Review of Australian transmission pricing

A report for the Australian Competition and Consumer Commission

London Economics
Review of Australian transmission pricing

A report for the Australian Competition and Consumer Commission

London Economics 
Executive summary
1.	Introduction	1
1.1	Terms of reference	1
1.2	The role of prices	1
1.3	About this report	2
2.	Economics of transmission networks	4
2.1	Kirchoff’s Law	4
2.2	Short term costs of transmission	6
2.3	Longer term costs of transmission	9
2.4	Summary	13
3.	The Australian HV network	14
3.1	The South-East Australian network	14
3.2	Future infrastructure developments	28
3.3	Summary	34
4.	Objectives of transmission pricing	36
4.1	Efficiency objectives	37
4.2	Cost recovery	46
4.3	Other objectives	55
4.4	Summary	57

5.	Short run charging for transmission in the NEM	60
5.1	Regional structure of the NEM	60
5.2	Price determination at nodes	61
5.3	Settlement residues	67
5.4	Rights of access	70
5.5	Summary	78
6.	Long run charging for transmission in the NEM	80
6.1	Code principles for fixed cost recovery	81
6.2	Review of cost recovery provisions	85
6.3	Transmission investment in the NEM	101
7.	International experience	111
7.1	Short run costs	112
7.2	Cost recovery	117
7.3	Investment	121
7.4	Summary	128
8.	Summary and recommendations	129
8.1	Objectives and an ‘ideal’ pricing system	129
8.2	Short term productive efficiency	131
8.3	Cost recovery	133
8.4	Investment efficiency	138

Figure 2‑1: Loop flow example	5
Figure 2‑2: Transmission losses	6
Figure 2‑3: Implications of constraints for least cost dispatch	8
Figure 2‑4: Cost of thermal capacity	10
Figure 2‑5: Cost of reliable capacity	11
Figure 3‑1: Regional interconnected structure of the NEM	16
Figure 3‑2: Comparison of network assets and costs	18
Figure 3‑3: Estimated hours of constraint for typical and atypical bidding	20
Figure 3‑4: 5-minute dispatch intervals with binding constraints	20
Figure 3‑5: Static intra-regional loss factors – New South Wales	22
Figure 3‑6: Static intra-regional loss factors - Queensland	22
Figure 3‑7: Static intra-regional loss factors – South Australia	23
Figure 3‑8: Static intra-regional loss factors – Victoria	23
Figure 3‑9: New South Wales transmission network	24
Figure 3‑10: Queensland transmission network	25
Figure 3‑11: South Australian transmission network	26
Figure 3‑12: Victorian transmission network	27
Figure 3‑13: Tasmanian transmission network	28
Figure 3‑14: Projected trends in load growth for NEM regions	29
Figure 3‑15: Coal resources in Australia	31
Figure 3‑16: Existing and planned gas pipelines	32
Figure 3‑17: Reserve plant margins in the NEM	33
Figure 4‑1: Cost recovery from short--run transmission charging	47
Figure 4‑2. Generator location decision	50
Figure 4‑3. External effects of generator location decisions	52
Figure 5‑1: Pricing framework for the NEM	61
Figure 5‑2: Example of intra-regional constraints	66
Figure 5‑3: Firm generator access: radial network	74
Figure 5‑4: Firm generator access: meshed network	74
Figure 5‑5: Firm access options	77
Figure 6‑1: Customer TUOS charges in the NEM	84
Figure 6‑2: Comparison of cost-reflective versus postage stamped charging	91
Figure 6‑3: Projected 1997/98 generator capacity charges	94
Figure 6‑4: Institutional and governance arrangements in the NEM	103
Figure 6‑5: Effect of network investment on feasible dispatches (1)	108
Figure 6‑6: Effect of network investment on feasible dispatches (2)	108
Figure 7‑1: Review of energy market pricing approaches	114
Figure 7‑2: Overview of transmission charging arrangements for cost-recovery	124

AARR			Aggregate annual revenue requirement 
ATC			Available transmission capacity 
CRNP			Cost-reflective network pricing
CQ			Central Queensland 
ECPR			Efficient component pricing rule
ESI			Electricity supply industry
FNQ			Far North Queensland 
FTR			Fixed transmission right
HV			High voltage
HVDC			High voltage direct current 
IRH			Inter-regional hedge
IRPC			Inter Regional Planning Committee
IRSR 			Inter-regional settlement residue
IRT			Inter-regional trader
ISO			Independent system operator
LRMC 			Long run marginal cost
LV			Low voltage
MLF			Marginal loss factor
NEM			National Electricity Market
NEMMCO		National Electricity Market Management Company
NQ			North Queensland 
NSP 			Network service provider
ODV			Optimised deprival value
OPF			Optimal power flow
PJM			Pennsylvania-Maryland Interconnection
RRN			Regional reference node
SLF			Static loss factor 
SRMC			Short run marginal cost
SQ			South Queensland 
TCC 			Transmission congestion contract
TNSP 			Transmission network service provider 
TUOS			Transmission use of system
WEPEX		Western Power Exchange

Executive summary
1.	This report reviews the pricing arrangements for electricity transmission in the National Electricity Market (NEM). It focuses on the resource allocation problem which a framework of transmission prices should ‘solve’ in order to bring about efficient outcomes in the provision of transmission services. 
2.	The Australian Competition and Consumption Commission (ACCC) commissioned London Economics to undertake a preliminary review of Australian electricity transmission pricing, starting from first economic principles, and with the objective of determining a ‘way forward’ for transmission pricing. In general, it is important for market participants, regulators and policy makers to continually seek ways to lower electricity costs for customers. This means that the process of electricity reform should be ongoing. This process will only continue if there is a genuine commitment by governments to the aims of reform. 
3.	In this respect, the recommendations in this report should be viewed as providing a framework for the next stage of the market in respect of transmission pricing arrangements. The recommendations for further reform should not be seen as our view of the ‘ideal’ market arrangements. 
South-east Australian interconnected network 
4.	Transmission pricing should address the current and future physical and market requirements of the South-east Australian interconnected network. Following completion of the Queensland-New South Wales interconnect (QNI), this will comprise the five regions of the NEM – South Australia, Victoria, New South Wales, Snowy and Queensland. 
5.	While the interconnected high-voltage (HV) network is generally depicted as having a long, linear structure, there are substantial loops, and hence interdependencies, within and between regions. At the same time – as a consequence of differential demand growth, fuel availability, topography and policy environments – each regional system has developed at a different pace, and is facing a different set of problems. The size of network losses and the frequency of intra-regional constraints differs across the regions of the NEM, and investment requirements vary correspondingly. 
6.	
Where future market requirements are concerned, the capacity of the existing infrastructure and trends in demand in the NEM are broadly known. In the short- to medium term, it is also possible to develop a view about the type and location of investment which may take place. However, these predictions depend on actions taken by independent market participants or regulators and policy makers, and are unlikely to be reliable in the longer run. 
7.	However the substantial changes that have occurred in the Australian electricity supply industry (ESI) in recent years are likely to impact on required network investment and the framework for transmission pricing:
•	Depending on which interconnectors are commissioned, there is a need for new generation capacity in different parts of the NEM. This may require network augmentation and, to the extent that generation projects will be privately financed, access rights to the network will have to be clarified. 
•	The system to date has not been engineered for wide-spread trading across regional boundaries, and further network augmentation is likely to be required to accommodate market trades arising from greater inter-regional trade. 
•	More generally, increased participation in the NEM of privately owned market participants is likely to place greater pressures on information provision and governance arrangements placed on transmission network service providers (TNSPs). 
Economics of electricity networks 
8.	The structure that is adopted for pricing transmission services should reflect the economics of electricity networks, that is, the structure of costs and other key characteristics. 
9.	In the short run, the costs of transmission take the form of energy losses and network congestion. To ensure that electricity is supplied at least cost, these costs need to be reflected in the dispatch of generating plant. In the NEM these costs are approximately captured in regional electricity spot prices.
10.	
In the longer run, the costs of transmission consist overwhelmingly of capital costs. Transmission investment is characterised by economies of scale and scope and is lumpy, so that ‘overbuilding’ is often the least cost option. ‘Loop flows’ arising from Kirchoff's Law in effect result in (positive or negative) externalities, since particular flows will have knock-on effects elsewhere in the network. The implications of the above features for transmission pricing are that: 
•	charges that are based on marginal costs will not recover the fixed costs of the network; and
•	it is often not possible to attribute specific assets to particular users, since electricity flows follow multiple routes along the path of least resistance, according to Kirchoff’s Law. 
11.	These characteristics of transmission infrastructure seriously limit the extent to which ‘market forces’ can be introduced in the provision of transmission services, and in particular investment. Decentralised investment would result in network investment which is insufficient or non-optimal from a wider public policy perspective. In practice, this means that the costs of the operations of the network and transmission investment will continue to have to be recouped via regulated transmission charges of some kind. 
12.	There is then a fundamental tension between the market failures in the provision of transmission services which necessitate a central planner for network investment (and a regulator for cost recovery) and the market forces which drive investment by market participants. The ‘regulated’ approach to transmission pricing has been adopted to address these market failures, but raises the prospect of regulatory failure. Under this approach, which has also been adopted in the NEM, a monopoly TNSP operates, plans for and invests in the HV network and collects regulated charges from network users to cover the costs of the shared network. In turn, market participant have more or less defined rights to make use of the HV grid. 
13.	This traditional model has limitations, where trade between market participants is important and transmission capacity is a limited resource. This raises the question how transmission pricing and regulation can meet the conflicting demands from market participants and customers which are likely to arise in a deregulated market environment. 

Objectives of transmission pricing
14.	This report identifies a number of objectives for evaluating approaches to transmission pricing, including efficiency objectives (encompassing the least-cost and cost-reflective operation and development of the ESI), cost recovery objectives, but also transparency, equity, stability and flexibility objectives. In practice these objectives are not consistent. 
15.	Efficiency objectives would require a rigorous marginal cost pricing approach across the transmission network to reflect the costs of transmission congestion and losses. This is the nodal pricing approach originally proposed by Schweppe et al. More recently, proponents of nodal pricing have argued that such a market should be supplemented by a framework of transmission congestion contracts (TCCs) which would support entrepreneurial investment in the transmission network. Others have argued that more familiar forms of financial contracts could also provide a solution to managing trading risks between price reference points across an electricity market. 
16.	The ‘market based’ model has been proposed to create a link between network investment and the commercial incentives of market participants. At least in part, network planning and investment would be undertaken by market participants. In return, these would receive corresponding property rights – TCCs – to lock in network capacity rights. While this approach is theoretically appealing and is likely to form the basis of an appropriate transmission pricing structure, fundamental problems remain: 
•	The rentals accruing from the explicit pricing of losses and congestion recover only a small share of the fixed costs of the network. 
•	While TCCs may be valid hedging instruments, loop flows and the existence of economies of scale and scope in electricity networks complicate the determination of contractual ‘rights’ to parts of the transmission network, in return for private investment. TCCs raise a number of serious implementation difficulties and, by themselves, are unlikely to lead to optimal investment in the network. 
17.	In addition, attempts to attribute the fixed costs of electricity networks to users to achieve cost-reflective prices are complicated by loop flows. At least to an extent, all users share the benefits of all transmission assets in the meshed network, since electricity flows move widely across a network. These difficulties are akin to those arising more generally in the context of network scale and scope economies. 
18.	These findings imply that a departure from the regulated model and administered two-part tariffs to achieve cost recovery objectives is some way off, until these issues can be effectively managed. Charging for the fixed costs of transmission is then a ‘second best’ pricing problem, where the objective becomes cost recovery in a least-distortionary fashion. 
Pricing arrangements in the NEM 
19.	Energy and transmission pricing arrangements for the NEM are set out in the National Electricity Code (the Code).
20.	The NEM was formed on a zonal basis and structured around a number of regions. Within regions congestion is not immediately reflected in price differences, and losses are approximated via fixed loss factors relative to a regional reference node (RRN) and by dynamic loss functions between RRNs. Network congestion between regions results in the separation of regional market prices. Within regions congestion does not lead to intra-regional price differences. While this framework provides time-of-day prices, it only captures locational price differences in an approximate manner. 
21.	With the exception of connection costs, transmission network costs in the NEM are recovered from customers via averaged (postage stamped) tariffs and charges based on the cost reflective network pricing (CRNP) methodology. Common services which maintain power system security, and cannot be allocated on a location basis, are also charged to customers via postage stamped tariffs. 
22.	The Code provides scope for a generator charge, based on the long run marginal costs of undertaking transmission investment. This has been linked with firm access rights in the network, but this relationship has not been clarified. 

Main findings 
23.	Given the context of reform and the objectives with which the NEM was established, economic efficiency should play a key role in the design of a framework for transmission pricing. In principle, spot markets based on nodal pricing theory meet these efficiency criteria. However, in the short term, designing a pricing system which meets all efficiency objectives is unlikely to be a practical option: 
•	efficient (i.e. marginal cost based) transmission pricing does not recover the costs of the fixed network; 
•	difficult technical and implementation issues that arise in the context of nodal spot market pricing that remain to be resolved; 
•	appropriate hedging instruments to manage greater locational price risks for market participants are required; and
•	efficient charging and greater cost-reflectivity is likely to raise equity concerns among the jurisdictions. 
24.	Achieving the most economically efficient pricing system should be the objective of transmission pricing reforms. However, in the context of the NEM, the need for transitional measures arises because the electricity policy positions developed over a number of years have only very recently been implemented. Even now these policies remain incomplete. It is likely that before any further major electricity reforms are accepted by policy makers, material gains from earlier reforms will need to be demonstrated. 
25.	The following recommendations should then be interpreted as transitional measures for addressing perceived short-comings in the Code, to ensure the predicted gains from reform are fully realised. 
Governance
26.	Appropriate governance mechanisms for TNSPs in a disaggregated and deregulated ESI are essential for limiting conflicts which will arise from the conflicting objectives between groups of market participants, but also market participants and customers. In a deregulated environment there is a requirement for transparent processes and clearly articulated objectives and roles of TNSPs, as well as for NEMMCO, and for governance processes to ensure that these are followed. 
27.	
It is unclear which body will represent the interests of customers for least-cost supply of electricity in a disaggregated and more commercially focused ESI, to ensure that:
•	investment which meets this objective is undertaken; and
•	investment which does not meet this objective is not undertaken. 
In line with international practice, this role could be undertaken by the regulator. Other options include an independent system operator (ISO), such as NEMMCO, but this model has serious drawbacks. 
Short run pricing in the energy market
28.	In the NEM the short-run costs of transmission are reflected in an approximation of a full nodal pricing approach and reflect the trade-off between:
•	creating short-term cost signals to network users; and
•	limiting the complexities and distributional effects associated with nodal pricing. 
29.	Where there are intra-regional constraints, the Code provides for payments in some circumstances to constrained on generators, but not for payments to constrained off generators. This approach appears arbitrary, the price determination approach is likely to encourage generator gaming, and the implications are for generator investment are unclear. 
30.	In relation to the energy pricing proposals for the NEM we recommend that:
•	the statistical approach for estimating inter-regional dynamic loss factor equations be reviewed to ensure that these faithfully reflect the structure and level of actual losses and, thus, send appropriate price signals; 
•	the pricing implications of intra-regional constraints be reviewed with respect to incentives for generator gaming, but also to clarify investment incentives for TNSPs and market participants; and
•	the extent to which the averaging of intra-regional losses is appropriate be clarified. 
31.	
Determining whether greater steps towards a cost-reflective pricing of transmission losses and congestion is appropriate requires:
•	calculating the costs of network congestion and losses in an optimal dispatch model under a diverse range of system conditions for comparison with the price and quantity outcomes under NEM arrangements; 
•	assessing whether the differences in the respective outcomes are likely to translate into significantly changed demand and generation profiles and hence resource costs; and 
•	assessing whether other conditions for effective trading – such as the existence of risk management instruments – are in place. 
Fixed cost recovery 
32.	50% of network costs are currently recovered from transmission customers through postage stamped charges, that is charges, which do not distinguish by location or size of customer. Averaged charges have some advantages, in that they are simple to collect and are considered equitable. However, full reliance on postage stamped charges for shared network assets encourages inefficient locational decisions by customers in the more distant and radial parts of the grid.
33.	The remaining 50% of network costs are recovered from customers via the CRNP methodology. CRNP charges:
•	are stable over time, if they are applied to customers, if load growth in different locations is reasonably steady, and if no major ‘disturbances’ in network flows occur;
•	can support dynamic efficiency objectives relating to locational decisions by customers; and
•	are more equitable than full postage stamp pricing in the sense that those customers further away from the centres of generation also pay more.
34.	The drawbacks identified by a number of commentators with the CRNP methodology can be addressed in practice, and the CRNP charge is broadly appropriate in the current market as a means of signalling the longer term costs of network expansion to customers. 
35.	
Determining the appropriate balance of postage stamped and CRNP charges should be determined by the following considerations:
•	longer run cost signalling objectives; 
•	cost attribution objectives, but these require an investigation of the relationship between long run marginal costs (LRMC) and average network costs, and may lead to different balances across regions; and 
•	equity (or cost averaging) objectives across the network. 
36.	The Code should provide some leeway on this issue, but only on the basis of actual network costs. That is, the onus should be on the TNSP (or jurisdiction) to show that the cost structure of the transmission network is such that a greater or lesser degree of locational signalling is appropriate. 
37.	Common service and postage stamped charges to customers are mostly recovered on a c/kWh basis. CRNP charges are currently levied on the basis of fixed components, nominated peak demand and $/kWh charges. The following issues should be clarified:
•	in the context of the postage stamped and the CRNP charge, whether a greater proportion of these costs should be recovered via a fixed charge, given that the majority of network costs are fixed, and to render these costs more ‘visible’ to users; and 
•	whether the Code should be formulated in a more restrictive manner, to ensure that the recovery of these costs is consistent with regional cost drivers. 
38.	The argument for charging both generators and customers for the use of the shared network rests principally on dynamic efficiency objectives, that is, the need to limit high locational costs in parts of the Australian HV network. The generator LRMC charge outlined in the Code is intended to signal the incremental cost of expanding the network to meet additional generation at every node, based on a 30-year grid expansion program and suffers from a number of short-comings, in that it:
•	lacks transparency; 
•	requires very good forecasting skills on the part of TNSPs, far into the future; and
•	is not stable, from one review period to another, since its calculation depends on load flows in the network which will change as new generators come on line. 
39.	
Nevertheless, in principle a generator charge incorporating some form of user-pays principle to capture locational network costs is appropriate. It may be possible to mitigate against some of the drawbacks of the generator charge specified in the Code by removing the requirement to ‘rebalance’ charges from year to year, and by relying on a greater extent of cost averaging. However, this raises the prospect of introducing inefficiencies. 
40.	A shift to generator charging would also bring with it benefits from a wider governance point of view. That is, charging all users of the network for some proportion of costs, is likely to strengthen the incentives for market participants to scrutinise these costs. 
41.	We propose a greater reliance on user payments for shared network assets. Where a user can be considered to ‘cause’ investment in the radial deep network which is unlikely to confer a benefit on other customers for some foreseeable term, direct payments by market participants for investment offer an avenue for recouping the costs associated with generator and customer location decisions. Whether or not investment should be financed directly by a proponent should be resolved with respect to an economic cost-benefit analysis. 
Investment 
42.	A key concern with current provisions in the NEM relates to the extent to which network investment is undertaken on a separate regional basis, rather than in the context of the integrated NEM. Given network externalities and inter-regional knock-on effects, the distinction between intra-regional and inter-regional network investment is inappropriate, and joint planning processes with the objective of facilitating the least-cost expansion of the ESI should be strengthened. From the point of view of minimising the costs of investment, such joint planning processes are appropriate not only between TNSPs, but also between TNSPs and distribution NSPs. 
43.	However, greater integration of network planning needs to be balanced:
•	by concerns about governance and accountability, if the result is simply a shift in power to a central body; and
•	concerns, regarding the extent to which investment at all levels of the network can be coordinated in practice. 
44.	
The implementation of market based approaches for network investment is some way off. However, the following proposals could serve to clarify governance processes and improve transparency:
•	that investments can be proposed by a range of interested parties, but are evaluated by an independent planning body; 
•	that proposed (inter- and intra-regional) transmission investment should be evaluated subject to the public benefits criterion, as measured by the size of economic surpluses under competitive market conditions; 
•	that if the economic benefit test is not met, investment should be financed by the proponent as an unregulated asset. 
Network access rights 
45.	The issue of firm inter- or intra-regional access has wider implications for:
•	the viability of existing and investment incentives for future generators;
•	the nature of the obligation by TNSPs to connect generators to the deep network and make corresponding payments to generators; and
•	the longer term incentives of TNSPs for network augmentation. 
46.	Payments in the energy market can constitute a form of implicit guarantee of firm access:
•	where inter-regional constraints are concerned, the development of (perhaps simplified) inter-regional hedging instruments should be encouraged; while
•	we propose a framework of payments for intra-regional constraint events that focuses on the extent to which generators who are constrained on or –off effectively perform a network service. 
47.	However, such payments should be determined with reference to a least-cost provision, to ensure that the interests of customers required to pay for shared network assets are appropriately taken into account. This proposal is likely to require greater involvement on the part of the system operator to assess trade-offs between energy and transmission costs. 

