comment on the practicality and transparency of such a process, particularly as compared with the development of full nodal pricing which is sometimes criticised on similar grounds.
Interested parties might also like to comment on the likely stability over time of the estimated benefits of a new investment.  For instance, circumstances could arise where early in the life of a new investment customers receive system security benefits.  However, that same investment could also provide additional power transfer capability that might not be reflected as a benefit to generators until later in the life of that investment.  Alternatively, it could be anticipated that benefits, which are identified at a particular point in time, might not always accrue to the same individual.  For instance, while a number of generators may benefit from a new network investment, this benefit could be transferred to customers as competition between the generators lead to a reduction in the pool prices.
4.1.3	How should transmission use of system charges be levied
TUOS charges are currently allocated partly using the cost reflective network pricing (CRNP) methodology and partly on a postage stamp basis.  The review concluded that this approach is not theoretically robust and that marginal cost pricing principles require prices to signal new investment costs.  In addition, the review concluded that the CRNP methodology should be revised so:  prices reflect spare capacity;  costs of system wide reliability and security should not be allocated to individual customer groups;  prices should minimise bypass;  and that the merits of price stability should be taken into account.
On this basis, the review proposes Code changes so that the networks establish a price range for each connection point which reflects capacity utilisation or, in other words, the longer term investment conditions at each connection point (see section 4.1.4 for details).  The transmission networks would chose the price from within this range after the ACCC, as the regulator of transmission network revenues, has determined that the price range was developed consistently with the Code principles.  The balance of the networks’ revenue requirement would be recovered through a fixed annual charge recovered via an energy related price.
Issues for the Commission
•	Do interested parties believe that a move to long run marginal cost (or utilisation adjusted) pricing represents a significant improvement in transmission pricing?
•	Do interested parties believe that the proposed pricing arrangements will ensure that network customers face charges that accurately reflect the needs for new investment at each connection point?
•	By using both short run (reflecting losses and constraints) and long run pricing methodologies, will there be over signalling of new investment at constrained parts of the network?
•	Do the proposed Code changes provide sufficient guidance to require the networks to adopt efficient prices from within the cost ranges?
4.1.4	Summary of proposed changes to TUOS charges
On the basis of the findings of the transmission and distribution pricing review, NECA have proposed replacing the existing TUOS charging arrangements (see Box 1 above) with a new set of arrangements which can be summarised as:
	a)	Generator use of system service costs:
i)	negotiated use of system service costs:
•	the generator may agree to pay for a proportion of the costs for augmentations of, and extensions to, the network (this service and revenue is distinct from a generator access service);
•	these costs can be recovered through a variable price that may include a combination of a demand, energy and/or fixed charge;
ii)	new transmission network investment
•	large investments
•	as part of the investment appraisal process, the networks are to estimate generator benefits (first by class and then individually), including generators in other regions; 
•	the relative benefits received by generators determine the proportion of capital costs they will pay; 
•	networks are to recover the capital and operating costs (consistent with the regulator’s determination) from the generators and the remainder from other connected networks; 
•	small investments
•	as part of their planning processes for new investments, the network’s must determine the ratio of benefits to generators, distributors and other transmission networks on a class basis;
•	based on this ratio of benefits, the networks can recover the investment costs from the generators in that network’s region; 
•	the charges are allocated to individual generators on a pro-rata capacity basis; 
	b)	Customer use of system service costs
•	usage component
•	for non-interconnector connection points, networks allocate to each point a cost that reflects likely future usage from within a range bounded by:
•	the cost reflective network pricing methodology (CRNP) with the cost of each transmission element represented as 50 per cent of its full cost;
•	a modified CRNP approach where the NSP scales the cost of each transmission element to reflect its utilisation and therefore, indirectly, the future costs of augmentation;  and
•	a direct assessment of the long run marginal costs determined from the transmission networks’ future investment plans and the anticipated load growth and generation development
•	this cost is to be recovered via a variable charge (may include a combination of a demand, energy and/or fixed charge) but subject to a cap of 2% per annum on any increase over the regional average; 
•	for an unregulated interconnector this usage component (plus any negotiated, common service, entry or exit charge) will be recovered by a fixed charge; 
•	for a regulated interconnector this usage component (plus a common service charge) will be recovered by a fixed charge, but not prior to NECA review by 1/1/2001; 
•	general cost component
•	is the residual charge calculated as the network’s annual aggregate revenue requirement: 
	less	generator TUOS
	less	customer usage TUOS
	less	common service 
	less 	settlements residue
	less	financial transfer from	plus	financial transfers to
		other TNSPs		other TNSPs
	less	excess revenue from 	plus	revenue shortfall from
		previous period due to		previous period due to
		forecast error		forecast error
	less	negotiated use of system	plus	revenue shortfall due
		charges from market NSPs		to 2% cap on customer
				TUOS charge
			plus	payments to market
				NSPs and generators 
				for network savings
•	this residual amount is allocated to customer (not market NSP) connection points on a postage stamp basis and recovered through a fixed charge; 
Issues for the Commission
•	Do interested parties believe that the proposed Code changes reflect the findings of the NECA review?
4.2	Distribution network pricing
The Code also provides scope for jurisdictional regulators to determine principles for the allocation of TUOS charges, determined at the level of each distribution business, onto final customers.  While the NECA review predominantly focused on transmission pricing issues, the Code also requires NECA to examine the appropriateness of the methodologies and regulatory principles governing the setting of distribution prices.  This review of the distribution pricing arrangements was conducted in the context that most States have currently derogated away from the Code’s distribution pricing principles and that the Code provides scope for the jurisdictional regulators to formulate national guidelines for distribution pricing.
In examining distribution pricing arrangements, the NECA review focused on unbundling TUOS and DUOS charges, the pass through of TUOS savings associated with embedded generation and the negotiation arrangements for the different levels of service.  The review also recommended that there be a substantive peak demand based element to distribution networks’ prices across the NEM.  However, NECA left the details of distribution pricing arrangements and the basis for allocating TUOS charges to final customers to the jurisdictional regulators but encouraged a coordinated approach through the regulators’ forum.
Issues for the Commission
•	To what extent is a uniform approach to the development of principles for distribution network pricing desirable and should jurisdictional regulators develop, as a matter of some urgency, national guidelines for distribution network pricing?
•	Does the flexibility available to jurisdictional regulators in determining how distribution network service providers pass on TUOS charges to final customers weaken the applicability of the principles emerging from the NECA review?
•	Other than NECA’s proposals for a sizeable peak demand charge, what issues should be included in any review of distribution network pricing principles?
4.3	Price negotiation framework and unbundling transmission and distribution charges
Prices determined in accordance with the Code principles (see Box 1 above) are maximum prices.  Customers have the ability, but not the right, to negotiate a discount on these maximum network charges.  Consumers also have an unrestricted right to bypass the network.  The NECA review confirmed this right on the basis that it provides a competitive spur to the networks.
However, as it currently stands, there is no scope for negotiated price reductions to be recovered from other customers.  This brings into question the likelihood that networks will not negotiate price reductions.  In turn, this raises the prospect that consumers will bypass the network on the basis they have been allocated costs that are above their stand-alone costs.  
The NECA Code changes seek to remedy this situation by allowing a network to negotiate discounts with customers and to recover from other customers (via the fixed cost component of the TUOS charge) the extent of the negotiated discount, provided:
•	the network complies with any relevant requirements of the ACCC;
•	the negotiated price remains within the cost range (see 4.1.4 above);
•	the ACCC agrees that the network’s calculations of the customer usage and fixed cost TUOS prices are consistent with code principles;
The Code also currently allows the network to negotiate with its customers to provide a level of service above the minimum (schedule 5.1).  The charge for the incremental cost in providing the higher level of service is determined by agreement between the two parties.  The NECA Code changes seek to extend this principle by requiring the network to develop a negotiating framework that specifies that:
•	the network and its customer must negotiate in good faith;
•	the network must provide any commercial information as reasonably required by the customer;
•	the network charges reflect reasonable costs of providing the negotiated service;
•	the negotiations are to be conducted within a reasonable period;
•	any disputes be handled in accordance with existing code requirements;
•	the outcome of the negotiations be published;  and
•	the customer pay the reasonable expenses incurred by the network in the course of the negotiations.
The network’s negotiating framework must be approved by the ACCC and comply with any conditions imposed by the ACCC.
Issues for the Commission
•	Are the proposed Code principles and regulatory arrangements sufficient to guide the negotiation processes, in particular where one party (ie the network) is a monopolist and likely to have an information advantage over customers?
•	Is it reasonable to allow some users to negotiate discounts but to require other users, presumably with less negotiating power, to bear the cost of the discounts?
•	Is it reasonable for negotiations on higher service standards to be subject to a network’s negotiation framework yet negotiations on price discounts are not?