Private investment 
48.	Code proposals for compensating private investors in the network are incomplete in a number of respects. For unregulated inter-regional and radial links, associated losses and congestion line rentals should be attributed to investors. However, the day-to-day control of the asset would have to be left to the system operator, and the day-to-day management, including operations and maintenance, would have to be left to the TNSP, to reflect the integrated nature of transmission networks and to mitigate against any adverse investment incentives.

1.	Introduction
This report reviews the pricing arrangements for electricity transmission in the National Electricity Market (NEM). It focuses on the resource allocation problem that a framework of decentralised transmission prices should ‘solve’ in order to bring about an efficient outcome in the provision of transmission services.
1.1	Terms of reference 
The Australian Competition and Consumption Commission (ACCC) has commissioned London Economics to undertake a review of Australian electricity transmission pricing, starting from first economic principles, and with the objective of determining a ‘way forward’ or general direction that the approach for transmission pricing should follow. This assessment should be undertaken in the context of the current and foreseeable configuration of the Australian high voltage (HV) grid and the operations of the NEM. 
In this respect, the recommendations in this report should be read as providing medium to longer term targets for supporting an efficient wholesale electricity market. Some of the more ambitious objectives, for instance those relating to the efficient pricing of transmission costs in the spot market, require a liquid market for financial instruments and assume that the underlying generating capacity market is competitive. It is not clear that these conditions will be met for some time to come. 
1.2	The role of prices
Prices for goods and services play a central role in market economies by directing resources to uses where they are most valued. Classical economic theory establishes a general equivalence: Under certain conditions, an ‘optimal’ (efficient) allocation of resources can be achieved via decentralised price-setting, which supports the operation of competitive markets. Alternatively, an efficient allocation of resources can be achieved via direct commands and controls to allocate resources in a welfare-maximising way – a planning solution. 

The provision of transmission services has traditionally been undertaken in a planning, rather than in a market-oriented, fashion. That is, transmission network service providers (TNSPs) undertake network operations and planning and investment activities. In return, network users pay transmission charges. In the NEM and in many other jurisdictions, the role of these transmission prices is primarily to recover the costs of the transmission network and, to a limited extent, provide a degree of cost signalling to users. 
More recently, the focus in the network pricing literature has shifted to developing pricing structures that more closely link services used to prices paid – for instance, by requiring users to finance and undertake their own investment. Such a ‘market-oriented’ approach contrasts with the traditional emphasis on achieving efficient transmission outcomes through reliance on centrally planned solutions. Central planning (and the power it confers to certain industry bodies) does not fit well in the context of reformed industries, where both generators and retailers are independent market participants. The question is therefore whether, in practical terms, transmission prices can be designed in such a way as to allow decentralised market behaviour to take the place of the planning solution.
1.3	About this report
This report aims to review the principles of transmission pricing and their application in the context of the NEM, and is structured as follows:
•	Section 2 reviews the economics of transmission networks;
•	Section 3 outlines the structure and operation of the Australian HV network;
•	Section 4 comments on the objectives of transmission pricing in the light of the economic characteristics of transmission and the Australian network;
•	Sections 5 and 6 review pricing arrangements in the NEM and provide a preliminary assessment of these approaches;
•	Section 7 reviews the international experience in transmission pricing; and
•	Section 8 develops our recommendations for transmission pricing in Australia in the light of the above discussion. 

This report is supported by the following annexes:
•	Annex I provides additional details about the economics of electricity networks; 
•	Annex II describes the provisions in the National Electricity Code (the Code) in more detail; 
•	Annex III reviews the international experience; and
•	Annex IV lists the references used in this report. 

2.	Economics of transmission networks 
This section reviews the economics of transmission networks to set the context for the pricing issues that are discussed subsequently in this report. The economic characteristics of electricity networks severely limit the extent to which standard pricing objectives listed in Section 3 can be implemented in practice. 
In the short run, the costs of transmission services take the form of network losses and the effects of network congestion. In the long run, the costs of transmission are fixed, and are characterised by economies of scale and scope. In either case, network externalities imply that cause and effect of short and long run costs are generally difficult to determine. 
2.1	Kirchoff’s Law
Externalities typically arise in electricity networks. Electricity moves according to Kirchoff’s Laws, following the path of least resistance. As a result of these physical laws, power moves across many parallel lines, often in circuitous routes. This has implication for the extent to which costs can be attributed to users:
•	electricity flows in one part of the network impact flows elsewhere, if there are multiple routes between the source of power and the corresponding load; and
•	the addition (or removal) of infrastructure by a TNSP or independent party changes electricity flows and therefore usage patterns elsewhere in the network. 
Consider for instance the analogy of the contract path. In a rail line, it is easy to describe the route that a train will take. The contract can specify a particular route and that path can be used. Likewise, it is easy to map of an electricity transmission system and find a path between a generating plant and a customer. However, in this case, the notion of a contract path is a fiction. The actual flow of power may, and often does, diverge widely from contract paths. As a result, the supposed economies of the contract path have little to do with the actual costs of the power transfer.
2.1.1	
Loop flow externalities
Kirchoff’s Law then gives rise to ‘loop flow’ externalities. Figure 2‑1 illustrates this effect in the context of the contract path approach for power exchanges that has been the norm in US power systems in the past. In fact, power transfers between two distinct nodes have network effects far beyond the direct route. 
Figure 2‑1: Loop flow example

Source: 	Hogan, Contract Networks For Electric Power Transmission: Technical Reference.
Notes:	The figure is adapted from Federal Energy Regulatory Commission, The Transmission Task Force’s Report to the Commission. Electricity Transmission: Realities, Theory, and Policy Alternatives, Washington, DC, October 1989.
2.1.2	Cost attribution
Kirchoff’s Law and the resulting loop flows imply that cost attribution of certain parts of the network to certain users becomes very difficult, since one network user’s power flows affect those of all other network users. These cost attribution difficulties apply both for the short term costs of transmission – electricity losses and congestion – and for the longer-term, fixed costs of transmission – the infrastructure used to transport electricity. 
2.2	
Short term costs of transmission
In the short term, the costs associated with operating and maintaining transmission networks are largely fixed. Instead, costs arise in relation to energy flows. The short term costs of transmission services for a particular network user take the form of losses and network congestion (constraints). 
These costs depend on overall flows of electricity, including those due to other system users. Electricity losses and congestion can then be compared to the types of consumption externalities arising in peak hour road traffic, where the travelling costs of an individual user increase as a result of the existence of many other users at the same time. 
2.2.1	Losses
Transmission losses increase exponentially in proportion to energy flows on any particular line, while marginal losses increase in proportion to flows and with distance. The value of these losses is directly related to the cost of generating electricity. 
In Figure 2‑2, for instance, Generator 1 supplies a load of 95MW at $10/MWh. To supply 95MW, Generator 1 needs to generate 100MW, since 5% of the power generated is dissipated in line losses. The delivered cost per MWh for customers correspondingly translates to $10.53/MWh. The implication is that the losses component of short run transmission costs are reflected in the increased cost of generation to meet demand.
Figure 2‑2: Transmission losses

Source: 	Hunt & Shuttleworth, Competition and Choice in Electricity.
If transmission losses are not properly taken into account in the dispatch decision, the overall short term costs of generation can increase. For instance, it may be more efficient to dispatch a higher cost generator that is located more closely to the centre of demand, rather than incurring large line losses to wheel cheaper power to a load centre. 
2.2.2	
Transmission congestion 
The costs of transmission congestion (or constraints) are more complex to determine than the costs of losses. Constraints arise, if the capacity of existing transmission lines is reached. As is the case for losses, the costs of transmission congestion cannot be separated from the cost of generated energy, since congestion has implications for generation dispatch. That is, transmission congestion is addressed by ‘redispatching’ generating plant to avoid violating the constraints. This implies a move away from an unconstrained, or least-cost, merit order. The opportunity cost of transmission congestion then depends on the marginal cost of power at different locations, and these costs are determined simultaneously through dispatch processes and the spot market. 
In Figure 2‑3, Region A is characterised by 500MW of demand and a generation structure where costs rise relatively steeply. Demand in Region B is 1,000MW, and generation costs rise more slowly. Graph 2C superimposes the two supply schedules for a total demand of 1,500MW. In the absence of constraints, demand would be met by the least cost combination of generators – that is Generators 1A, 2A and 1B, 2B, 3B would generate to meet total demand. In this case, the most expensive generator operating would be generator 3B at $28/MWh. 
In the presence of a network constraint between the two regions, Generator 3B could not be fully dispatched to meet demand in Region A and the more expensive Generator 3A would also have to be dispatched. This changes the least-cost merit order; in effect, Generator 3B is constrained off and Generator 3A is constrained on. In the extreme case, where no capacity can be transported from one region to another, Generators 1A, 2A and 3A would meet demand in Region A and Generators 1B, 2B, 3B would meet demand in Region B. The cost of constraints is therefore directly related to the difference in the cost of energy between the ‘importing’ and the ‘exporting’ region.
Figure 2‑3: Implications of constraints for least cost dispatch

2.3	
Longer term costs of transmission 
The theory of perfect competition assumes increasing marginal costs in production and instantaneous responses in a market context. In contrast, transmission networks exhibit classical economies of scale in the form of a cost versus capacity curve where average costs decrease over large stretches of capacity. Transmission assets take some time to construct and have a useful life of between 30 and 50 years. These cost characteristics and the loop flow externalities referred to in Section 2.1 imply that cost savings arise from coordinating investment. 
2.3.1	Capacity costs of transmission lines
The amount of electricity that can be supplied to consumers depends on the capacity of the network. Transmission capacity refers to both thermal and reliable capacity. Power flow constraints on shorter lines are set by thermal limits and on longer lines by stability limits. Capacity constraints on a network are set by a combination of these constraints on lines and a reliability criterion, such as the N-1 contingency criterion. 
	Thermal capacity 
Transmission capacity is initially interpreted as the thermal capacity of the line in, say, MW. Thermal capacity is the maximum power that can be transmitted along a transmission line without causing accelerated aging of the line. In practice, the thermal capacity of a line also depends on other factors, such as losses, reactive power, surge impedance loading and emergency ratings. 
Broadly speaking, the capacity of transmission facilities depends on the operating voltage of a line. Operating voltages are standardised into a small number of widely spaced levels – e.g. 115kV or 220kV - so that transmission capacity is typically available only in discrete lumps. At a given voltage level, it is standard practice to build towers to support either one or two sets of transmission lines (single-circuit and double-circuit construction). The capacity of double-circuit construction is approximately twice that of single-circuit construction; however, the costs of double-circuit construction are considerably less than twice the costs of single-circuit construction. This gives rise to the alternative staircase cost characteristic in Figure 2‑4. 

If all construction must be either at 115kV or 220kV, the minimum cost of thermal capacity is shown by the lower envelope of the two cost curves in Figure 2‑4. 
Figure 2‑4: Cost of thermal capacity

Notes:	Cost of thermal capacity, in arbitrary money units per unit length, versus thermal capacity. Capacity at 115kV is shown by the thin line; capacity at 220kV is shown by the thick line. Data is sourced from EPRI, 1986. 
Source:	Baldick and Kahn, 1993. 
Figure 2‑4 illustrates significant economies of scale, but also reflects the lumpiness of construction of transmission wires. Lumpiness combined with economies of scale produces average costs that vary significantly as capacity changes, even at high levels of capacity.
	Reliable capacity 
The economies of scale described in Figure 2‑4 are reinforced by the need to construct reliable transmission capacity. To prevent transmission failures, it is standard practice to design transmission systems according to the ‘N-1 criterion’. This (reliability) criterion requires that even after failure of any one of N lines in a system, load must still be able to be served without overloading any of the remaining lines past their emergency ratings. 

The N-1 reliability criterion exacerbates the economies of scale effect, but also results in economies of scope, since there are cost savings from sharing back-up capacity. Figure 2‑5 charts construction cost versus reliable capacity at 115kV and 220kV, respectively. The minimum cost of reliable capacity is the lower envelope of the two cost curves. The minimum costs are the lower of the two lines. 
Figure 2‑5: Cost of reliable capacity

Notes:	Cost of thermal capacity, in arbitrary money units per unit length, versus thermal capacity. Capacity at 115kV is shown by the thin line; capacity at 220kV is shown by the thick line. Data is sourced from EPRI, 1986. 
Source:	Baldick and Kahn, 1993. 
It is important to note that for both thermal and reliable capacity, costs apply for de novo construction. It is not possible to start with 115kV construction and achieve a higher capacity at 220kV for the incremental costs implied in Figure 2‑5. In other words, a choice between 115kV and 220kV construction has to be made at the outset. 
2.3.2	
The longer term planning problem
Economies of scale and scope of transmission networks complicate longer-term planning and investment, since there are cost savings from integrating otherwise separate investment projects. 
Annex I formalises an example dynamic planning problem. In this example, the aim is to minimise the total cost of constructing thermal and reliable transmission capacity and supplying electricity to customers (through transmission or generation investment), subject to meeting a range of network constraints. The example shows that even for simple network extensions or augmentations, establishing a least-cost investment path is a far from trivial problem. The overall cost minimisation problem solved by Kahn and Baldick reflects the dynamic trade-off between generation and transmission costs and results in a three-dimensional ‘solution’. 
Kahn and Baldick conclude that:
•	over wide areas of network configurations, the optimally coordinated plan is considerably less expensive than independent planning; 
•	due to the lumpiness of construction, there can be ‘excess’ capacity in an optimally planned system; and
•	the information needed to perform the calculation of the transmission cost function is usually under the exclusive control of the utility or group of utilities owning the network. 
2.4	
Summary
In the short term, transmission costs take the form of energy losses and changed energy costs arising from network constraints. The longer term costs of transmission are characterised by economies of scale and scope and declining marginal costs over wide ranges of the cost function. This implies not only that prices based on marginal costs cannot recover investment costs, but that complex coordination problems are created: 
•	Neither short nor long term transmission costs can be easily attributed to a particular market participant, since loop flow externalities imply that activities by one user can impact on power flows and network usage elsewhere in the network.
•	An example planning problem suggests that over a wide range of choices of transmission expansion, the coordination losses from independent planning are a relatively large fraction of the transmission expansion costs. 

3.	The Australian HV network
Transmission pricing should reflect the cost characteristics of the network and, to the extent that these can be estimated in advance, be sufficiently flexible to accommodate likely infrastructure trends, including developments in generation and demand. Existing characteristics, and expected future developments, of the integrated transmission network are therefore relevant for:
•	ranking the objectives defined in Section 4 of this report; and
•	determining the degree of complexity that is required in transmission pricing. 
This section considers the current and likely future nature of the existing interconnected South-East Australian HV network, to inform decisions about the ranking of objectives and complexity of transmission pricing rules that are required. It places the review of Australian transmission pricing in the context of:
•	the physical interconnected transmission system;
•	existing generation infrastructure and load centres; and
•	likely trends in infrastructure developments, including generation and demand.
3.1	The South-East Australian network 
3.1.1	Background
Historically, the electricity supply industry in Australia was managed on a regional basis. In each region, the generation, delivery and supply of electricity, and the maintenance and development of the electricity system were managed reasonably independently to other regions. The regional structure of the Australian electricity supply industry developed over many decades, and the separate regional systems are now connected by a series of transmission links with limited capacity.

The location and nature of power sector infrastructure has been influenced by a range of factors, including the natural endowment of fuel, water and topography, the level, pattern and growth of electricity demand, and the nature of the regulatory and institutional environment. None of the Australian power systems have been developed in the context of a national market. At least in the past, State Governments and/or their agencies have made all investment, operating and pricing decisions.
3.1.2	Information availability
Preparing a comprehensive description of the Australian HV system is not a simple exercise. Each of the TNSPs publishes information about existing network capacities and proposed network augmentation projects. However, information that is available on the location and materiality of constraints is confined to (some) inter-regional links and focuses on historic trends. There is limited published information relating to intra-regional network constraints, hence the evidence presented here is only qualitative in nature. There are several reasons for the limited availability of information about intra-regional constraints, depending on the region in question:
•	In the historically vertically integrated electricity supply industry (ESI) intra-regional transmission constraints were managed via redispatch of state-owned generators. The extent of intra-regional constraints may therefore not be well understood.
•	In some areas of highly meshed networks, the analysis of intra-regional constraints is a complex and time-consuming process. Intra-regional constraints that historically occurred infrequently were therefore not subject to detailed consideration of the constraint conditions.
•	‘New’ intra-regional constraints have emerged with different generation patterns emerging from the operation of the competitive wholesale market.
•	Over-investment in some regional networks has meant that intra-regional constraints occur infrequently at current network loading levels. 
3.1.3	Overview of the interconnected network 
Figure 3‑1 provides a simplified representation of the South-East Australian interconnected HV network that makes up the NEM, presenting both existing and proposed links.

Figure 3‑1: Regional interconnected structure of the NEM 

	Existing interconnections
The interconnected network currently links South Australia, Victoria and New South Wales. These jurisdictions have been defined as four interconnected regions for the operation of the NEM – South Australia, Victoria, Snowy and New South Wales. 

The main existing interconnectors include:
•	the Victoria-Snowy-New South Wales interconnectors between Dederang and Murray and between Wodonga and Jindera, as well as a further point of interconnection between Red Cliffs and Buronga; and
•	the South Australia-Victoria interconnectors (Heywood interconnector) between the Heywood Terminal station in South West Victoria and the South East substation in South Australia. 
	Proposed interconnectors and augmentations
It is intended that Queensland and perhaps Tasmania will become linked to the interconnected South East Australian network in the future. In addition, a number of augmentations to existing links have been proposed. In particular, the following interconnectors have been proposed or are under construction:
•	the Queensland-New South Wales interconnector (QNI), due for completion in 2000; 
•	interconnection between Victoria and Tasmania (Basslink) via a high voltage direct current (HVDC) link;
•	interconnection between New South Wales and South Australia (SANI); and
•	augmentation of the existing Heywood link between Victoria and South Australia.
	Interconnectors and regional boundaries
Transfer limits on transmission lines are dependent on the system operating parameters at any point in time. The transfer limits indicated in Figure 3‑1 are therefore only indicative, since the limits have been determined assuming particular system conditions. Moreover, the interactions between critical elements on the transmission network means that interconnector transfer limits are often determined according to their impact on assets deeply embedded in the regional networks. In some cases, the interactions between network parameters means constraints cannot be attributed to a specific location at all.

The complexity associated with the definition of interconnector transfer limits has implications for the definition of regions in the NEM. The declaration of regional boundaries is to some extent arbitrary, since the distinction between what constitutes an inter-regional asset and an intra-regional asset is not clear. In practice this means:
•	a number of other factors, such as minimising the number of constraints, and minimising the variation in marginal loss factors, are used to determine regional boundaries; and
•	pragmatism is applied in determining the distinction between inter- and an intra- regional assets. Here 
3.1.4	Fixed costs of the transmission network 
Figure 3‑2 summarises the available information on the size and valuation of the fixed costs of the respective regional networks. 
Figure 3‑2: Comparison of network assets and costs
Jurisdiction	Circuit km	Substations	Depreciated valuation property, plant & equipment ($millions)	
New South Wales (TransGrid)	11,527	73	1,968.1	
Queensland (Powerlink)	9,228	75	1,407.2	
South Australia (ETSA Transmission)	5,5431
	N/a	N/a	
Victoria (Powernet)	6,470	43	1,140.2	
Source:	Powernet SCI, 1996; ETSA Corporation 1997 Annual Report; TransGrid 1998 Annual Report; PowerNet 1997 Annual Report.
1	Expected.
3.1.5	
Short run costs of the transmission network 
The short run costs of the transmission network include network congestion costs and losses. The market rules for the NEM, including the energy pricing arrangements and the treatment of network congestion and losses, are described in Section 5 of this report. 
	Inter-regional network constraints 
Published data on inter-regional congestion in the NEM are available primarily from two sources:
•	NEMMCO’s review of NEM regions and loss factors undertaken prior to the commencement of the market; and
•	market data published during the operation of NEM1. 
The information presented by each of these sources is considered in more detail below.
	Review by NEMMCO 
NEMMCO undertook a review of transmission constraints and loss factors in September 1997.  The objective of the review was to advise on the number of regions and associated regional boundaries in the context of the Code framework, which declares areas separated by frequent constraints as separate regions and allows prices to diverge when a constraint applies. 
NEMMCO emphasised that network constraints currently arise in both directions between:
•	Victoria and South Australia, across the existing Heywood interconnect; 
•	Victoria and Snowy, across the Snowy interconnect; and
•	Snowy and New South Wales, across the Snowy interconnect. 

NEMMCO contended that the first two sets of constraints apply frequently, but provided no supporting evidence. The report noted that although the limit from Snowy to New South Wales is rarely reached, the limit from New South Wales to Snowy is reached relatively often (Figure 3‑3). NEMMCO did not report any detailed findings in relation to intra-regional constraints.
Figure 3‑3: Estimated hours of constraint for typical and atypical bidding
	Constraint hours per year	
Constraint	Lower bound	Typical	Upper bound	
New South Wales to Snowy	50	200+	400-1000+	
Snowy to New South Wales 	0	15	60	
Source: NEMMCO. 
	Data from NEM1
Some data on the frequency of constraint events are available from the operations of the NEM1 market between Victoria and New South Wales. This information supports NEMMCO’s findings in relation to the frequency of binding constraints. 
Figure 3‑4: 5-minute dispatch intervals with binding constraints 

Source: TransGrid
	
Losses 
Relatively little is documented about the size of the losses associated with inter-regional power flows in the NEM. As discussed in Section 5, inter-regional loss factors are approximated by inter-regional loss factor equations. While these equations are published, there is relatively limited historical data available to enable an analysis of inter-regional losses.
More information is available about intra-regional losses, since the published static loss factors (SLFs) provide an indication of the size of losses within regions. SLFs provide an indication of average marginal losses associated with power flows to and from a specific node within a region to the ‘reference node’ (the main load or generation centre). 
Figure 3‑6 through Figure 3‑8 plot SLFs for New South Wales, Queensland, South Australia and Victoria, respectively, for the year 1998/99. These figures highlight some key differences:
•	Queensland exhibits the greatest variation in SLFs, and relatedly, the greatest departure from the regional reference node loss factor of 1, indicating that:
-	losses are a significant proportion of energy costs in Queensland; and
-	patterns of generation and demand in different parts of the network have quite different implications for losses;
•	the New South Wales, South Australian and Victorian networks exhibit much less variation and losses are relatively limited.

Figure 3‑5: Static intra-regional loss factors – New South Wales 

Figure 3‑6: Static intra-regional loss factors - Queensland

Figure 3‑7: Static intra-regional loss factors – South Australia 

Figure 3‑8: Static intra-regional loss factors – Victoria 

3.1.6	
The regional transmission networks in the NEM
This section briefly considers the characteristics of the regional transmission networks in the NEM – New South Wales, Queensland, South Australia, Victoria and Tasmania. The characteristics of the Snowy region are discussed in context of the New South Wales and Victorian regions.
	New South Wales 
The transmission system within New South Wales consists of a 500kV and a 330kV system linking the major generating centres in the Snowy, Hunter Valley, Central Coast and Western coalfield areas with the major load centres at Newcastle, Wollongong and Sydney (Figure 3‑9). A 220kV supply is interconnected with the Victorian network and extends to Broken Hill. 
Figure 3‑9: New South Wales transmission network 

Source: NGMC Statement of Opportunities
Notes: 	 refers to 330kV or 220kV circuits.  refers to 500kV circuits. 

Inter-regional network constraints arise in the context of the Snowy-New South Wales interconnect. Intra-regional constraints currently arise infrequently, but are expected to occur in the future between the Hunter Valley and the Western Area, the Central Coast and Sydney (in particular following interconnection with Queensland) and between the Hunter Valley and the Far North Coast.
	Queensland
The Queensland 275kV main transmission system stretches from Chalumbin in Far North Queensland (FNQ) to Mudgeeraba in South East Queensland, a distance of some 1,500km and a transmission line length of approximately 1,700km. Figure 3‑10 presents an overview of the Queensland network and recognised limitations of the network. 
Figure 3‑10: Queensland transmission network 

Source: 	Powerlink Statement of Opportunities
Notes: 	 refers to 275kV circuits. 

The majority of Queensland generation capacity is located in Central Queensland (CQ), while the principal load centres are Brisbane and coastal areas, including those areas in the North of the State, although there are significant mining and industrial loads elsewhere. Relatively high power transfers therefore currently occur from CQ to North Queensland (NQ) and from CQ to South Queensland (SQ), and there are currently binding transmission constraints on each of these lines. Rapid load growth occurs, and is expected to continue in NQ and FNQ.
Powerlink has commenced a substantial program of transmission reinforcement projects to relieve existing and projected network constraints.
	South Australia 
The transmission system within South Australia consists of a main 275kV network underpinned by a 132kV and 66kV system. The network connects the major load centre at Adelaide with generation at Port Augusta, Torrens Island and the Victorian transmission system (Figure 3‑11). No information is available on intra-regional constraints. 
Figure 3‑11: South Australian transmission network

Source: 	NGMC Statement of Opportunities
Notes: 	 refers to 275kV circuits. refers to 132kV circuits. 
	
Victoria 
The transmission system within Victoria consists of a 500kV backbone from the major generators in the Latrobe Valley through Melbourne and across the Southern part of the state to Portland and Heywood, where there is transformation to 275kV for transmission to South Australia (Figure 3‑12). The major loads are located in the Melbourne metropolitan area, but also include the aluminium smelter at Portland.
Figure 3‑12: Victorian transmission network 

Source: 	NGMC Statement of Opportunities
Notes: 	 refers to 330V or 275kV circuits.  refers to 500kV circuits. 
VPX does not expect significant intra-regional capacity constraints to appear in Victoria in the foreseeable future. Additional capacity between the Latrobe Valley and Melbourne can be met without further development of this transmission corridor. There are some limitations associated with network elements at the extremities of the state grid, in particular, in the context of the Snowy-New South Wales interconnect. These limitations are primarily related to the operating state and pattern of loading, with the level of transfers a less important determinant of constraints.
	
Tasmania 
Tasmania is not presently a participant in the NEM, although the Government has announced its intention to join the NEM at some stage in the future. The Tasmanian transmission uses 220kV and 110kV transmission lines (Figure 3‑13). 
Figure 3‑13: Tasmanian transmission network 

Source: 	NGMC 
Notes: 	 refers to 220kV circuits. refers to 110kV circuits. 
Interconnection with Victoria via an undersea direct current (DC) link is currently being planned. Electricity in Tasmania is almost entirely generated by hydro-electric stations. The NGMC highlighted the need to augment the HV network between Derwent and Poatina in the late 1990s.
3.2	Future infrastructure developments
Section 3.1 focused on known current network characteristics. One of the objectives for developing a transmission pricing framework is to ensure that this is sufficiently flexible to address the types of issues that are likely to arise in the future. This requires an understanding of future trends in the Australian ESI, including the location and growth of future loads, as well as of future generation projects. This section considers future trends in the structure of the NEM, in terms of trends in generation and demand, respectively.
A number of difficulties arise in predicting future network trends:
•	Historically, planning tasks would have been undertaken centrally, in the context of a vertically integrated ESI. In a deregulated environment, this is no longer the case. Where (parts of) the industry are privately owned and make decentralised decisions, the scope for integrated planning, and indeed, the information that is likely to be available to network planning bodies, is much reduced. 
•	There is also an interdependence between electricity demand forecasts, network power transfer capability and subsequent developments, such as new generators or grid developments. That is, reliable grid capacity may encourage more generation and loads, and vice versa. 
3.2.1	New demand
New generation investment and new customer loads changes power flows throughout the network. As flows are rerouted and increase, further constraints may emerge, necessitating network investment.
Figure 3‑14: Projected trends in load growth for NEM regions

Source: 	TransGrid, VPX, ETSA Transmission, Powerlink. 
Figure 3‑14 shows projected aggregate trends in load growth for the regions of the NEM. Average baseline projections for peak demand growth are 2.2% per annum for New South Wales, 2.4% per annum for Victoria, 3.0% per annum for South Australia, and Queensland summer demand is expected to grow by an average of 4.0% per annum over the 5-year forecasting horizon. 

South Australia, Victoria and Queensland are all summer peaking systems, while New South Wales experiences electricity peak demand in winter, although this is expected to change over time.
It is worth noting that aggregate demand growth figures may mask significant regional variations, which will in turn drive network investment. In the case of Queensland, for instance, above average load growth is expected in the North of the State, and therefore detailed regional forecasts are required to determine network investment requirements. In addition, while most load growth tends to be gradual, the location decision of a very large customer, such as an aluminium smelter, will shift the regional demand-supply balance and will also significantly affect network flows. The location decisions of large industrial loads are difficult to predict. 
3.2.2	New generation
The type and location of new generation is likely to depend on a number of factors, including:
•	regional demand-supply balances, and the characteristics of plant best suited to meet any shortfalls;
•	the availability of fuels or required infrastructure, such as gas pipelines or water; and 
•	the location and capacity of other important infrastructure, such as transmission links. 
Figure 3‑15 and Figure 3‑16 below show the present location of coal resources and gas reserves, and pipelines in Australia, respectively. There are extensive coal deposits in Victoria, New South Wales and in Queensland. Whereas corresponding baseload generating plant is located in a fairly closely defined area in Victoria and New South Wales, this is not the case in Queensland, and the location of potential new generators is difficult to predict. In addition, all four states have (on- and off-shore) gas reserves, although the capacity of the pipeline infrastructure that is in place is limited. For instance, South Australia’s ability to accommodate new gas fired power stations in some parts of the network appears to be restricted, due to transportation constraints. In contrast, the proposed construction of a gas pipeline to Queensland from Papua New Guinea may offer scope for new gas-fired generators to locate in different parts of Queensland.

Figure 3‑15: Coal resources in Australia

Source:	LANDINFO Pty Ltd. 
Figure 3‑16: Existing and planned gas pipelines

Source:	Australian Gas Association. 
There are a large number of new generation projects currently under investigation in the NEM. It is difficult to determine in advance which projects are most likely to proceed. For example, in Queensland, a number of investors have signalled their interest in installing new capacity. A selection of projects currently being considered includes Callide C Power Station at Biloela, the Tarong Power Station expansion, Kogan Creek Power Station, Millmerran Power Station, Wondoan Power Station, the Sythe cogeneration project at Gibson Island, Acland Power Station, Wambo Power Station and the development of a cogeneration facility to support the Comalco alumina refinery.
3.2.3	
Market trends
Figure 3‑17 plots projected reserve plant margins for the regions of the NEM using the demand forecasts referred to above, and taking into account existing and committed generation projects. The figure indicates that New South Wales and Victoria are characterised by a substantial reserve plant margin arising from past over-investment in generation, while South Australia and Queensland have very low plant margins. This means that there is a relatively high probability of multiple generation outages in Queensland and South Australia, resulting in load shedding.
The supply-demand balance in each region must be considered in the context of existing and likely future transmission links. For example, if SANI is commissioned, the need for new generation capacity in South Australia would be reduced. Further network augmentation is likely to be required to facilitate inter-regional trade. 
Figure 3‑17: Reserve plant margins in the NEM 

Source:	London Economics.

The substantial structural changes that have occurred in the Australian ESI in recent years are likely to have implications for network trends, but also for the role of TNSPs more generally:
•	Network access and network rights. There is a need for new generation capacity in some parts of the NEM, which is likely to require network augmentation. To the extent that this generation investment is intended to be privately financed, access rights to the network will have to be clarified.
•	Information provision to market participants. Increased participation of privately owned market participants in the NEM is likely to place greater pressures on information provision about the operations and capabilities of the regional networks.
3.3	Summary
The South-East Australian interconnected transmission network consists of a series of regional markets, linked by HV power lines with limited capacity. This reflects historical trends and the slow rate of convergence of the individual regions. 
The regional ESIs making up the NEM – New South Wales, Queensland, South Australia and Victoria – also differ substantially in terms of generation and network infrastructure:
•	Victoria and New South Wales rely largely on electricity generated by coal-fired power stations. These systems are also characterised by excess generating capacity; 
•	South Australia relies on inter-regional power imports and, like Queensland, is facing increasing power shortages; 
•	intra-regional constraints arise frequently within Queensland and are expected to arise within New South Wales, but less so in Victoria; 
•	Queensland stands out among the four member regions of the NEM, in terms of capacity shortages arising both in generation and in transmission.

To a limited extent, these aspects provide an indication of future trends. Queensland and South Australia face power shortages that can either be met via greater interconnection or through commissioning of new generating plant. However, the degree of longer term uncertainty in the interconnected South-East Australian market has increased, given:
•	greater opportunities for independent market participants to invest in the industry; and 
•	the likely changed trading patterns arising in the NEM, in particular following the commissioning of new HV interconnections. 

4.	Objectives of transmission pricing
This chapter aims to clarify the objectives of transmission pricing. The following subsections review, in turn, the range of ‘standard’ pricing objectives in the context of the economics of electricity networks. 
Transmission prices should ideally support the following objectives: 
•	Efficiency objectives. These include: 
-	promoting the least-cost operation of the power system;
-	ensuring prices accurately reflect the costs of providing services; and 
-	encouraging efficient investment in the power system (including generation, demand side measures and the transmission system).
•	Cost recovery objectives. These are to ensure that owners of transmission assets recover efficient costs. 
•	Simplicity/transparency objectives. Such objectives relate to the complexity of the charging system and the extent to which customers understand prices and can respond to these in an appropriate way. This also encompasses market participants’ costs of participating in the market. If these are higher than the expected benefits, this undermines the likely reform benefits. 
•	Non-discrimination or equity objectives. These aim to ensure that one or more groups of users are not disadvantaged by a specific approach to transmission pricing. 
•	Stability over time. This may be considered important in order to facilitate investment decisions.
•	Flexibility. Flexible pricing structures may be required to accommodate important changes in the HV network and the structure of the ESI. 
These objectives are easy to list, but difficult to define in practice; they are also unlikely to be internally consistent. Thus a measure of the relative importance of the objectives needs to be developed, and the implied ranking may be different for different circumstances. 
4.1	
Efficiency objectives
From an economic perspective, and given the central importance of an efficient ESI in a modern economy, the different dimensions of economic efficiency should play a key role in designing a framework for transmission pricing. 
4.1.1	Least-cost production 
Economic theory suggests that under ‘ideal’ conditions (fully clearing and competitive markets, no institutional constraints and full information), a system can be regarded as efficient, if the following conditions are satisfied:
•	production occurs at least cost; and
•	prices equal the marginal costs of production.
	The short term
In the short term, the cost of transmission consists of energy costs. Different energy flows across a network are associated with correspondingly different levels of electricity losses. As power flows increase, congestion may eventually arise in the network, leading to network constraints. This has implications for generation dispatch. Some generators are required to generate more than they would have done under least-cost dispatch, while others generate less. These costs vary across different locations in the network and by the time component of usage. 
To achieve least-cost production in the short run therefore, least cost dispatch of power stations needs to simultaneously consider: 
•	the marginal cost of each generating unit; 
•	the cost of transmission losses from generation; 
•	the incidence and duration of grid constraints; and
•	relatedly, the additional cost incurred because ‘out-of-merit’ power stations need to run in order to meet demand to overcome the inability to supply customers from lower cost power stations (including transmission losses) due to grid constraints. 
As is the case in Australia, this approach has broadly been adopted internationally in reformed power systems (Section 7), although the extent to which losses and congestion are precisely valued varies significantly. 
	
The long term
The aim of minimising the fixed costs of transmission is generally considered to be a regulatory, rather than a pricing, problem, although this distinction has been the subject of some academic debate in recent years. The international experience suggests that utilities have incentives to invest to optimise their own benefits at a high cost to customers. The tendency to over-invest or to undertake poor investment projects is a result of the information asymmetry that typically exists between regulators and regulated utilities. Firms are far better informed about the cost and demand conditions in the industry, and the degree to which costs are reduced as much as is possible. As a result, a range of forms of regulation, involving different degrees of ‘intrusiveness’ and different ‘rules’ for determining allowable expenditures, have been developed in order to provide regulated utilities with some incentive to minimise costs. Whether or not these forms of regulation have been effective in terms of achieving lower cost outcomes is unclear. 
The decision to adopt one or another form of regulation for transmission businesses implicitly reflects a judgement about the risks of market versus regulatory failure. The origins and consequences of market failure are well understood. Market failure arises in the presence of declining marginal costs, externalities and where goods and services have ‘public good’ characteristics. However, it is now recognised that utility regulation to address these market failures brings with it associated costs, in terms of direct compliance costs, but more importantly, in terms of the particular incentives a regulatory regime offers to a utility. The incentive to over-invest (or ‘gold plate’) is a classic product of rate of return regulation, but utilities may adopt far more subtle strategies to ‘beat’ the regulator. In response, regulators have followed different strategies to overcome information asymmetries with respect to regulated utilities. For instance:
•	by developing highly intrusive and prescriptive regulatory structures, such as those that have evolved in the water industry and some aspects of the electricity industry in England & Wales; or 
•	by taking the view that greater interference is eventually counterproductive, and adopting a more light-handed regulatory approach, such as in New Zealand. 

It is in this context that options proposed in recent years by commentators such as Hogan need to be understood. Hogan refers to the ‘regulated’ approach to transmission pricing and investment, which has traditionally played a major role in integrated utilities as a ‘black box’. Hogan proposes a more market-based approach, in order to achieve greater planning transparency and efficient investment. This is discussed further in the context of network investment below. 
4.1.2	Pricing efficiency
Allocative efficiency objectives require that prices broadly reflect the cost of the service being provided. Users should consume a service until the marginal benefit they derive from it equals its costs of provision, and efficient prices should therefore signal the efficient level of costs. The concept of a nodal spot market has been developed to precisely value the short run costs of transmission, and to signal these costs by location and time of day. However, where long run costs are concerned, fixed cost allocation presents formidable difficulties in electricity networks, and standard economic ‘rules’ do not provide much guidance. 
	Short term pricing efficiency: Role of nodal spot markets 
In principle, capturing the short run costs of electricity relies on (nodal) spot markets that reflect locational and time-of-day cost differences. Spot market theory defines the optimal spot price at each node as the minimum system cost of supplying an additional kWh at that node when the system is optimally dispatched. The optimal nodal spot price measures the (forward looking) cost of supply and, as a consequence, provides the correct price signal to loads. If loads are presented with this price, they will consume up to the point where their marginal value of power is equal to the spot price. Thus, the optimal nodal price will also equal the value of supplying a marginal kWh at the node in question. 