•	What sort of information should be publicly released on the outcome of the negotiations, in particular if the outcome is that some customers pay a greater share of someone else’s network charges?
•	Is this negotiating framework sufficient to ensure that networks are limited in their ability to cross-subsidise some customers at the expense of others?
•	Should networks have the ability to negotiate lower service standards than those specified in the Code, in particular in lightly utilised parts of the network where providing N-1 may not provide a net public benefit but where investments proceed on the basis that they are “cost effective”?
Under the current arrangements, the distribution charges bundle together the cost of both the transmission and distribution networks.  A number of network users complained that faced with a single network charge, it is difficult for them to assess the benefits of bypassing the distribution network by connecting directly to the transmission network.
The review concluded that maximum information about the composition and structure of network charges would lead to greater transparency and improved decisions.  On this basis the review proposes code changes:  to entitle major customers to unbundled transmission and distribution charging information on request;  and to require distribution networks to publish annually unbundled information on a customer class basis. 
Issues for the Commission
•	Do the proposed Code changes meet customer expectations on the type and level of disaggregated information on network costs and prices?
•	Are the time frames reasonable in which requested information must be provided?
•	Is it reasonable that the proposed Code changes have been inserted into a part of the Code which has been derogated by all of the participating jurisdictions and, therefore, will not come into effect in the immediate future?
4.4	Service standards
In determining a revenue cap for the transmission networks, the Code requires the Commission to take into account the standards (mainly quality of supply standards) as specified and any standards as determined between the transmission network service provider and its customers.  However, as part of its decision on accepting the access code, the Commission noted that these arrangements may not be comprehensive.  This can be important as revenue cap regulation not only provides the transmission network with an incentive to lower service standards to reduce costs and increase profits.
In examining this issue, the NECA review concluded that service standards should be set for tariffed services provided by all networks from 1 July 2001.  Subsequently, the networks would propose service standards and the regulators would determine service standards as part of the regulatory review process.  The review also concluded that:  the networks should publish annual statistics on operational performance;  and the regulators forum should consider commissioning a benchmarking study.
The review also concluded that there should be a defined process for negotiating terms and conditions for the provision of contracted services.  These negotiations should be based on a number of principles, including:  networks responding within determined timeframe;  access to information;  publication of outcomes;  and assessing impacts on third parties.  Any unresolved issues could be resolved via the Code’s alternative dispute resolution arrangements with a right of appeal to the relevant regulator.
In implementing the NECA review proposals, cl 6.5.7(2) has been inserted into the code and requires transmission NSPs to publish:
the service standards to which it will adhere for the services to which those transmission service prices relate, which service standards must include, and not be inconsistent with, any service standards imposed on the Transmission Network Service Provider and/or Transmission Service Owner (as appropriate) by any regulatory regime administered by the ACCC.
A similar requirement (cl 6.14.5) has been imposed on distribution networks.

Issues for the Commission
•	Do the proposed Code changes fully implement the findings of the NECA transmission and distribution pricing review?
•	Do the Code changes impose sufficient obligations on the networks to establish clear and measurable service standards in advance of the determination of their revenue cap?
•	Has an appropriate balance been achieved between the responsibilities of the networks and independent parties (eg technical panels or regulators) in establishing network service standards?
•	Are the responsibilities and powers of regulators been clearly defined?
4.5	Embedded generation 
With a view to introducing locational signals to embedded generators, the review concluded that where a generator connects to a distribution network, and this reduces the TUOS charges levied on the network, the full reduction in those charges should be passed through to the embedded generator.  Provision of standby services to the embedded generator would be treated as a contracted service, where the terms and conditions of supply are to be negotiated.
In order to implement these proposals, the requirement (cl. 5.5(f)(3)) for an NSP and an embedded generator to negotiate the pass through of TUOS savings has been deleted from the code.  This requirement to negotiate the pass through of TUOS savings has been replaced by a requirement, in Part E of Chapter 6 of the Code, for a distribution network to automatically pass through any TUOS savings to an embedded generator.  These payments are to be calculated as the difference between the actual TUOS charges and the TUOS charges had the embedded generator not been connected to the distribution network.  Any such payments to the embedded generator would be included in the distribution network’s revenue and/or price cap.
Issues for the Commission
•	In the absence of generators contributing to the costs of the existing (sunk) networks, does the proposed arrangements establish a competitively neutral environment for embedded generation?