Efficient (nodal) spot markets have a number of properties that solve the short term pricing problem to ensure efficient pricing of energy, losses and congestion and the least-cost operation of the ESI. Only some of these price outcomes are immediately obvious:
•	In a loss less and uncongested grid, the optimal nodal spot price is the same at all nodes. 
•	In an uncongested, but lossy grid, the optimal nodal spot price is lower at generation nodes and higher at demand nodes. These differences are great enough to earn the system operator a merchandising surplus (also referred to as a ‘loss rental’). The loss rental arises, because energy losses are priced at marginal costs, while average losses are only about one half of marginal losses. 
•	In a congested grid, the separation of nodal spot prices leaves the system operator with a second merchandising surplus (also referred to as a ‘congestion rental’). This congestion rental arises, because consumers pay for electricity at the cost of the ‘marginal’ plant, while some power will be supplied by lower cost plant. 
•	In a lossless grid with one congested line, it is possible that for some other line in the network the spot price at the demand end will be lower than at the generating end. This is referred to as an ‘uphill’ flow. In a grid with more than one congested line, the optimal nodal price at the receiving end of a congested line may be higher, lower, or equal to the optimal nodal price at the transmitting end. 
In spite of these complications, the optimal spot price differences between nodes send the correct signals to generators and loads. Both are discouraged from contributing to system losses and to congestion. Efficient spot prices, by design, take into account all system costs and benefits. 
	
Long term pricing efficiency: Allocation of fixed costs
While nodal spot markets reflect short term pricing objectives in the energy market and, by implication, the short run opportunity costs of transmission, they do not provide any guidance as to the pricing of the fixed capacity costs of transmission. Ideally, charging for the fixed costs of the network should:
•	reflect the notion that those parties who can influence the causation of costs should be the same parties that pay the costs; and 
•	be subsidy free (for instance, to ensure that there is competitive neutrality between network and local generation alternatives). 
However, in electricity networks, attempts to attribute costs to a user are seriously complicated by Kirchoff’s Law. At least to an extent, all users share the benefits of all transmission assets in the meshed network, since electricity flows move widely across a network. These difficulties are akin to those arising where there are network economies (economies of scale and scope). The difficulties associated with cost attribution and, hence, pricing in integrated networks are well known, and a number of approaches have been developed for addressing these. 
	Baumol-Willig conditions
Two general principles for the price regulation of network industries where there are economies of scale or scope are well established. These principles, frequently referred to as the Baumol-Willig conditions, are necessary conditions for ensuring productive efficiency in network and retail service provision. They are designed to mimic the constraints placed on the behaviour of multi-product firms in contestable markets: 
•	No price, or set of prices, should exceed the stand-alone costs of providing the service or services, where stand-alone costs are defined as the costs that an efficient competitor would incur in providing just that service or group of services.
•	No price, or set of prices, should be less than the incremental (or avoidable) costs of providing the service or services, where incremental costs are the additional costs incurred by the monopolist in providing just that service or group of services.

The difference between incremental costs and stand-alone costs is equal to the value of the scale and scope economies that arise from undertaking multiple activities within one network. The Baumol-Willig conditions are both necessary and sufficient to ensure that network and retail prices:
•	do not permit a monopolist to earn more than a competitive rate of return (i.e. excessive profits);
•	are not set so high as to induce the inefficient duplication of network provision (i.e. the inefficient entry of competing network operators); and
•	do not permit cross-subsidisation between services, and prevent a monopolist from engaging in predatory pricing. 
However, within the price bounds set by the Baumol-Willig conditions, numerous different pricing structures are possible - each corresponding to a different allocation of ‘common’ and ‘joint’ costs between services or users. In practice, this rule does not result in unambiguous pricing outcomes. Loop flows imply that each user’s power flows are distributed across a large number of assets, hence the floor and ceiling between which prices must lie is potentially very large. There is then a significant range in which prices could be described as being ‘subsidy free’. 
	Network access pricing mechanisms
The following is a discussion of a number of approaches to the pricing of access to networks that are either used in practice (for instance in telecommunications), or are supported by economic analysis. All except the last approach are complementary to each other in the sense that each may be optimal under different industry or regulatory circumstances.
	Marginal cost pricing
Allocative efficiency is achieved by pricing goods and services at their marginal (social) costs of production. This principle remains valid in a wide range of circumstances and is not confined to perfectly competitive markets. In industries characterised by economies of scale and scope, such as transmission, marginal cost pricing does not cover the fixed costs of production, unless supplemented by lump-sum transfers or fixed payments (e.g. a two-part tariff). 
	
Ramsey pricing
Ramsey pricing sets the prices of products so as to minimise the welfare losses from deviating from marginal cost pricing, whilst covering fixed costs. Ramsey pricing is not widely used in practice, however, despite its ‘second-best’ properties, because: 
•	it requires detailed knowledge of demand (and cross-) elasticities, as well as cost conditions; and 
•	Ramsey prices may sometimes exceed stand-alone costs, and hence result in inefficient entry. 
In the context of network pricing, Ramsey pricing is also likely to be considered discriminatory. For instance, British Gas pursued a network pricing policy where customers with alternative energy supply options or the ability to switch between electricity and gas would be charged less for gas delivery services than users without such facilities. This pricing approach was successfully challenged before the regulator. 
	The efficient component pricing rule (ECPR)
ECPR focuses on the opportunity costs to the dominant incumbent firm of providing access to its rivals. In brief, the rule states that the price of access should equal the direct or incremental costs of providing access to competitors, plus any opportunity costs incurred by the incumbent (i.e. foregone contributions to common costs and foregone profits). Recent research has shown that while ECPR is optimal in certain circumstances, it is not a generally valid access pricing rule. Where this has been applied in the context of telecommunications access in New Zealand, a key criticism was also that ECPR permits the incumbent network provider to pass on the costs of existing network inefficiencies. 
	Fully allocated (or distributed) pricing
Fully distributed or allocated cost has been a standard regulatory approach to network pricing, but one that is not much recommended by economists. Fully distributed costs for a service may be defined as the direct or incremental costs of providing the service, plus a share of the common or joint costs incurred. These can be calculated either on the basis of historic costs or current costs, but often do not reflect underlying market pressures.

There are numerous methods for determining the shares of common or joint costs attributable to any particular service. While some of the cost allocation techniques that have been developed in more recent years (such as activity-based costing) are a considerable improvement on those traditionally employed, a full allocation of costs remains, to some extent, arbitrary. 
4.1.3	Long term (investment) efficiency
In the long run, the problem that transmission prices should ideally address is complex. Transmission prices that support dynamic efficiency objectives should encourage the construction of generation and transmission assets, so as to minimise the overall cost of providing electricity supplies to customers. That is, ideally the investment process should recognise the extent to which generation and transmission investment are substitutes and complements. 
Dynamic efficiency objectives also have implications for institutions and governance. If transmission prices cannot achieve dynamic efficiency objectives, defining the roles of bodies undertaking network planning and investment becomes increasingly important. 
	Institutions and governance
The objective of investment efficiency has wider implications for the role that various institutions play in the planning process and governance provisions. The example planning problem referred to in Section 2.3 illustrates that minimising the least-cost investment path of the ESI is a complex coordination problem. 
If such coordination could be shown to have occurred in the past and have worked well, it could be argued that integrated network planning by a TNSP would lead to substantial efficiencies. A number of commentators, including Hogan, would argue that this has not been the case, and that transmission utilities have not invested efficiently, have not undertaken coordinated planning, and have not pursued appropriately ‘market-oriented’ longer term planning objectives. This debate is crucial to moves away from traditional forms of regulation for TNSPs to an environment where users have a greater say in determining transmission investment. Such a change in focus also has implications for transmission pricing, since proponents of the market model would argue for a framework where users directly pay for the assets they require. 
	
Regulated approach to investment 
The regulated model for providing transmission services focuses on the monopoly management of transmission operations, investment and the recovery of associated costs via a set of charges that, in effect, represent more or less distortionary taxes. The TNSP is obliged to provide transmission services for all users, and in return users achieve some form of (more or less well-defined) access rights to the network. 
The transmission investment model being implemented in the NEM essentially represents a regulated model. Network planning and augmentation substantially remain the prerogative of TNSPs and inter-regulatory bodies, such as the National Electricity Market Management Company (NEMMCO). Given appropriate price or other regulation, the TNSP should make efficient investments or enter into contracts with market participants to remove or manage transmission limitations. 
Under traditional regulatory rules, network plans rely on long run forecasts of the timing and location of supply and demand for power. This traditional approach results in a powerful monopoly and raises concerns about governance issues. As a general rule, it is unlikely that the regulator will possess sufficient technical and system information to determine, whether network augmentation for growth or security reasons is required. In turn, private sector industry participants tend to rely on the activities of the TNSPs, without necessarily a great deal of insight or input. 
	Market approach to investment 
The market approach to transmission pricing relies on efficient spot market prices to determine the cost of short run transmission services and a definition of property rights in return for undertaking network investment. Efficient nodal prices generate locational prices which incorporate the combined effect of generation, losses and congestion. However, these short term market arrangements do not address objectives which relate to providing price stability for market participants, cost recovery for the shared network and for ensuring that overall system expansion is least cost. 

Several proposals for transmission access and corresponding payments in a market framework have been developed. The most well-developed proposals centre on the development of transmission congestion contracts (TCCs) which would be assigned to users in return for undertaking network investment. These types of arrangements rely on an important aspect of nodal pricing in the energy market – the accumulation of rentals. That is, if prices between nodes or regions reflect transmission losses and the effects of congestion, additional funds are collected in the course of the settlement process. At least in spirit, the market approach relies on market participants’ private incentives to undertake investment in the network. In return market participants would obtain TCCs to lock in future network rights.
The implications of TCCs as a basis for financing private network investment is discussed in detail in Section 6.3. However, it is difficult to see how information asymmetries and regulatory intervention can be removed, even under the alternative ‘market model’ designed around network rights, such as TCCs. The emerging consensus in the literature is that such investment incentives are likely to be undermined by the existence of network externalities arising from loop flows, and that the light-handed regulatory approach which was originally anticipated is unlikely to materialise in practice. 
4.2	Cost recovery
Transmission grids are highly capital-intensive and capital-related costs form the overwhelming part of transmission costs. Sunk cost recovery objectives can be supported on efficiency grounds, since failure to do so can undermine economic efficiency by raising the cost of capital to electric utilities above the competitive level, or by creating an enduring shortage in investment. 
4.2.1	Revenues from short run pricing
Section 4.1 referred to losses and congestion rentals arising in the course of efficient spot market operations. Such rentals are also expected to arise in the course of trading in the NEM. 
When the theory of spot market pricing was first conceived, it was thought that under optimal network expansion, network revenues from marginal cost pricing would suffice to recover the fixed costs of the shared network. 

However, in practice revenues from short term losses and congestion fall well short of recovering the costs of network investment (Figure 4‑1).
Figure 4‑1: Cost recovery from short--run transmission charging
Country	Approximate recovery of fixed network costs from rentals	
New Zealand	10%	
Norway	17.2%	
Chile	10%	
Bolivia	3.6%	
Estimate US	5-20%	
Queensland	24%	
Sources:	Read, Transmission Pricing in New Zealand, 1997; Glende & Westre, Transmission Pricing in Norway; Rudnick, Presentation: Latin American Experience in the Restructuring of Electric Power; 1998. Federal Energy Regulatory Commission, The Recovery of Fixed Transmission Costs, 7 December 1997, NARUC-DOE National Electricity Forum; Powerlink.
There are some more obvious reasons for the observed short-fall: 
•	reliable transmission capacity is characterised by lumpy investment projects and substantial economies of scale, so that a degree of ‘overbuilding’ tends to be cost-effective; and 
•	revenues from line rentals decline following an investment, if losses and congestion are reduced. 
But transmission networks may also be ‘overbuilt’ from a wider economic point of view. In theory, transmission investment should be undertaken, until it is more costly than savings in generation costs, in terms of losses and congestion. In practice, the decision whether or not to invest is taken on the basis of reliability criterion, not according to expectations about future electricity supply costs. Indeed, in most electricity spot markets, including the NEM, the price of electricity is capped, and the cost of unserved energy is never revealed in the market. That is, investment criteria focussing on the future costs of energy cannot operate efficiently in the first place. 

There is therefore no reason why investment that is undertaken on the basis of strict reliability criteria (and an underlying notion of the value of lost load) should be consistent with signals arising from the energy market. The short-fall between those rentals which should theoretically accumulate and actual funds can be interpreted as indicating a discrepancy between reliability targets which are administratively determined (such as those set out in the Code) and those which would emerge in a more market driven outcome. 
The revenue short-fall arising from sole reliance on rentals has implications for transmission pricing. Given a set of reliability targets which TNSPs are required to meet, transmission pricing structures which address short run efficiency objectives need to be supplemented by additional mechanisms to recover the overall costs of providing transmission services. 
4.2.2	Second best pricing
The move away from charging only for marginal losses and network congestion entails a move from first to second best pricing which must meet a total revenue requirement. While efficient prices should reflect the costs of the service being provided, cost attribution is problematic in shared electricity networks, because of economies of scale and scope. In practice, the implication is that:
•	cost attribution ‘rules’, such as those proposed by Baumol Willig provide little guidance on the appropriate structure of prices; and
•	it is unclear which users (e.g. generators or customers) should pay, and on what basis, for the use of network services, since all users make use of virtually all assets embedded in electricity networks, at least to an extent.
4.2.3	Dimensions of second best charging
The broad pricing structures described below can differ across a number of dimensions, reflecting different objectives of transmission pricing. Each of these is associated with possible sources of inefficiency. How serious these short-comings has to be assessed with reference to other, including efficiency objectives of the pricing scheme. 
	Fixed versus variable charges
Variable charges – such as $/kWh charges – are simple to implement. At the same time, variable charging discourages electricity consumption and hence the utilisation of existing network assets. 

Given that the majority of the costs of transmission networks consist of fixed capital costs, fixed transmission charges could be considered to reflect the structure of costs. Fixed charges also remove incentives to modify electricity consumption in response to transmission charges. However, largely fixed charges may be considered inequitable and may discourage users with declining electricity demands, even if there is excess capacity in the network. 
	Locational charging
Locational transmission charging aims to signal the costs of their locational decisions to network users, generators and customers alike. Given the large distances which networks must traverse, combined with substantial costs of network expansion, the extent to which locational signals can be incorporated in transmission prices is an important issue in Australia. 
Locational charges to generators or customers should be interpreted in a dynamic context, that is, where charges to existing users perform a signalling function for future users (this also referred to as the ‘distance problem’):
•	By definition, existing users of networks have made their locational decision. Like a tax, the sunk costs of network investment should then be recovered in a least distortionary way, preferably in a manner which does not affect consumption decisions. 
•	However, if access charges to existing users are averaged, this may send inappropriate longer-term signals to users contemplating locating in the network, in turn resulting in poor location decisions of generators and loads poor grid investment.
However, locational pricing poses both conceptual and implementation problems that require compromises in practice. 
	The economic problem
The following discussion applies both to customer and to generator locational charges and is intended to set out the difficulties in defining locational charges. 

In Figure 4‑2 below, Generator 1 has the choice of locating either at A or at B in the transmission network. Fuel costs are cheaper at B, but the cost of deep network augmentation more than makes up for this advantage. Conversely, fuel is more expensive at A, but only limited network augmentation is required. In fact, if Generator 1 were to optimise over both parameters (fuel versus network costs) it would locate at A. An ‘ideal’ locational charge would then aim to ensure that Generator 1 takes into account the higher network costs at B and locates at A. 
Figure 4‑2. Generator location decision

Source:	London Economics. 
This example highlights that, in order to be effective, a locational charge would have to accurately reflect the costs which an individual user imposes on the network, in terms of how it affects network transfer capabilities and investment plans. In effect this would be some version of long run marginal costs (LRMC). 
An ‘effective’ locational charge would then take actual LRMC costs at each node as a charging basis. This would mean that:
•	such a charge would reflect the actual costs of deep network augmentation and the new user could be guaranteed to locate at the ‘correct’ node; 
•	depending on wider network effects, payments would have to be made to new users, for instance, if a generator location decision reduced the need for network augmentation; and
•	it is unclear how economies of scale in network augmentation should be reflected in the final charge.

This last point implies that a cost-reflective locational charge raises equity concerns that essentially arise as a result of economies of scale in network investment and from the transient nature of the locational signal. Assume that in Figure 4‑2 network augmentation has taken place upstream of A, but because of economies of scale, capacity has been expanded by substantially more than what would be required by Generator 1 alone. Generator 1 could be required to pay the actual LRMC cost of its location decision, which could be: 
•	the cost of the entire network augmentation, including whatever excess capacity may be required to build it economically; 
•	only that part of network augmentation which is actually required for the generator and another party (presumably the TNSP) would have to finance the remainder of the investment; or
•	some form of rebate system would have to be introduced to ensure that the first generator would be compensated by later users of the augmentation. 
Each of these alternatives has specific draw-backs, since they are likely to:
•	impose some costs on the network operator (and hence indirectly on customers);
•	impose higher than direct costs on the generator; or
•	introduce a significant degree of additional complexity. 
	The practical problems
Given the difficulties of attributing fixed network costs to users, many jurisdictions, including the authors of the Code have created provisions for charging transmission customers and/or generators an approximate version of locational LRMC costs. The application of a standardised charge implies that locational charges are no longer cost-reflective, but represent indicative signals. Such charges cannot then strictly ensure that customers and generators moved to the ‘right’ location. To a lesser or greater extent, these charging approaches also suffer from common implementation problems. 
	
Stability
By definition, locational charges vary over time, as the network develops and investment requirements shift. Indeed, a locational network charge would be expected to change, following the locational decision of a user. This tends to be less of an issue with customer based locational charges where load growth tends to take place on an incremental basis, and transmission charges evolve in one direction over time. However, future network costs may change significantly with the location of an additional generator. It is then not clear why existing generators should be charged time-varying locational transmission charges which they are not in a position to respond to. 
In Figure 4‑3, a new generator, Generator 3, might affect the locational charge of other generators to a limited extent. However, if Generator 4 decides to locate at the same node as Generator 1, this will very substantially affect Generator 1’s locational charge, as the remaining capacity of the link is used up. The implication is that the LRMC charge to existing generators may increase substantially, reflecting the fact that the decision to locate by another generator will require substantial augmentation. Since Generator 1 has already made its locational decision and its costs are sunk, it has no control over such increased locational charges.
Figure 4‑3. External effects of generator location decisions

Source:	London Economics. 

This instability problem is compounded, if locational charges must meet a total revenue requirement. The arrival of a significant new user anywhere in the network will then require a rebalancing of all charges. 
	
Information requirements
Locational charges raise governance and information issues:
•	Information requirements. Any locational network charge confers a substantial responsibility on the TNSP or the relevant planning body to forecast accurately, and to apply these forecasts, including projected costs of network augmentation, scaling assumptions and market (dispatch) outcomes, in a transparent and non-discriminatory manner. In practice, the complexities inherent in network planning are such that external monitoring/scrutiny of these plans is difficult. 
•	Forecasting and governance. It is questionable whether even well-informed network planners are in a position to anticipate long term developments in the ESI, without at the same time playing an unacceptable role in determining the future structure of the industry. 
	Peak versus energy charges
The arguments in favour of peak based charging or cost allocation methods arise, since transmission networks are dimensioned on the basis of reliably serving peak system demand. Network asset costs are related to peak capacity, and if costs must be allocated in some way, an allocation on the basis of contribution to peak demands may be appropriate. The exact form of a peak charge can vary:
•	The peak can be defined as the single highest half hour of demand or supply over a number of years, within each year, or the average demand/supply over a small number of half-hours within the year. An energy charge is then simply the peak charge averaged over all half-hours. 
•	Regional aspects can also be incorporated in peak charging. A peak can be defined as the contribution to system peak demand or regional peak demand, the customer’s own peak or the peak for each supply point servicing a customer. 

The arguments against a peak charge are that:
•	peak-based access charges discourage utilisation of existing assets, if there is excess capacity in the network; 
•	whereas a per kWh charge raises the marginal cost of generation across all generators, a peak (generation or demand) charge may disadvantage some generators – mid-merit and peaking plant – more than others;
•	pure peak demand charges ignore distance related fixed costs which are material in the Australian ESI; and
•	peak electricity demands are price responsive, suggesting that charging for peak costs via the energy market – as reflected in spot prices – rather than through peak transmission charges may be more appropriate. 
In contrast, an energy based access charge encourages under-consumption of electricity (as any other tax does), but is likely to have fewer adverse effects in the energy market.
	Averaged versus ‘nodal’ charges
Fixed and variable charges can be either averaged over a wide area, or differentiated by region, or even by consumer or by node. The range of charges includes wide area or local area postage stamping and distance-based charges.
Postage stamped access charges have the advantage of simplicity. Cost-reflective or distance based tend to discourage generators and customers from locating at far ends of the grid, but: 
•	tend to reduce trade, even with uncongested lines; 
•	are potentially unfair, since it is not possible to accurately track loads (loop flows); and
•	are difficult to verify, since they typically rely on information that is internal to the TNSP. 
4.3	
Other objectives
Efficiency and cost recovery are key pricing objectives, but must be balanced against a number of other objectives. Their relevance is discussed in Sections 5 and 6 which review NEM provisions and the overseas experience. 
4.3.1	Non-discrimination
In theory, network charges should not discriminate between network users with similar characteristics in terms of the costs (or benefits) they impose on the network. To be non-discriminatory, the pricing structure should fulfil two objectives:
•	it must offer the same treatment to users facing similar circumstances; and
•	it must contain no non-tariff provisions which give a built-in advantage to any transmission user of a particular class.
In this context, the overlap between transmission and distribution pricing should be considered. In practice, the delineation between transmission and distribution assets and network is often unclear, and users have choices about locating at one or another level in the network. The pricing structure should ensure that customers or generators do not have uneconomic incentives for locating at one level and not another. 
4.3.2	Simplicity / transparency
The issue of transparency of charges is related to that of simplicity. A complex charging system is likely to be less easily understood by market participants, and any signals that it is intended to send may not be recognised until after the event. Complex or unpredictable charges may represent a barrier to entry for new or smaller industry participants, and may increase the transaction costs of market participants. 
Simplicity also relates to the costs of implementation. A pricing approach which raises severe technical difficulties – in terms of development costs or the costs of ‘experimenting’ until prices reflect what is considered to be the right outcome – imposes costs on market participants and system operations. 
4.3.3	
Stability 
Stable network charges are likely to be desirable from the perspective of network users:
•	customers (and billing agents) will favour prices that are reasonably stable, or at least predictable, from year to year, for planning and billing purposes; 
•	unpredictable or highly variable charges may undermine the ability to attract finance for projects, particularly in the context of long-lived generation investments.
The second point is unlikely to be relevant for small customers, but may be an issue for large users where transmission costs represent a larger proportion of overall network costs.
Similar arguments apply to network owners and private network investors. Transmission network assets are long-lived, and network owners require certain revenue streams to justify such investments. 
However, these objectives must be balanced against dynamic efficiency objectives:
•	where customers and generators are concerned, longer term stable charges may not reflect the real costs of the network; 
•	in terms of their signalling effect, network charges may be swamped by highly variable generation costs; and
•	for TNSPs or investors, against the incentives that guaranteed cost recovery are likely to create. 
4.3.4	
Flexibility
Section 3 of this report reviews the existing structure of the Australian HV network. Future trends in infrastructure and the use of the network are difficult to forecast with certainty. However the substantial changes that have occurred in the Australian ESI in recent years are likely to have implications for network investment:
•	Depending on the interconnections which take place, there is a requirement for new generation capacity in different parts of the NEM. This may require network augmentation and, in turn, clarification of who should pay for new investment and any corresponding access rights. 
•	The system to date has not been engineered for wide-spread trading across regional boundaries, and further network augmentation is likely to be required to accommodate such trades. 
•	More generally, increased participation in the NEM of privately owned market participants is likely to place greater pressures on information provision and governance arrangements. 
These issues have implications for the types of access charges that are likely to be appropriate to signal the costs of substantial network augmentation, and also suggest that a greater clarification of corresponding rights of market participants for connection and assets is required.
4.4	Summary
4.4.1	Efficiency
	Productive efficiency 
In the short term transmission prices must address the least cost dispatch problem, that is to reflect the costs of using the transmission networks in order to minimise the overall cost of generation to meet a given level of demand. These costs take the form of energy losses and changed energy costs as a result of network constraints. Spot market based on the nodal pricing approach achieve this objective, albeit with increased complexity. Minimising the fixed costs of the network in the longer term has traditionally been addressed by regulation.
	
Pricing efficiency
Efficient prices should reflect costs and be free of subsidies. Pricing efficiency presents a central problem in transmission pricing, since general network cost allocation rules provide little guidance on what is an appropriate pricing outcome. 
	Investment efficiency
Network investment has been traditionally undertaken by TNSPs in a regulated environment. In turn, users are typically charged more or less averaged transmission tariffs. This raises the question, whether efficient investment can be encouraged by a more decentralised form of transmission pricing, such as through a form of contract networks. 
	Cost recovery
The costs of the transmission network are largely fixed and sunk and are, in practice, substantially greater than revenues accruing through short term energy market transactions. Loop flows in the meshed network undermine attempts to allocate costs to specific users or lead to unacceptably large price ranges within which prices to network users may be considered subsidy free. A ‘second-best’ pricing approach must be found to recover the fixed costs of the network. 
The recovery of fixed and sunk transmission costs raises contradictory objectives: 
•	from an efficiency perspective, the preference would be to divorce the charge from usage levels, since costs are not related to usage; 
•	this would imply some fixed cost or Ramsey pricing recovery mechanism which, in their pure form, are likely to be considered inequitable and discriminatory; and
•	since transmission prices must then focus on other characteristics of users, this result in separate sources of inefficiency. 
This explains the wide variety of access charges applied across jurisdictions. Transmission charges for cost recovery are typically determined with reference to a specific network and ESI and with reference to the other important objectives listed in this chapter. 
4.4.2	
Other objectives
Efficiency and cost recovery are key objectives in transmission pricing, but must be balanced against other objectives, including non-discrimination against certain market participants, simplicity in implementation and transparency to users, stability to support long-term investment decisions and flexibility to support changing market environments. These objectives represent key criteria for judging the appropriateness of various charges for achieving efficiency and cost recovery objectives. 

5.	Short run charging for transmission in the NEM 
Sections 5 and 6 describe the provisions for energy and transmission pricing in the Code, and how these have been implemented to date. These provisions are reviewed in the context of the objectives listed in Section 2 and the Australian HV network. 
Section 2 highlighted that to ensure the least cost operation of the ESI, prices must reflect the short run costs of transmission. Pricing rules in the energy market relating to the treatment of losses and inter- and intra-regional network constraints are an integral part of the overall framework for transmission pricing. However, revenues accruing from short run transmission pricing signals do not recover the costs of the shared network. A second-best pricing approach to recover sunk network costs then needs to be adopted, and Section 6 reviews how this has been implemented in the NEM. 
5.1	Regional structure of the NEM 
The NEM model for energy pricing focuses on the marginal cost of energy. When the NEM was developed, it was considered that while marginal pricing of delivered energy would provide the best support for economic efficiency objectives, complete implementation of this principle would require arrangements akin to a nodal spot price market. Such an approach was considered too complex, and a modified framework was subsequently adopted.  
The proposed NEM then represents a simplification of a nodal pricing framework. The impact of losses and significant constraints is reflected in energy dispatch and pricing by separation of the NEM into a number of regions. Each region includes one reference node at which intra-regional and inter-regional generator bid prices are compared. Regions were created to permit electricity prices to vary in different areas, principally to reflect constraints on the free transfer of electricity. Regions are connected by transmission lines, or interconnectors, with limited capacity.

Conceptually the market is represented by a small number of regional reference nodes (RRNs) at major demand centres, linked by a notional single line, to form a linear chain (Figure 5‑1). Each region has a single RRN where all electricity trading is assumed to occur, and where the electricity price for a particular region is set. Market participants’ bid and offer prices are referred to the central reference node using transmission marginal loss factors (MLFs) and distribution loss factors to determine comparative prices for dispatch and pool settlement purposes.
Figure 5‑1: Pricing framework for the NEM

Source: 	Review of the Proposed Inter-Regional Trader Framework for the Australian National Market, NGMC, 1995.
5.2	Price determination at nodes
Once the generator dispatch order is determined, the bid or offer price of the last unit dispatched in that trading interval sets the pool price at the reference node. The price at each other transmission connection point is then determined from the price at its reference node and vice versa. Energy prices across RRNs differ when there are inter-regional network constraints, but also as a result of network losses. Energy prices at nodes within a region are determined according to fixed formulae in relation to the RRN. 
5.2.1	
Treatment of losses
In the NEM losses are approximated via static and dynamic loss factors. 
	Code provisions
The Code requires all generator bids to be adjusted for marginal losses to ensure that generators are dispatched optimally. Therefore: 
•	first, all bids are adjusted relative to their local RRN on the basis of static, that is, fixed intra-regional marginal loss factors (SLF); then 
•	all bids are adjusted relative to the primary national pricing node that is defined as being Sydney, using dynamic, that is time-varying, inter-regional loss factor equations. Each inter-regional link is assumed to have a (quadratic) loss function which, in principle, represents the losses between reference nodes. 
SLFs represent an approximation of actual losses in two key respects: 
•	loss factors as defined in the Code are essentially backward looking (except in Queensland where they have been defined for future years); and 
•	SLFs are calculated as the average of marginal losses across the previous year.
Currently all jurisdictions in the NEM have put in place derogations to ensure that jurisdictional bodies, rather than NEMMCO, would determine SLFs. The objective appears to have been to limit intra-regional price variations in the cost of electricity. 
Because of the variability of flows between regions, it was concluded that a single ‘static’ loss factor would not be appropriate between inter-regional reference nodes. ‘Dynamic’ equations have therefore been determined to reflect losses between RRNs. These are calculated for each dispatch interval from major parameters, such as power flows on the interconnect, regional loads and regional generation. The effect of the dynamic inter-regional loss factor equations is that spot market prices between two RRNs always differ on a time-varying basis, by an estimate of marginal transmission losses between the two regions. 
	
Discussion
Accurate short run pricing for losses is important to ensure the efficient dispatch of generation plant and the least-cost short term operation of the ESI, as well as for signalling the ‘real’ cost of electricity to customers. The extent of averaging that is inherent in these pricing arrangements has benefits for market participants, in terms of greater simplicity and stability of the resulting cost signals. Against these benefits must be balanced the costs of resulting inefficiencies.
The NEM energy pricing arrangements represent an approximation of exact market outcomes to manage the trade-off between:
•	the theoretical efficiency properties of a nodal spot pricing market; 
•	the draw-backs associated with nodal spot market pricing, including:
-	complexities in price determination and greater localised price uncertainty for retailers and customers; and
-	implementation difficulties and costs, in terms of software and metering requirements. 
Whether this simplification is appropriate can be assessed with reference to energy market modelling to compare the outcomes of a full nodal pricing model with those which would be observed under the NEM pricing rules. Where there are significantly different dispatch and pricing outcomes, customer responses would also have to be determined. The extent of averaging which is inherent in the system of SLFs may be a concern for Queensland, where the evidence in Section 3 suggests that losses are high and vary significantly across different parts of the grid. This may translate into greater time-of-day variability.
5.2.2	Treatment of congestion 
The emergence of transmission constraints may prevent electricity from flowing freely to regions or parts of the network, where excess demand is highest. A constraint then arises, if the potential power flow across the interconnect (arising from dispatch) exceeds the technical capability of the electricity infrastructure. In the NEM plant is dispatched according to a national merit order. However, when transmission lines become constrained, optimal dispatch is no longer feasible. 

Inter- and intra-regional constraints are relevant in the context of generator market power. The existence of generator market power in different regions of the NEM has been investigated in a number of studies which have highlighted concerns about likely market outcomes in South Australia, New South Wales and in Queensland. If a market is characterised by a relatively small number of players (producers and/or customers) the pricing and production decision of one participant can affect the market price. Where a generator can sustainably affect the market price they can be regarded as having market power. For the generator, this type of behaviour translates into excessive (greater than economic) profits.
Constraints limiting power transfers separate a larger, more competitive integrated market into a series of smaller regional markets, in which individual generators have greater opportunities to influence price outcomes in the spot market. 
	Inter-regional constraints 
The NEM rules distinguish between inter-regional and intra-regional congestion. 
	Code provisions
When inter-regional constraints occur, the interconnected system dislocates to form a group of regional markets, and prices differ at the respective RRNs. Low priced generation in the exporting region will produce less than in the absence of the constraint, while high priced generation is dispatched and sets the system marginal price (SMP) in the importing region. The regions of the NEM are then characterised by different SMPs. However, a single spot price, determined at the RRN continues to apply within each region. 
	
Discussion
Inter-regional congestion results in price dislocation between the regions of the NEM. In contrast, in a full nodal market, congestion is reflected in complex knock-on effects, referred to as a ‘spring washer’ effect, where spot prices in the vicinity of a constraint may be less or higher than in the unconstrained case. The inter-regional approach adopted here represents a simplification and, in principle, the same analysis as for losses should be undertaken, in order to assess whether market outcomes are likely to be significantly different under a nodal pricing system. 
	Intra-regional constraints
	Code provisions
Intra-regional constraints can affect regional generator dispatch, and hence the regional energy price, but do not create intra-regional electricity price differentials, since there is only one regional price which applies at the RRN. When intra-regional constraints occur in the NEM, the spot market price is determined by the marginal value of supply at the RRN. The marginal value of supply is given by the bid of the generating unit which would be used to meet an incremental increase in demand at the RRN.
Figure 5‑2 illustrates this. Consider a single region model with a transmission constraint between two areas, A and B. There is a 20MW generator in area A and a 50 MW generator in area B. Total demand in the region is 30MW, 15 MW in each area. Generator A bids $20/MWh, and generator B bids $10/MWh. Assume that both generating units have static loss factors equal to 1. Suppose that due to a transmission outage there is a constraint on the flows on the transmission line between areas A and B which limits the flows in either direction to 10MW. The RRN is in area A. 
In the absence of the constraint the cheapest generator would be used to meet demand. Generator B would generate 30MW and would set the pool price at $10/MWh. The energy generated by generator B would be used to meet 15MW of demand in area A and 15MW of demand in area B. However, the transmission constraint prevents more than 10MW being exported from area B to area A. Generator A will therefore need to produce 5MW to ensure demand in the area A is met. Generator B’s output will need to be reduced by 5MW to 25MW.

Figure 5‑2: Example of intra-regional constraints

Source:	London Economics. 
In Figure 5‑2 the spot market price in the NEM would be set by the bid of the marginal unit generating unit used to meet an increase in demand at the RRN. Since the RRN is in Area A, and the transmission line connecting Area A and Area B is constrained, any increase in demand at the RRN would have to be met by generator A. According to this methodology, the price would be set by the marginal generator at the RRN, that is generator A at 20 $/MWh.
This price outcome would be different, if the RRN was located in Region B. In this case: 
•	supply in Region A would still be constrained, and Generator A would be required to produce 5MW to meet the short-fall; 
•	generator B in Region B would still generate 5MW less than it would have done in the absence of the constraint; 
•	the spot market price would be set by the unconstrained generator in Area B, that is generator B at $10/MWh; and
•	in either case, actual dispatch is always unchanged. However, market prices change, depending on the location of the RRN.
	
Discussion
The Code provisions relating to intra-regional congestion limit the extent to which the short term value of transmission capacity is signalled to users. Given that intra-regional constraints are, by definition, infrequent, this approximation may be justified, in comparison to the costs that intra-regional price differences are likely to impose on retailers and large customers purchasing energy at a greater number of local spot and contract markets. Whether the criteria for increasing the number regions as set out in the Code reflect an appropriate balance would have to be assessed with reference to the additional costs that might arise, if the threshold for regional separation were modified. 
The assumption that the regional spot market price in the event of intra-regional congestion should be determined by a generator located near the reference node appears poorly founded. This approach:
•	implies that the regional spot price may or may not reflect the costs of the marginal generator, may leave some generators unable to cover their variable costs and others profiting from ‘wind-fall’ gains; and 
•	encourages gaming by the generators who are likely to be dispatched to mitigate a constraint.
5.3	Settlement residues 
In the course of trades across the network, rentals accumulate from two sources, corresponding to the causes of differences in spot prices. Congestion rentals arise when transmission links are constrained and prices separate, while (inter- and intra-regional) losses rentals are present at all times. The year-on-year magnitude of the settlements residue varies, and to date estimates for the NEM have not been available. In the case of inter-regional congestion and losses, these accumulate to form the inter-regional settlement residue (IRSR). 
5.3.1	
Code provisions
According to Section 3.6 of the Code NEMMCO is required to develop and publish a methodology for the accounting, allocation and distribution of intra- and inter-regional settlements residues. This methodology is to be based on the principle that settlements residues will be allocated and distributed to the appropriate network service providers (NSPs), and used to offset network service charges. 
5.3.2	Derogations
The development of a framework for inter-regional hedging takes place in the context of a number of derogations which have been put in place in the jurisdictions:
•	any New South Wales IRSR allocation will, in the first instance, be directed to the Snowy Trader to support hedging contracts for power purchase in New South Wales; 
•	the Victorian derogation requires the Victorian share of the IRSR to be paid to a State body and then allocated first to the SECV and then to Snowy Hydro Trader, with the residue going to the NSP; 
•	the most recent South Australian derogation provides that the South Australian allocation of the IRSR should be paid to a Government body prior to any auction or other sale. The body will distribute the residue for the benefit of franchise and contestable customers as follows:
-	a proportion not exceeding 50% of the total amount of the settlements residue will benefit franchise customers; 
-	the government body will contribute the balance to an auction of the IRSR; and 
-	the proceeds from an auction will be distributed to benefit of contestable customers. 
5.3.3	Recent developments 
The IRSR has historically been viewed as a source of funds for creating IRHs, to manage the risks associated with inter-regional trade. It can be interpreted as a ‘natural hedge’ against inter-regional price differences, since, at least in theory, revenues collected match regional price differentials that arise in the event of constraints. IRHs derived from the IRSR would lock in a form of rights of access to markets in different regions, since holders of IRHs are not exposed to price risks arising out of inter-regional congestion. 