•	Is it reasonable that the existing requirement has been deleted from Chapter 5 of the Code and replaced by proposed Code changes that are to be inserted into a part of the Code which has been derogated by all of the participating jurisdictions and, therefore, will not come into effect in the immediate future?

Appendix 1
Statutory tests for authorisation and access codes
The Code is a single document that sets out arrangements governing the operation of the wholesale electricity market and an access regime to the wires network.  Authorisation of the Code provides the applicants with immunity from court action for specified market arrangements or conduct that would otherwise breach Part IV of the Trade Practices Act 1974 (TPA).  The changes relate to network pricing which is a central element of the access code which establishes a single access regime across the transmission networks in the national grid and across the distribution networks in each of the participating states and territory.
While many of the access and authorisation issues are closely related, the Commission is required to assess the authorisation and access code applications against separate criteria.  The remainder of this section outlines the authorisation and access code decision criteria.
A1.1	The authorisation test
Authorisation is granted in order to provide immunity from court action by the Commission or any other party for specified conduct or arrangements that might otherwise contravene s. 45 and/or s. 47 of the TPA.
Section 45 of the TPA prohibits the making of, or giving effect to, contracts, arrangements or understandings containing provisions which:
•	have the purpose or effect (or likely effect) of substantially lessening competition in a market;
•	are exclusionary; or
•	have the purpose, effect or likely effect of fixing, controlling or maintaining prices.
Section 47 prohibits certain exclusive dealing practices between suppliers and acquirers.  Generally this involves either the supply or acquisition of goods or services on terms or conditions that substantially lessen competition or involve third line forcing.  Third line forcing involves the supply of goods or services on condition that the purchaser acquire goods or services from a particular third party.
However, if an authorisation is granted under:
•	sub-s. 88(1), an action for breach of s. 45 cannot be brought against the parties referred to in the application for authorisation or, if the authorisation so provides, persons who become parties to the contract, arrangement or understanding; or
•	sub-s. 88(8), an action for breach of s. 47 cannot be brought against the party who applied for the authorisation.
However, the Commission must not authorise:
•	matters which may contravene s. 45 (excluding exclusionary provisions) or s. 47 (excluding third line forcing) unless it is satisfied in all the circumstances that:
•	the provisions or conduct would result (or be likely to result) in a benefit to the public; and
•	that benefit would outweigh the detriment to the public constituted by any lessening of competition that would result (or be likely to result) from the proposed contract, arrangement, understanding or conduct (sub-s. 90(6)); and
•	exclusionary provisions which may contravene s. 45 or third line forcing under s. 47 unless it is satisfied in all the circumstances that the proposed provision or conduct would result (or be likely to result) in such a benefit to the public that the proposed contract, arrangement, understanding or conduct should be allowed (sub-s. 90(8)).
In deciding whether it should grant authorisation, the Commission must be satisfied that, in all the circumstances, the proposed conduct or arrangements:
•	are likely to result in a benefit to the public which outweighs the potential detriment from any lessening of competition that would result if the proposed conduct or arrangements were made, or engage in; or
•	are likely to result in such a benefit to the public that the proposed conduct or arrangements should be allowed to take place or be arrived at,
as the case may be.
The Commission may grant authorisation subject to conditions as a means of ensuring that these tests are met.
A1.2	The access code test
Section 44zzaa(6) of the TPA states that:
The industry body may withdraw or vary the code at any time, but only with the consent of the Commission.
Section 44zzaa of the TPA does not stipulate what statutory test the Commission is to apply, nor what public consultation procedures the Commission is to follow, to applications to withdraw or vary an already accepted access code.  However normal administrative law principles would apply.  In this context it is relevant that in assessing whether to accept an access code, the Commission is required to follow a public process, by publishing the code and inviting submissions, and to have regard to:
a)	the legitimate business interests of providers who might give undertakings in accordance with the code;
b)	the public interest, including the public interest in having competition in markets (whether or not in Australia);
c)	the interests of persons who might want access to the services covered by the code;
d)	whether the service is already the subject of an access regime;
e)	matters specified in regulations, in particular:
i)	government legislation and policies relating to ecologically sustainable development;
ii)	social welfare and equity considerations, including community service obligations;
iii)	government legislation and policies relating to matters such as occupational health and safety, industrial relations and access and equity;
iv)	economic and regional development, including employment and investment growth;
v)	the interests of consumers generally or of a class of consumers;
vi)	the competitiveness of Australian businesses;
vii)	the efficient allocation of resources; and
f)	any other matters the Commission thinks are relevant.