Since the Code was drafted, a series of proposals have been put forward for applying the settlement residue to create hedging instruments for inter- and intra-regional access rights, and the process has been a lengthy one. In January 1998 NEMMCO convened an industry working group – the Inter-regional Hedging Working Group (IRHWG) – to develop broadly supported proposals for inter-regional hedging instruments. 
Within the working group, four subgroups were established to:
•	design the contract instrument to be issued by NEMMCO in the short term, based on the IRSR; 
•	design the short-term auction mechanism for NEMMCO to issue these contracts;
•	design appropriate governance arrangements for this short-term partial solution to the inter-regional hedging requirement, recommend relationships with network service providers and the system operator, and deal with regulatory issues; and 
•	prepare a submission regarding the longer term treatment of facilities to enhance inter-regional hedging.
The IRHWG was considered to have largely completed its terms of reference at the end of 1998. It is intended that settlements residue auction (SRA) will take place, as an interim arrangement, instead of the inter-regional hedging mechanism that was removed from the Code as part of its authorisation. It is intended that six basic hedging products will be for sale – corresponding to directional hedges between the three existing key interconnectors. The design features of the auction process have also now been clarified. 
5.3.4	Discussion
The process of implementing formal mechanisms for managing the risks associated with inter-regional has to date been slow. Even given the conclusions now emerging from this process, it is unclear to what extent market participants will have access to inter-regional hedging instruments:
•	jurisdictional derogations remain in place which effectively eliminate a proportion of funds from the IRSR for hedging purposes; and 
•	important implementation questions remain to be clarified 
5.4	Rights of access
The discussion about network access rights is closely linked to the application of settlement residues, but is also has important implications for network investment and the ability of ESI market participants to finance investment. 
Issues about rights of access arise in the event of inter- and intra-regional constraints in the NEM. In either case, the dispatch of plant is altered from what it would have been in the absence of the constraint. Access rights have central implications for investment, in terms of:
•	the nature of the obligation by TNSPs to connect generators and the access rights that this bestows on generators; 
•	longer term incentives of NSPs for network augmentation, given rights of access by market participants; and
•	the viability of generators who face the risk of being constrained on or –off and may fail to cover their costs.
5.4.1	Inter-regional hedging
Given the regional structure of the NEM, it is common practice to distinguish between inter- and intra-regional rights of access. Inter-regional congestion results in price dislocation between the regions of the NEM. This is a source of risk for generators and retailers and may restrict inter-regional trade and competition. Where inter-regional constraints are concerned, it had been envisaged that financial instruments would emerge to help market participants manage associated market risks. However, the discussion in the context of the IRSR highlights that this process has been a slow one. Key implementation problems related to:
•	difficulties in defining network capacity; 
•	the fact that the inter-regional trader would be left to manage a considerable degree of pure insurance risk; and
•	the obligations, as well as the risks and commercial implications on the part of TNSPs. 
5.4.2	
Firm access
Access issues also arise in the context of intra-regional constraints where this is referred to as ‘firm access’. Implications for investment arise from the frequency and materiality of network constraints, in particular:
•	how these are addressed in the transmission pricing framework, for instance whether it is possible to contract for inter- or intra-regional access to customers; 
•	how these are reflected in prices in the energy market, that is which plant determine prices in the even that there are intra-regional constraints. 
	Code provisions
Generator firm access rights have not been clarified in the Code:
•	Chapter 6 states that generators may agree as part of their connection agreements to pay for transmission use of system (TUOS) services or may purchase firm access services. Other than referring to a risk premium that must be paid, the Code is not specific about the scope or price of such firm access provisions. 
•	Chapter 5 provides that:
-	NSPs are required to provide access to connection applicants, subject to maintaining the security of the network and quality of supply; and
-	the NSP must provide an offer to connect to meet the reasonable requirements of the applicant, including without limitation, the location of the proposed connection point and the level and standard of power transfer capability that the network will provide.
•	Chapter 5 also refers to payments by generators of use of system charges for augmentations that may be required. However, it is unclear under what circumstances a connection applicant is required to pay for network augmentation, and how such costs would be determined. 
•	
Chapter 5 furthermore determines that an NSP and a generator should negotiate to reach agreement on compensation to the connecting generator, if it is constrained off, and on compensation for which the connecting generator may be liable in the event that its dispatch constrains off other generating units. 
	Discussion 
Where intra-regional ‘firm access’ is concerned, it is unclear, whether the general connection and access rights laid down in the Code will provide sufficient certainty for investors in generation projects, but equally, whether these are likely to be consistent with least-cost ESI expansion. Important provisions relating to network investment have not yet been clarified in the Code, notably the nature of rights and obligations of generators and TNSPs in the context of firm access. Such rights are likely to become increasingly important to support private generation investment. 
Under current energy pricing arrangements, the location of the RRN has an effect on spot market prices and financial implications for generators. How prices are determined also impacts on the extent to which the energy pricing arrangements imply some (financial) right of firm access:
•	Constrained off generators. Generators who are constrained off are not compensated, irrespective of their location. Under current Code provisions, the spot market price will be set by the generator deemed to meet demand at the RRN, if intra-regional constraints arise. If this price is high enough, it may more than compensate a generator for reduced output. If this is not the case, the generator will suffer reduced revenues. 
•	Constrained on generators. Generators who are constrained on are compensated at the spot market price which may be greater or less than their marginal running cost, depending on where they are located in relation to the RRN. 
In either case, there appears to be a significant element of arbitrariness in terms of whether a generator is likely to be advantaged or disadvantaged from intra-regional constraints. It is conceivable that a generator might want to locate so as to exacerbate a constraint, in order to profit from high regional spot market prices (at least in the short term). It is equally possible, that a generator may not locate in a low-cost location, if constraints and resulting market prices elsewhere in the network mean that pool price outcomes are unpredictable. 
	
Competitiveness of regional markets
Firm access issues have wider implications for the competitiveness of regional markets:
•	Incentives for gaming. The focus, for price determination purposes, on a specific plant near the RRN is likely to encourage strategic bidding behaviour on the part of generators. 
•	Availability of contracts for differences. A generating unit which is constrained off may not be able to cover its contractual obligations and is exposed to pool price risks in its contracts with retailers. It has an incentive to enter into fewer generating contracts with retailers than it otherwise would, thereby reducing competition in the contract market. 
•	Incentives to invest. Since generators who are constrained off do not receive corresponding payments, their ability to finance investment through longer term contracts is likely to be reduced. 
	Investment incentives for TNSPs 
The Code provisions regarding firm access have implications for TNSPs’ investment incentives. 
In Figure 5‑3 Generator 1 connects to an existing (radial) HV link to the deep network. The capacity of the generator is greater than the capacity for power transfer to the load centre. If the TNSP is required to connect all new generators and is liable for constrained off payments in the event that the generator is unable to export the capacity it has bid into the Pool, the TNSP has an incentive to undertake network augmentation, where there is a risk of such payments. If such constrained off payments are simply passed through to customers, these in effect carry the cost of locational decisions by a new generator, whether or not this investment is of benefit to them. 
Correspondingly, a new generator has a legitimate interest in ensuring that it will be dispatched and may rely on some form of firm access guarantee to ensure project finance. However, in the scenario described in Figure 5‑3, there are also opportunities for generator gaming. For instance, a generator could consistently bid low in the knowledge that it could never be dispatched, given existing network constraints, and benefit from ongoing constrained off payments. Even if the existing transmission line was upgraded to enable full power transfer by the generator to the load centre, there is no guarantee that a second generator may not locate at the same location, in turn creating a constraint. This raises further concerns about the longer term incentives by the NSP to augment the network. 

Figure 5‑3: Firm generator access: radial network 

Source:	Queensland Electricity Reform Unit. 
In Figure 5‑4, Generator 2 is connected in the meshed shared network. Occasionally the generator is constrained on to relieve transmission constraints in other parts of the deep network. Correspondingly, other generators are constrained off. In effect Generator 2 provides a network service, since the network would have to be augmented in its absence. 
Figure 5‑4: Firm generator access: meshed network 

Source:	Queensland Electricity Reform Unit. 

These two examples highlight a key distinction between circumstances in which generator payments are more likely to be appropriate, and those when they are not:
•	In Figure 5‑4 Generator 2 (and by implications those generators that are constrained off) effectively perform a network service (this service could equally be provided by demand side measures). Generator payments then reflect a trade-off between undertaking network investment or paying higher (generation) operating costs. 
•	In contrast, Generator 1 in Figure 5‑3 is not performing a network service. As a result of its locational decision, it has created a network constraint. It is therefore far less obvious that the TNSP (and by implication customers) should bear the cost of this locational decision, unless the generator pays for such a service.
	Existing proposals for firm access
Existing proposals for firm intra-regional access are linked to the LRMC generator charge, where the original intention appears to have been that:
•	a TNSP would offer firm access rights to the local market to regional generators;
•	such rights would be available to all market participants, and would require the TNSP to publish a price at each existing and future generator connection point;
•	this price would represent the incremental cost of expanding the network to meet additional generation at that location and would be available to any generator wishing to purchase firm access rights, regardless if sufficient capacity was available; and
•	the revenue from these rights would be intended to cover the costs of transmission augmentation. 
It was anticipated that TNSPs would be exposed to a significant amount of pure risk, which would have to be insured against. Firm access rights would then reflect locational incentives to generators. 

This approach leaves the posting of LRMC prices entirely to the TNSPs, with a number of practical questions remaining, including: 
•	the types of network risks which would be covered by firm access rights; 
•	how the TNSPs’ exposure to market outcomes and associated risks would be addressed; 
•	how physical network capability would reasonably be determined in practice; 
•	how a single (firm access) price could be offered to generators, since network augmentation requirements depend on the type of generating technology, running regime etc; and
•	how lumpy investment projects and economies of scale could be incorporated in such a framework, so that costs could be recovered. 
	Combining energy market payments and TNSP/system operator responsibilities
Figure 5‑5 presents an overview of the range of firm access options. These have substantially differing implications for:
•	generators, in terms of the financial risks they face; 
•	TNSPs, in terms of their financial and planning obligations; 
•	costs arising to customers; and
•	the incentives created for the longer term expansion of the network. 
	Option 1: Constraint principles
Option 1 provides for the inclusion of constraint costs in the NSPs’ planning processes, without constraint payments actually being made. At least in theory, this would provide for appropriate planning of the network, but this approach leaves generators financially exposed to constrained on and –off events, potentially undermines the competitiveness of the contract market and the financial viability of existing and new generation projects. This reflects current investment processes in Australia. 

Figure 5‑5: Firm access options
	Option 1: Constraint principles (no constraint payments)	Option 2: Limited constraint payments	Option 3: Unlimited constraint payments 	
TNSP	No specific incentives for TNSP.
Little financial risk for TNSP.	TNSP seeks to minimise payments, unless funding is assured. Incentive for network overbuild.
Financial hardship for TNSPs in the event of severe and unplanned constraint events.	Strong incentive for TNSP to overbuild network to avoid liability. 	
Generator	Financial hardship, if constrained on/off and in unplanned constraint events. Negative incentives for generator investment.	Some generators are compensated. 	No risk for generators.	
Customer	Potentially lowest cost outcome in the short term, but negative investment signals for generators.	Moderate cost outcome for customers, if extreme constraint events are rare.	High costs to customers. Conservative planning will increase costs.	
Planning process 	Outcome reliant on appropriate planning. 	Incentive to balance constraint payments against costs of network augmentation	Strong incentive for high-cost planning.	
Other issues 	Transmission development not necessarily lowest cost.	Gaming by generators possible. 
Unclear how TNSPs’ financial obligations would be met.	Gaming by generators possible.	
Practical issues	Reliance on transmission planners simulating constraints. Detailed information required 	Funding not predictable for TNSP. Variable network costs.	Increased predicability / funding problems.	
Source: 	Queensland Electricity Reform Unit. 
	
Option 2: Limited constraint payments
This option provides for payments to generators in the presence of constraint events under some circumstances. Similar provisions also exist in the two US energy markets reviewed in this report. In principle, constrained on or –off payments to generators are made for recognised constraints in the HV system, if this is the least-cost option for meeting demand (over some appropriate planning horizon). At present the Code provides for such payments to be negotiated. 
	Option 3: Unlimited constraint payments
The third option provides for an unlimited constraint payment system. Generators would be compensated for revenues or profits forgone, in the event that a transmission constraint arises, independently of the reason for the constraint. Constraint payments could be substantial and the funding and incentives for TNSPs to undertake uneconomic network expansion and rollout become a central issue.
5.5	Summary 
In the NEM the short run costs of transmission are reflected in an approximation of a nodal spot market and reflect the trade-off between:
•	creating short term cost signals to network users; and
•	limiting the complexities associated with nodal pricing. 
Whether the approximation that is currently used in the NEM is appropriate depends on the trade-off between efficiency and simplicity objectives. 
The Code provides for separation of regional energy prices in the event that inter-regional constraints arise. When the Code was drafted, the intention was to develop corresponding financial instruments to assist market participants in managing these price risks. 

However, the approach that will be adopted in relation to the IRSR has taken some time to clarify, and the availability of hedging instruments is limited by a number of jurisdictional derogations currently in place in the NEM. 
Inter-regional hedging instruments derived from the IRSR should, in principle:
•	permit generators to secure contractual obligations to generate with corresponding inter-regional congestion contracts; and
•	be self-financing, provided that the capacity of inter-regional links is conservatively defined. 
Code price signals for intra-regional constraints are potentially arbitrary and raise corresponding questions, in that these:
•	may encourage generator gaming; 
•	may limit the number of contracts for differences which generators are prepared to offer; and
•	afford different levels of firm access, depending on where a generator is located in the network. 
These arrangements then have implications for the competitiveness of the energy market, but also for generators’ and TNSPs’ incentives to invest. Ideally, generators should be able to contract for (financial) firm access, but this may not be an option in the meshed shared network where such rights cannot be rigorously defined. There is also a legitimate cost trade-off between building new transmission assets and constraining some generators. That is, generators may in effect perform a network service. 
Where financial access rights cannot be provided, the question then arises which role the TNSP should play in terms of providing physical access, and more generally:
•	which body should determine the type of investment that should take place; and
•	who should pay for investment which primarily benefits one market participant, but may also benefit others, now and in the future.

6.	Long run charging for transmission in the NEM
Section 5 reviewed Code provisions for charging for losses and congestion, and discussed issues relating to network access rights. Short run price signals for losses and congestion provide signals for the short term use of transmission assets, but do not recover the costs of the network. 
This section reviews the provisions for recovering the sunk costs of transmission assets, including the costs of investment, in the NEM. According to the process outlined in Chapter 6 of the Code, recovery of transmission network costs are based on three broad steps: 
•	the regulator sets an overall revenue capacity; 
•	in accordance with the Code methodology, the TNSP allocates this revenue cap, first to distinct network services and then to broad customer categories; and
•	TNSPs are free to set the prices to recover the allocated costs to the various network services and customer categories.
The efficiency of the network prices then depends on whether:
•	the regulator determines a revenue cap to meet the competing needs of the network and users;
•	the allocation of costs mimic a market outcome by being subsidy free and the effectiveness of the cost-reflective network pricing (CRNP) customer charge and the LRMC generator charge in providing longer term locational signals; and
•	The networks implement prices which reflect the underlying costs and utilisation of the network (eg fixed, demand and/or energy based charges).
Where investment by TNSPs is concerned, the Code does not distinguish between cost recovery for sunk assets and for new investment. That is, once an investment has become part of the ‘regulated’ asset base, its costs are recovered on the basis of the existing methodology from all users. The Code also provides for investment by private market participants, but how costs are recovered for such investments, and what prices may be charged has not been clarified. 
6.1	
Code principles for fixed cost recovery
The Code addresses cost recovery of transmission services on a top-down basis. The maximum allowed aggregate annual revenue requirement (AARR) for transmission services provided by an NSP must be categorised into four classes of network services: 
•	entry and exit services provided to generators and customers; 
•	TUOS services; and
•	common services which include the costs of system security and cannot reasonably be allocated on a location basis. 
6.1.1	Cost allocation
Broadly speaking, the AARR must be allocated among the assets used for providing transmission network services in proportion to replacement cost: 
•	Connection services must be allocated to customers and generators by directly attributing the costs for the individual assets used to them. 
•	The AARR for common services and for firm access services become separate cost pools. Common service costs are recovered from all transmission customers on a postage stamped basis.
•	TUOS costs are allocated to transmission customers and generators:
-	generators may elect to pay for the provision of firm access to the transmission network; 
-	50% of the AARR for the TUOS must be allocated to transmission customers at connection points using CRNP; and
-	the balance of the AARR for the TUOS must be allocated to transmission customers on a postage stamp basis. 
6.1.2	
TUOS charges
The outcome of the cost allocation process is an allocated annual cost referable to the various cost categories. These categories of cost must be converted into usage based prices:
•	Entry and exit costs are fully allocated and charged to relevant generators and HV customer. 
•	Common services costs are to be recovered from transmission customers through a variable transmission customer common service charge.
•	Customer TUOS costs are to be recovered via a variable charge. The pricing structure may be chosen at the discretion of the NSP to reflect network investment objectives, may apply to actual or agreed use of the network and may include the following components: 
-	$ per maximum kW; 
-	c per kWh; and 
-	a fixed charge.
6.1.3	Regional implementation
Four charges then form the basis for cost recovery of shared transmission costs under the Code: 
•	a common services charge to customers which includes the costs of system security; 
•	a proportion of network costs is charged to customers based on the CRNP methodology;
•	a proportion of network costs is charged to customers on the basis of an averaged (postage stamped) c/kWh rate; and
•	there is scope for a generator charge – based on a methodology set out in the Code – which is not currently implemented in the NEM. 

At the cost allocation level, the Code provisions for transmission charging have been broadly implemented across the regions: 
•	revenues have been allocated to system control/common service costs, shared network costs and connection assets/costs;
•	entry and exit services are paid for by customers and generators, respectively; and 
•	shared network costs are entirely borne by customers. 
Differences exist in the implementation of more detailed Code provisions. The determination of customer TUOS charges varies across regions, in particular the extent of cost-averaging, and how charges are passed through to customers (Figure 6‑1):
•	New South Wales and Queensland have adopted a 50/50 split for cost-reflective versus postage stamped charges and translate these into differing fixed, peak demand and energy charges;
•	Victoria recovers all shared network costs via a CRNP charge, but since this is capped, locational signals are substantially reduced; and
•	the cost of the shared network in South Australia is entirely averaged. 
Regional differences in transmission charging approaches are the result of various derogations postponing the date on which jurisdictional regulation of the TNSPs will cease and be transferred to the ACCC.

Figure 6‑1: Customer TUOS charges in the NEM
Allocation of transmission services costs	Conversion into TUOS charges	
Queensland	
Common services costs postage stamped.
TUOS charges:
•	50% of costs allocated via CRNP;
•	50% of costs postage stamped.	Common services charge: c/kWh 
TUOS charges:
•	postage stamped charges recovered via c/kWh charge;
•	CRNP charges recovered 50% via nominated demand charge ($/kW/ month), 50% via $/kWh charge. 	
New South Wales	
Common services costs postage stamped.
TUOS charges to customers:
•	50% via CRNP allocation;
•	50% postage stamped.	Common services charge: c/kWh
TUOS charges: 
•	50% fixed charge ($/annum); 
•	25% peak/shoulder energy consumption ($/kW) ;
•	25% average demand (c/kWh).	
Victoria	
TUOS charges (network charge) to customers: 
•	locational (CRNP) component; 
•	common services component to recover costs not appropriately recovered on a locational basis. 	Common services charge: c/kWh 
CRNP costs are converted into charges:
•	peak summer demand price, capped at $20/kW/per annum;
•	summer energy price to recover the balance of locational network costs (c/kWh) . 	
South Australia	
TUOS charges to customers:
•	demand component;
•	usage component;
•	common services component.	Conversion into charges:
•	$/MW/day;
•	$/MWh;
•	$/MWh. 	

6.2	
Review of cost recovery provisions
The following reviews the structure of transmission pricing in the Code. In return for paying these charges, customers and generators receive access to the transmission network. Investment in the shared network by the TNSP is rolled into the shared asset base and is discussed separately in Section 6.3.
6.2.1	Connection charge
	Code provisions 
Customer and generator connection charges represent the shallow cost of network connection, where it is possible to unambiguously attribute these costs to network users. Unless these costs have been agreed upon in a contractual agreement, they are determined as the sum of the annual revenue requirements associated with entry/exit assets. 
	Discussion
Efficient prices reflect the costs that a particular user imposes on the network. Connection costs can be directly attributed to users or groups of users and, provided that these costs are efficient, it is appropriate that the costs of installing and maintaining dedicated connection network assets are borne directly by the customers or generator who benefits from them. The application of depreciated optimal deprival valuations (DODV) places a stand-alone cost ceiling on these charges, and removes the incentive for customers to duplicate connection equipment, if charges are not cost-reflective. 
6.2.2	Postage stamped charges
A proportion of the costs of providing transmission services is currently recovered from customers via postage stamped tariffs, that is, tariffs which do not distinguish between the cost characteristics of network users. At least in part, the degree of postage stamping of transmission charges reflects a policy decision about the extent to which charges should be averaged across the HV grid. 
	
Common services charges 
	Code provision
Common service costs are defined as the annual costs related to facilities used to ensure the integrity of the transmission grid and benefiting all network users. These are asset related and operating costs associated with common service assets as defined in the Code (system control, reactive plant, communications equipment). These costs are allocated to customers in relation to energy usage. 
	Discussion 
By definition, common services benefit all users of the transmission network to some extent, regardless of location or other characteristics. If these costs cannot be attributed to users or on a regional basis, an averaged charging approach is likely to be appropriate. 
It does not immediately follow from this that common services costs should be paid by customers. Section 6.2.5 reviews questions relating to the balance of customer versus generator charges in more depth. 
	Postage stamped TUOS charges
The postage stamping methodology is also used to allocate a proportion of the cost of providing use of system services.
	Discussion 
Averaged (postage stamped) charges for TUOS services have the advantage of simplicity and meet notions of equity by not distinguishing between users in different locations. However, the averaging that is implicit in postage stamped tariffs creates the following problems: 
•	Averaged charges provide poor investment incentives. Particularly in combination with uniform energy tariffs, postage stamping of network costs does not discourage users from locating in remote areas of the network, with associated long term increases in the overall costs of augmenting and maintaining the network. 
•	For large customers, averaged charges may encourage network bypass, by encouraging direct connection to power stations. 

If the objective is to achieve a pricing framework which minimises the distortions in energy consumption patterns, at least a part of the fixed cost of network services should be recouped from users via some form of pricing ‘rule’ which reflects users’ elasticity of demand. Ramsey pricing is one such (market based) rule, whereby prices are differentiated in inverse proportion to the elasticity of demand of users. Postage stamped charges incorporate no aspect of Ramsey pricing or any other approach for minimising distortions in the use of the network, since they do not distinguish between users.
	Charging basis
The postage-stamped charges provided for under the Code, including the common services charge, are currently recovered via c/kWh charges. This meets some equity objectives:
•	large customers pay a greater share of common services than small customers; and
•	customers of a particular class pay the same charge, independently of location in the network. 
Variable energy based charges achieve these equity objective and are less likely to result in distortions in the energy market, since relative energy costs in different demand periods are not distorted. These charges are also more appropriate than peak based charges, where there is excess network capacity. Where this last point is concerned, the evidence is mixed. There appears to be excess capacity in the Victorian and in the majority of the New South Wales HV networks, but there are capacity shortages and associated intra-regional constraints in the Queensland network. 
The question arises in the context of averaged energy charges whether a greater proportion of these (essentially fixed) costs should not be recovered via a fixed charge. Fixed charges – appropriately applied – are less distortionary than variable charges, are simple to apply, could be differentiated by size of customer, and would reduce the taxation impact on consumption. 
There are also governance issues associated with variable charges levied on end users. From the point of view of using price signals as a discipline on the running costs of TNSPs, variabilisation of market charges and allocation of these charges to consumers will diminish the scope for prices to act as a discipline on costs. That is, by spreading these charges thinly, these costs are effectively ‘disguised’ in product prices so consumers are generally unaware of the overall costs of certain services.
6.2.3	
CRNP charge
CRNP charges allocate the fixed costs of the network to customers and are intended to approximately reflect the LRMC of augmenting the HV network. 
	Code provisions 
The CRNP charging methodology allocates network costs to customers on the basis of load flow modelling and aims to model ‘cost causation’ by:
•	establishing the annual cost of each transmission network assets; 
•	determining the proportion of network assets used in providing network services at each network node; 
•	averaging these proportions across a set of ‘typical’ system conditions; 
•	determining the total cost allocated to each node with reference to the costs of individual network assets in each point in the network.
The Code provision to require 50% of the fixed costs of the network to be recovered via the CRNP charge relates to the perceived relationship between CRNP and network costs. There are some plausible reasons for thinking that network prices derived entirely through the CRNP methodology would ‘over signal‘ the LRMC of network expansion:
•	if there are economies of scale in the network or in security standards, the incremental cost of network augmentation is less than the average cost;
•	CRNP charges do not reflect spare capacity in the network, where additional load can be supported with little or no network development; and
•	the CRNP approach does not reflect the (relatively small) common service aspects of some parts of the network which benefit all users, regardless of location.
	Discussion
The CRNP charge is a locational charge which aims to signal the (longer-term) costs of their locational decisions to customers. As such, it suffers from the drawbacks associated with locational charges highlighted in Section 4.2. 
	
Advantages
The CRNP method provides a practicable option for developing an LRMC based price on a locational basis in a network with a large number of nodes, each subject to relatively smooth and small levels of growth with time. As such, CRNP pricing provides robust longer term signals. 
To the extent that load growth and customer movements occur gradually, CRNP charges send longer term stable locational signals about the cost implications of their investment decisions to customers. It is worth noting that this is not the case for a generator version of the CRNP charge, since load flows are more likely to change significantly, if a new generator locates in the network. 
CRNP pricing is likely to discourage customers from locating in remote locations and to limit some forms of network bypass. Customers who use few assets (by virtue of their location in the network) are charged relatively little and vice versa. In this respect, CRNP charges are likely to fall inside the (Baumol Willig) range of incremental and stand-alone costs. For instance, where large customers are concerned, CRNP charges would limit the incentive to connect directly to power stations, since these are likely to broadly reflect the cost of assets ‘along the way’ to generators. 
CRNP pricing also reflects some notion of ‘user pays’ Sine the CRNP allocation is based on (notional) use made of the transmission system:
•	customers who represent the longer term ‘cause’ of network investment are charged more; and 
•	price outcomes are the same for existing customers which require the same service at the same location. 
	Limitations 
CRNP charges are derived through an averaged approximation of load flows along system paths to which individual assets are then attributed. To this extent, CRNP charging is arbitrary. Since costs are directly related to assets, CRNP charges are also always positive, whereas location in some parts of the network may reduce the longer term costs of network expansion. 
As a modelling approach, CRNP charging suffers from the drawbacks which typically arise in the context of complex charges – a lack of transparency and detailed data and modelling requirements. However, in contrast to the generator charge, the CRNP charge relies on existing data about the costs of sunk assets – as opposed to future investment plans and expected network trends. 

CRNP charges are essentially back-ward looking, since these are based on historical investment costs. However, these signals may not be too far removed from forward looking LRMC, since technological change in the electricity networks has to date been slow. The DODV approach for valuing assets that is required under the Code imposes additional disciplines in terms of linking asset valuations to replacement costs. 
The CRNP charge is likely to be less effective in terms of limiting bypass by other (generation or demand) technologies. High cost attribution to connection points under the CRNP approach may encourage the use of alternative sources of energy and lead to an overall decline in TNSP revenues. This would imply that the asset valuation should reflect the cost of a bypass option (or the revenue maximising outcome), such an approach is likely to be complex to implement, lacks transparency and would probably be considered discriminatory. However, the alternative – greater price averaging – would then tend to encourage bypass in different parts of the network. 
It is unclear how the CRNP charge can accommodate greater inter-regional flows. In principle customers’ use of assets in another (other than their own region) should be traced back to them and would have to be recovered via corresponding network charges and transfer payments between regions. 
This would require:
•	consistent modelling approaches and data assumptions between TNSPs; and
•	inter-regional transfer payments to be made between jurisdictions. 
Such processes are currently not in place. 
	Charging base
Different approaches have been adopted in the various jurisdictions for recovering the CRNP charge: 
•	in Queensland, CRNP charges are recovered via a combination of a nominated demand charge ($/kW) and an energy charge ($/kWh); 
•	in New South Wales, CRNP charges are recovered via a combination of a peak/shoulder energy consumption charge ($/kW) and an average energy charge (c/kWh); and
•	in Victoria, CRNP charges are recovered via a (capped) peak summer demand charge ($/kW) and an energy charge ($/kWh).

Whether these charging bases are appropriate depends on the characteristics of the relevant networks, such as the existence of excess capacity and the extent to which capacity based cost signals are considered necessary for the longer term least-cost expansion of the network. It is again unclear why the use of fixed transmission charges has been limited in the regional implementation to date. 
6.2.4	Balance of postage stamped/CRNP charges
	Code provisions
The Code provision to require only 50% of the fixed costs of the network to be recovered via the CRNP charge relates to the perceived relationship between CRNP and network costs. 
Figure 6‑2 shows the implications of the 50/50 CRNP/postage stamp split for Queensland. The regional divergence in charges is likely to be less severe for regions where the HV network covers a lesser distances. 
Figure 6‑2: Comparison of cost-reflective versus postage stamped charging

Source: Powerlink (1997).
	
Discussion
The present 50/50 split between CRNP and postage stamped pricing set out in the Code was initially determined as a pragmatical approach for estimating incremental capacity costs – that is LRMC costs – across the shared network. While it was recognised that this was not a precise approach for each individual network element, it was considered to be a reasonable approximation (and more likely, an underestimate of LRMC costs). In turn, the objective was to recover the remainder of costs in the least distortionary manner, and hence a postage stamped annual energy charge was chosen, in order not to distort price relativities.
A review of the Code provision for a 50/50 split between CRNP and postage stamped charges to customers would require:
•	a decision to structure charges to so as to reflect the LRMC of the HV network and acceptance of the notion that CRNP costs broadly reflect LRMC; 
•	a review of the costs of the transmission networks in the regions of the NEM to discover the relationship between the LRMC and the average fixed costs of the network; but also
•	an investigation of the cross-elasticities of demand of (large) customers, with a view to establishing the likely extent of bypass to other technology. 
There is unlikely to be a consensus outcome on these issues, in particular where the question of the relationship between long run and average costs is concerned. For instance, Queensland is currently embarking on a major program of grid augmentation which is likely to substantially raise transmission charges for some time to come, whereas no such large-scale investment is currently planned within the other regions. 
6.2.5	Generator charge 
Like the CRNP charge, the generator charge provided for in the Code aims to signal locational costs to generators by focusing on network expansion costs. 
	
Code provisions
The Code provides for generator payments in return for use of system services. Schedule 6.3 sets out the Maximum Generator Use of System Price expressed in $/kW/year.  It provides that generator charges for distribution or transmission use of system services should:
•	be determined separately for each network node; 
•	be determined as a scaled version of the LRMC of the network augmentation costs required to connect a new generator at each network node;
•	reflect certain assumptions about the capacity increment and type of new generator; 
•	be based on 30 year forecasts of network trends; and
•	reflect future network trends, including trends in demand and in new generation, as well as future load flows across the network. 
The Code provides that the generator LRMC charge should be determined on the basis of the long run costs of network augmentation at each node of the network to accommodate a new generator. 
	Discussion
Many of the arguments raised in the context of the CRNP charge also apply to the generator charge. However, the generator LRMC charge raises more serious implementation and governance issues, which again mirror the potential difficulties with locational charging highlighted in Section 4.2
Like the CRNP charge, the generator LRMC charge is a scaled charge which is not directly cost-reflective. It will therefore either approximately direct generators to lower cost network locations or raise revenues designed to approximately reflect the network investment costs at a particular location. 
	
Advantages
Many of the arguments raised in the context of the CRNP charge also apply to the generator charge. That is, in principle the LRMC charge encourages generators to locate in lower cost parts of the network. For instance, the Queensland LRMC charge aimed to reflect the cost of augmenting the network if a generator were to locate in a specific part of the state. The charge was based on a 30 year transmission augmentation program using existing generator locations and spatial load forecasts. The change in the capital expansion program for a 600MW generation increment at each location in the network was examined, and charges were set accordingly. 
The Queensland LRMC charge then resulted in higher TUOS charges for generators at locations which would require grid augmentation to accommodate new generators. Charges were low in NQ, high in CQ and moderate in SQ (Figure 6‑3). At the same time, the charge was intended to encourage new generators to locate in NQ and SQ.
Figure 6‑3: Projected 1997/98 generator capacity charges
Location	$ / kW / year	
Far North Queensland, North Queensland	Close to zero	
Central Queensland 	Approximately $11	
South-east Queensland	Approximately $7	
Gold Coast	$0	
Source: Powerlink
	Limitations
	Governance/transparency
In contrast to the CRNP charge, the LRMC charge is forward-looking. This confers a substantial responsibility on the TNSP to forecast accurately into the future and to accurately apply very detailed information requirements, including:
•	the projected costs of network augmentations at all nodes in the network; 
•	assumed standard new generation increments on which the charge is based; and 
•	detailed modelling of market (dispatch) outcomes, which determine required network augmentations. 

In practice, the complexities inherent in network planning are such that external monitoring/scrutiny of the detailed plans on which generator charges are based is difficult. 
The LRMC charge is also, by design, unstable over time, since it changes as new generators locate in different parts of the network. Whereas the CRNP customer charge is likely to change gradually (since load growth is assumed to occur on an incremental basis) the LRMC charge is susceptible to swings between price reviews. The outcome may be that existing generators are exposed to changing locational signals to which they are not in position to respond.
	Charging base
The generator LRMC charge is a $/kW/year capacity charge which can alternatively be referenced to various capacity increments. As a charge on generator capacity it is essentially a tax on fixed costs which will have to be recouped through generators’ contracts for differences or via higher-priced bids in the energy market. 
As a proportion of fixed costs, generator charges which are based on capacity are likely to impact lower capital cost plant with low load factors (mid merit and peaking plant) more than, say, base load stations. That is:
•	at least for large, coal-fired power stations with very substantial fixed costs, the generator charge is likely to be immaterial; while
•	the LRMC charge may be material for smaller (peaking) plant with low load factors. 
However, this may not be an undesirable outcome. To the extent that base load plant are inflexible in terms of their locational requirements, these would then be expected to pay a generator charge which would cover (some proportion) of the resulting costs for the network. In turn, smaller, more flexible plant may take a generator charge into consideration in making their locational decision, provided the charge is reasonably stable over time. 
	
Public policy issues
The pricing rules in the Code focus on the recovery of incurred costs. Particularly where postage-stamped charges are concerned, the primary focus appears to be the simplicity of the fee structure. In effect the Code assumes that the nature and scope of TNSPs’ activities are ‘a given’, and that it is the role of the regulator to ensure that costs are efficient. 
While it is important that the recovery of expenditures associated with the provision of any public good is carried out in an efficient and non-distortionary manner, it is often also important to ensure that appropriate incentives are in place to ensure that those expenditures are minimised. In this regard, charging both consumers and generators may increase the level of public scrutiny of costs. 
6.2.6	Short run versus long run cost signals 
Both the CRNP charge and the LRMC charge aim to provide longer-term (LRMC) cost signals to network users. These charges then are in addition to the short run marginal cost (SRMC) signals arising in the energy market. 
Some commentators have argued that static and dynamic loss factors – as indicators of short run marginal costs (SRMC) – should represent the only locational cost signals to network users. Given SRMC cost signals, CRNP and generator charges as an approximation of LRMC would effectively duplicate costs signals. 
	‘Ideal’ investment criteria
In fact sole reliance on short run charges is not an option, since these do not recover the costs of the network. In an ideal world, SRMC costs would accurately signal the opportunity cost of the network, but current reliability criteria are likely to imply that theoretical investment triggers are never reached. That is, network augmentation tends to be undertaken without significant numbers of loss of load events, and even when these occur, the price of unserved energy is capped at $5,000. This constitutes a key argument why users should also see price signals which reflect the longer term cost of the network, since energy prices are ‘artificially’ constrained. 
	
Departures from marginal cost pricing 
More generally, LRMC based charges tend to be more effective in signalling longer term cost trends than SRMC charges. While it is a central principle of micro-economics that price should equal SRMC, marginal costs are (only) the place to begin, because of the many issues which arise in their implementation. 
The limitations of SRMC charging relate to the static nature of the theory of efficient pricing. SRMC charging assumes that markets clear effortlessly, costlessly and instantaneously under perfect competition. This applies to some markets, but not for transmission network services which have a useful life of between 30 and 50 years. In practice, economically efficient prices of utilities with long-lived assets, such as electricity networks need to be based on some mix of short and long run marginal costs so that network users receive appropriate signals. 
Sole reliance on SRMC charges – and correspondingly averaged transmission prices – could lead to dynamic inefficiencies in the following areas:
•	the lack of long run locational signals for users; 
•	network users’ incentives for bypass; and
•	inter-temporal equity issues.
	Locational decisions by customers
In many Australian jurisdictions energy prices to small final customers are highly averaged, certainly by time of day, but often also on a geographical basis. Given the absence of locational signals in the energy market, LRMC based transmission charges are the only means of signalling the costs of network expansion and reinforcement. The alternative – greater averaging of charges – sends poor investment incentives. For instance, full postage stamping does not discourage users to locate in remote areas of the network, with what are likely to be long term increases in the overall costs of the network. 
	
Bypass signals of postage stamped charges
Section 4.1 highlighted that least-distortionary cost recovery would imply some form of Ramsey pricing rule which reflects users’ elasticity of demand. Postage stamped charges incorporate no aspect of Ramsey pricing, and may encourage larger users to bypass the existing transmission network by connecting directly to power stations. 
	Inter-temporal equity issues 
Reliance on ‘full blown’ SRMC charging to signal and recover the costs of the network raises inter-temporal equity issues, given the long life of network assets. LRMC charges are likely to be more equitable in this regard. 
Under full SRMC charging, network users would pay for investment via accumulated and future losses and congestion rentals. Even if SRMC were sufficient to recoup the costs of investment, it is unclear whether those parties paying for short-term losses are the same as those benefiting from of network expansion in the longer term. 
	A proviso
The above discussion highlighted two key points:
•	that signals for the short run costs of transmission in the NEM, for a variety of institutional and policy reasons, are constrained and cannot signal the opportunity cost of transmission; and 
•	that, at least in the short to medium term, smaller customers in particular are unlikely to see other than highly averaged energy prices. 
To the extent that generators and large customers are less insulated from market signals, it should be recognised that SLFs may provide a relatively stable signal, even in the longer term. 
Generators and large customers receive some locational signals via marginal loss factors in the energy market. Other things being equal, the marginal loss factors provided for under the Code are likely to encourage:
•	large customers to locate in areas where losses are less, regional pool prices are lower, and hence, indirectly, network augmentation costs are reduced; and
•	generators to locate near nodes where losses and loss factors are high, and hence where generation at such nodes is likely to reduce losses and associated network investment.

Loss factors vary over time with shifting power flows. However, as long as broad relativities between loss factors remain unchanged, locational energy prices are expected to signal the impact of network constraints, and hence the cost of associated network augmentations. Projections for Queensland indicate that this may be the case. However, as noted above, the approach for determining the NEM spot price implies these signals are ‘muted’. 
6.2.7	Interconnectors
An interconnect is a transmission element involved in the interconnection of two regions of the NEM. 
	Code provisions
The Code provides for different governance and payment arrangements for intra-regional and inter-regional assets:
•	intra-regional connectors are considered to be part of the intra-regional networks and receive a regulated income; while
•	inter-regional connectors must undergo a public benefit test before the interconnect can become part of the regulated asset base.
Where pricing for the use of regulated interconnectors are concerned, Chapter 6 determines that the same pricing rules should be applied as to the remainder of the regional networks. The pricing arrangements for non-regulated interconnectors are have not yet been finalised. 
	Discussion
The definition of regional boundaries and intra-regional and inter-regional interconnectors is in many instances arbitrary, due to the existence of network externalities arising from loop flows and associated wider impacts of regional investments.
6.2.8	
Summary
In principle, user pays objectives would suggest that both customers and generators should contribute to network costs. The locational charges outlined in the Code are loosely based on LRMC estimates of transmission costs, but this does not imply that such charges would effectively ‘double count’ the SRMC signals arising in the energy spot market:
•	the design of spot market prices in the NEM is such that the opportunity cost of transmission is not fully signalled to network users; and
•	in industries with long-lived assets, a combination of SRMC and LRMC charging is appropriate to indicate long term cost trends. 
	Charges to customers
The majority of network costs are recovered from customers via postage stamped tariffs and charges based on the CRNP methodology. 
	Postage stamped charges
Averaged charges are appropriate where:
•	shared network costs benefit all users to some extent; 
•	there are concerns about encouraging competitive trades in the presence of market power; and
•	there are equity concerns in relation to locally differentiated charges levied on customers. 
All of these issues arise in the NEM to some extent, and some proportion of averaged charges is therefore appropriate. 
	CRNP charges
CRNP charges have a number of drawbacks, but do provide stable and verifiable longer term locational signals to customers. In contrast, reliance on fully postage stamped charges for shared network assets is likely to encourage inefficient investment at more distant parts of the grid. 
TNSPs currently levy charges to customers on the basis of a combination of fixed, nominated peak demand and $/kWh charges. It is unclear whether this necessarily corresponds to the underlying cost characteristics of the regional networks. 
	
Balance of CRNP and postage stamped charges 
Determining the appropriate balance of these charges should be driven by the following considerations:
•	longer-run cost signalling objectives; 
•	cost attribution objectives, but these require an investigation of the relationship between LRMC and average network costs, and may lead to different balances across regions; 
•	the extent to which greater reliance on CRNP charging is likely to lead to bypass to alternative energy technologies; and 
•	equity (or cost averaging) objectives across the network. 
This suggests that the Code should provide some leeway on this issue, but only on the basis of actual network costs. 
	Charges to generators
The LRMC generator charge currently proposed under the Code suffers from a number of deficiencies, including instability and lack of transparency. At the same time, the cost implications of connecting new generators in high cost parts of the network are clearly substantial, and it is difficult not to argue for a contribution by generators to network augmentation costs. 
6.3	Transmission investment in the NEM 
One of the key objectives for capital intensive industries, such as electricity transmission is to encourage dynamic efficiency. It is intended that this be achieved via Code rules that determine the role of various institutions and lays down governance provisions. 
In the majority of restructured ESIs, transmission and system operation services have been separated from the competitive sectors of the industry - generation and retailing. In many cases, including in Australia, the provision of transmission services and investment was considered to be best left to a TNSP. TNSPs undertake all network planning and investment and recover the costs of the shared network through access charges which are levied on generators or consumers or both. In turn, market participant have (more or less clarified) rights to make use of the grid. 

The regulated model for the provision of transmission services focuses on the central control of transmission operations and investment and on cost recovery of associated costs via (more or less) averaged charges. The TNSP is obliged to provide transmission services for all users. Given appropriate price or other regulation, the TNSP should make efficient investments or enter into contracts with market participants to address transmission limitations, and these investment costs become part of the regulated asset base. This is the approach that has been adopted in the NEM.
This approach rests uneasily within a framework where privately owned industry participants undertake investments in generation and demand infrastructure and rely on unambiguous rights of access to the HV network as a strategic asset. This is an issue in the NEM, where privately financed generators may encounter network limitations which constrain their operations and hence impact financially, and where retailers purchasing power on behalf of customers are exposed to high spot market prices in the event of such limitations. 
6.3.1	Code provisions
Chapters 5 and 6 of the Code lay out the provisions regarding network investment in the NEM. 
	Institutions and governance 
Figure 6‑4 provides an overview of the institutional and governance structure for the provision of transmission services. Monopoly TNSPs operate the HV network and manage ongoing maintenance. Except in Victoria, TNSPs also undertake the network planning function. 
Following the hand-over from the jurisdictional regulators, the regulation of TNSPs will be undertaken by the ACCC. The ACCC has indicated that while it does not intend to involve itself in network planning, its powers to remove certain investment from the asset base via the optimisation process are intended to encourage efficient investment decisions by the TNSPs. 
NEMMCO, in turn, has extensive powers of direction. There are some processes for consultation with market participants, but it is unclear whether the existing level of jurisdictional oversight is appropriate. 
	
Network planning and investment 
NEMMCO is responsible for power system security, but also for coordination of power system planning. The Inter Regional Planning Committee (IRPC) provides a forum for joint planning, and is required to collect and disseminate information to participants in the NEM by preparing regular statements of opportunities, undertaking annual planning reviews of the power system and assessing applications to establish new interconnectors between regions.
Figure 6‑4: Institutional and governance arrangements in the NEM

Source: 	London Economics. 
	Inter-regional investment 
The IRPC specifically coordinates inter-regional planning under the auspices of NEMMCO. In undertaking its obligation, the IRPC’s focus is on future network losses and on constraints on power transfers within and between regions. For inter-regional planning and investment purposes, assessment by the IRPC augmentation options must aim to maximise net benefits to customers. 
	
Intra-regional investment 
Within a region investment in the HV network is largely the responsibility of the corresponding TNSP:
•	TNSPs must conduct annual planning reviews, and where investment requirements are identified, consult on the options that should be adopted. Intra-regional network augmentation must be undertaken on the basis of an economic cost effectiveness analysis. 
•	TNSPs must comply with power system performance and quality of supply standards, must enter into connection agreements with market participants and are responsible for the planning and development of their networks. Network performance requirements focus on ‘adequate levels of network power transfer capability or quality of supply for the common good of all, or a significant number of Code Participants’ and those measures ‘required to achieve a specific level of network service at an individual connection point’. 
Where intra-regional investment is concerned, complexities arise from the overlap between what constitutes the transmission network and what would be considered part of the distribution network. In practice this distinction cannot be as clearly defined as suggested in the Code and has to be made in a regional context. For instance, in both New South Wales and Queensland, HV (distribution) lines provide reliable back-up capacity for the main transmission grid. In addition, it is often possible for distribution system development to be used to address emerging transmission capacity limits. The implication is that network investment can sometimes be undertaken at either level. In practice, consistent with the Code framework, TNSPs and distribution NSPs address these interdependencies by coordinating investment. 
	Private investment 
The NEM expands the range of investment opportunities in the ESI. In the past, new entrants could only invest in new generation or demand side options. The Code provides for private investment in network assets, such as unregulated interconnectors, although key provisions for access and charging have not been clarified.
6.3.2	Discussion
In order for the monopoly TNSPs to undertake appropriate grid augmentation, the regulator needs to specify clear rules for network investment. This is complicated by information asymmetries. 
	Regulated model of investment 
In the regulated model of the NEM, network planning and augmentation substantially is undertaken by TNSPs and NEMMCO, although these should be undertaken with reference to customer benefits. The experience in Australia is that scrutiny of regional investment plans in the various regions of the NEM appears to have been limited in the past. It can also be concluded that boundary issues have historically limited cooperation between the regions of the NEM. 
It is also unclear whether current Code provisions are likely to improve the situation:
•	the committees, such as the IRPC established under NEMMCO to address inter-regional planning issues appear divided along jurisdictional lines; and
•	the notion of intra- and inter-regional investment suggests that the conscious integration of the regional networks is some way off. 
	Market model for investment 
In contrast to the regulated model, Hogan’s contract model would rely on network users to undertake network investment as and when required. 
	Transmission congestion contracts
The objective of various types of network ‘rights’ is to grant owners and users of transmission assets entitlements to the usage of, or revenues from, the joint operation of the HV grid. 
TCCs pay the right holder the difference between spot energy prices at the two nodes specified by that right. TCCs contain no reference to the transmission link or the path by which power may move between two points. Hogan (1992) proved that, provided network capacity is appropriately defined, TCCs would be self-financing; that is, revenues from losses and congestion rentals would meet payments required under the TCCs.
	
Contract networks 
Contract networks defined by TCCs were originally intended to: 
•	provide users of the grid with a mechanism to hedge against network congestion by purchasing transmission rights; 
•	provide an avenue for compensating transmission owners for the joint use of their transmission assets; and
•	encourage a market solution for private investment in the network. 
When the concept of contract networks was first developed, it was considered that such contractual rights would entail a move away from the traditional role of the TNSP to a decentralised market environment and transmission pricing system. Investments would be made by individual, or coalitions of, investors who would receive no explicit guarantee of recovery of their capital. Investments would be undertaken, because the benefits from adding transmission capacity would offset the corresponding costs. In theory, such investments could be made anywhere in a regional network, so that investors could focus on the most cost-efficient option for meeting their network requirements. 
	Limitations to the market approach to investment 
The concept of private transmission investment in return for transmission rights is an appealing one. However, market based approaches to transmission investment, such as Hogan’s contract networks, suffer from a series of theoretical and practical limitations. 
	Economics of networks
Difficulties arise directly as a result of the economics of transmission networks. The theory of perfect competition assumes increasing marginal costs in production and instantaneous responses in a market context. In contrast:
•	transmission networks exhibit economies of scale and scope and investment are lumpy; and
•	reliability criteria introduce additional economies of scope, since it is cheaper to construct an integrated network, rather than a network where each line separately meets contingency criteria.

In combination, these effects are likely to result in under-investment, if investment is decentralised, since an individual investor has no incentive to construct ‘optimal’ capacity, rather than the capacity increment that they require. 
	Market power
Network scale and scope economies may be intensified, where there are concerns about generator market power. Because market power is related to the size of a generator’s market share within a geographical market, interconnection with other regions is one important means of reducing market power. 
Lines built for this purpose may lead to net public benefits, but do not necessarily meet standard investment criteria:
•	if a connecting line is of sufficient capacity to reduce market power as much as possible, it will appear to be over built and under used; and 
•	a line that is, on average, uncongested may still be too small to reduce market power at both ends as much as a larger line would.
	Kirchoff's Law 
Loop flow externalities undermine efforts to attribute costs to any particular users and complicate independent investment decisions. Externalities make the definition of TCCs complex in practice and alter investment incentives. The rule for allocating contracts to modifiers of the network are of crucial importance, because much of the incentive to expand or otherwise change the network, or to invest in the network in the first place, is determined by the precise allocation of transmission rights.
The following example highlights the potential effects of a transmission investment in an existing network, such as adding an additional (weaker) capacity line to a radial network. The effect of this investment is to change power flows, and to change the order of (least cost) generator dispatch (Figure 6‑5). 
Nodes 1 and 2 are supply nodes; demand is located at Node 3. Initially the network consists of two radial lines. The effect of adding a third, smaller capacity line connecting the two generators at nodes 1 and 2 is to eliminate those dispatches that are ‘unbalanced’, i.e. those which draw much more power from one supply than another. 
Figure 6‑5: Effect of network investment on feasible dispatches (1)

Source:	Bushnell & Stoft, Improving Private Incentives for Electric Grid Investment. 
Figure 6‑6 illustrates how the set of feasible dispatches has changed. Such a change in feasible dispatch patterns has financial implications for market participants. If Generator 1 is the cheaper generator and previously supplied the entire load at Node 3 of, say, 6MW, its output will now be comparatively reduced. In turn, the more expensive Generator 2 will be required to generate more, and overall costs to customers at Node 3 will rise. 
Figure 6‑6: Effect of network investment on feasible dispatches (2)

Source:	Bushnell & Stoft, Improving Private Incentives for Electric Grid Investment. 
This type of example illustrates the knock-on effects which arise in transmission networks and which increase the scope for poor investment decisions. Conversely, it is also possible to show how independent investment decisions improves the overall capacity of the network and benefits other network users who have not contributed to its cost. Either way, network investment has implications for (existing) network users. 

Negative or positive externalities have implications for the extent to which transmission pricing can be modified to permit independent (private) investors to make longer-term investment without some supervision by a regulatory body: 
•	reinforcing a particular line may increase or reduce the transfer capabilities of the network; and
•	resulting loop flows can and do affect third parties distant from the intended power flow. These third parties may and often do incur costs as a result of this.
Proposals by some Australian commentators for a more atomistic market where local generation competes with network alternatives ignore such network externalities. Hence, the notion of a market, where segments of network are constructed according to the needs of individuals, is likely to result in poor investment efficiency in the longer term. 
In the absence of a complete set of TCCs that accurately reflect the effect of loop flow externalities, under-investment is likely to result from economies of scale effects, since:
•	benefits seen by individual investors are most likely smaller than those seen by the network as a whole; 
•	if an investment increases benefits to other agents as a result of a beneficial expansion, but the positive externality is not reflected in the TCCs; 
•	coordination problems arise which create ‘perverse’ investment incentives for individual market participants so that:
-	users will have incentives to expand the grid, even if this reduces total welfare; and
-	a transmission link may be beneficial from an overall point of view, even if it generates a negative congestion rental; and
•	if pairs of nodes are directly connected by a single link, incentives to degrade links, similarly as for link-based rights, remain. 
	
Practical issues in defining TCCs 
It is not possible to define transmission capacity for a transmission interface without knowing everything about the use of the network at the time. In practice, load flow models are used to determine the transmission capacity of a particular transmission system, based on assumptions about system conditions and reliability. Defining a full set of contingent delivery and receipt property rights between points in a network is then highly complex. 
To define such rights, transmission capacity must be defined conservatively, to reflect ‘stressed’ system conditions. As a result, during many hours, more transmission capacity will be available for use than has been allocated to users.
6.3.3	Summary
The governance and charging provisions relating to network augmentation and expansion play a key role in supporting longer term dynamic efficiency objectives. 
The roles and responsibilities of TNSPs as planning bodies are not clear in a disaggregated and deregulated ESI. In an integrated ESI, conflicting objectives between users of the network were managed centrally; in a deregulated environment there is a corresponding need for transparent processes to resolve these issues. However, the economics of transmission investment are such that mechanisms for achieving decentralised investment, such as TCCs, are unlikely to achieve efficient outcomes. 
There is therefore likely to remain an ongoing requirement to reconcile conflicting aims of network users, clarifying the objectives of TNSPs and putting in place governance processes to ensure that these are followed. Given the role of NEMMCO, in terms of its inter-regional planning functions, such a requirement is likely to be appropriate for this body as well. 
The network interdependencies highlighted in this report, both on an inter- as well as on an intra-regional level, require joint planning provisions between TNSPs, as well as between transmission and distribution NSPs. It is not clear whether these roles will be undertaken effectively in a more commercially focused environment. 
The Code provides for opportunities for private investment in inter-regional links. However, given that corresponding rights to collect revenues have not been clarified, this is likely to limit private investment in practice.

7.	International experience
This section puts the review of transmission pricing provisions in the NEM in the context of the international experience of reform in transmission pricing. Section 5, which reviewed the provision in the NEM, identified a number of issues which require further investigation, or which need to be addressed in the Code:
•	Short run pricing of transmission costs:
-	whether the approximation of nodal pricing applied in the NEM is appropriate; 
-	in particular, whether greater time-of-day differentiation for loss factors is desirable in regions, where losses are high; 
•	Recovery of the fixed costs of transmission:
-	whether the approach of levying all fixed charges of the network on customers, but not on generators, is appropriate; 
-	whether there are better means of signalling the costs of network expansion to customers than the CRNP charge; 
-	whether the present 50/50 balance of postage-stamped and CRNP charges is appropriate; 
-	how locational charges to generators could be structured; 
-	whether the present charging basis for the various customer charges is appropriate;
•	Investment:
-	how generator access rights can be better clarified and what the corresponding obligations for generators and TNSPs should be; 
-	in particular, how this can be achieved in the case of inter- and intra-regional constraints, respectively; 
-	how greater efficiencies can be introduced in planning and investment processes; 
-	which party should pay for investment; 
-	the respective roles and responsibilities of TNSPs and the independent system operator (ISO). 
7.1	
Short run costs
Figure 7‑1 summarises the approaches that have been used internationally for pricing the short term costs of transmission. With the exception of the England & Wales approach, the principle in all countries reviewed is to price losses and congestion. Differences arise in the extent of averaging that is undertaken, that is, whether these costs are reflected on a zonal or nodal basis, and the extent of averaging across time. 
7.1.1	Losses
With the exception of the England & Wales spot market, all systems reviewed here incorporate a form of charging for losses in the energy market:
•	Argentina applies hourly nodal factors to energy transfers, calculated a day ahead of generator dispatch; 
•	in Chile, the marginal costs for power are based on the development costs for peak units plus a penalty factor to reflect marginal losses;
•	in New Zealand and the Pennsylvania-Maryland Interconnection (PJM) energy prices reflect how total transmission losses change for a small change in demand or generation at each point in time; 
•	in the zonal spot market in Norway and Sweden losses are reflected in a set of fixed loss factors which differ across locations, season and time of day; and
•	in the Western Power Exchange (WEPEX) zonal spot market generators’ schedules are adjusted to compensate for transmission losses through loss factors published for each generator location and scheduling point by the ISO prior to bidding in the day ahead market. 
7.1.2	
Congestion 
With the exception of Sweden, the markets listed above also provide for some form of energy congestion charging, although costs arising from intra-regional congestion tend to be averaged across users:
•	in Argentina and Chile nodal prices separate as constraints arise; given the radial nature of the networks, this does not lead to complex loops; 
•	in New Zealand and PJM all constraints lead to price breaks between nodes and shifts in prices in the vicinity of the constraint; 
•	in Norway capacity fees are calculated as the difference between the unconstrained spot market price for the (entire) power system, and the (constrained) spot market for each price area;
•	in England & Wales and in Sweden, the costs of changed dispatch arising from network congestion is charged to the transmission operator and recovered from customers; and
•	in WEPEX congestion gives rise to differing zonal prices in the two active regions.
7.1.3	Lessons for the NEM
The list of countries reviewed above represent the range of trade-offs between complexity and accuracy in charging for the short term costs of submission. In practice, the difficulties which more complex pricing systems – such as the ones applied in New Zealand and PJM – bring with them must be assessed in the context of the grid and the ESI, in particular the competitiveness of the generation sector. For instance, we understand that in a small system, such as New Zealand, the introduction of nodal pricing has brought with it considerable complexity and unpredictability in nodal energy prices which appear to change rapidly and not in intuitively clear directions. 
In terms of achieving greater cost-reflectiveness, the approach adopted in Scandinavia where loss factors vary by time of day/season, may increase the accuracy of signals in regions of the NEM where loss factor variability is potentially high. 

Figure 7‑1: Review of energy market pricing approaches
Market/ country	Energy market 	Losses	Congestion (inter-regional)	Congestion (intra-regional)	Settlement residue 	Access arrangements	
Argentina	Limited form of nodal pricing in a radial system	Advance incremental loss factors applied to energy and capacity 	Separation of regional prices	N/a	Rentals used to recover the fixed costs of transmission	Fixed access charge and payment of investment contributions do not imply firm access, except in the case of international interconnectors	
Chile	Limited form of nodal pricing in a linear network	Advance penalty factors for energy and capacity 	Separation of regional prices	N/a	Allocated to network assets to recover some of the costs of the network. 	Open access, but no guaranteed firm access. 	
England & Wales 	Spot market without locally differentiated energy prices	Transmission losses are accounted for by scaling up, for each half-hour, each supplier’s metered demand by the same amount, until the adjusted demand equals the metered generation sold through the Pool. 

	Cost of transmission constraints recovered via Uplift. Constrained on and -off plant are compensated. Part of Uplift is recovered as a surcharge on the Pool price, the remainder as a charge to customers.	N/a	N/a	Open access; energy market payments imply firm access rights for generators. 	
New Zealand 	Nodal pricing approach where energy prices at a particular grid location, or node, are set by the marginal cost of generation set to meet the demand at that node.	Transmission losses reflected through location factors and AC factors, where the price of electricity at a given point is the price at the reference node, multiplied by the AC factor. The AC factor describes how total transmission losses change for a small change in demand or generation:	Distinction between three types of constraints – thermal, voltage and/or reactive power and spinning reserve constraints – with different price consequences. Thermal constraints lead to price breaks between regions and shifts in prices in the vicinity of the constraint, if there are loop flows. 	N/a 	Trans Power collects congestion rentals and rebates these to customers. 
	Capped transmission hedges at the North and South Island reference nodes were available, but their sale has now been discontinued. 	
Norway	Zonal spot market	Losses are recovered via an energy fee intended to reflect marginal losses in the grid via a set of loss factors. Loss factors differ across locations, between periods, season and time of day.	Capacity fee is calculated as the difference between the unconstrained balance price for the (entire) power system, and the (constrained) balance price for each price area. 	In the event of constraints during operations, the ISO rebalances dispatch. Costs are carried by the grid and passed through to customers. 

	Rentals are used to recover the costs of the grid. 	Open access; energy market payments imply firm intra-regional access rights for generators, but not inter-regional rights. 	
PJM

	Nodal pricing reflecting hourly locational marginal Price (LMC) at each node.. 	Losses reflected in nodal energy prices.	Transmission constraint charges is difference in LMCs. Firm transmission customers are charged for congestion costs; non-firm customers elect to pay charges.	N/a 	ISO collects settlement residues and provides FTRs. Holders of firm services receive FTRs for payment of energy price differences from congestion. 	Customers can request firm or non-firm transmission services from. Corresponding transmission rights are under development. 	
Sweden	Zonal system, but locational price differences only reflected to generators	As for Norway. 	Constrained on and –off plant are paid their offer and bid price, respectively. Net cost of trades is charged to the ISO and recovered from customers. 	N/a	Applied to cover grid costs. 	As for Norway. 	
WEPEX (US)	Zonal spot market (two active’ zones)	Generators’ schedules are adjusted to compensate for transmission losses through Generator Meter Multipliers published for each generator location and scheduling point by the ISO prior to bidding in the day ahead market. 	Congestion gives rise to differing zonal prices. Congestion charge collected by the ISO is defined as the difference in zonal prices and is applied to the flow along congested interconnectors. 	Costs of intra-zonal congestion managed with adjustment bids paid to generators. Costs recovered through average grid congestion charge to loads in each zone. 	Intended to be used to issue transmission rights. 	Open access, (financial) firm access rights can be purchased. 	

7.2	Cost recovery 
Figure 7‑2 summarises the international experience reviewed, in terms of approaches to cost recovery in the network, including how investment is undertaken and paid for. 
7.2.1	Connection charges
As is the case in Australia, connection charges typically reflect the values of the assets involved, although the extent to which shared transmission assets are attributed to individual users varies. 
The exception is Norway, where connection charges are intended to reflect the wider reliability costs of the transmission grid. However, the Norwegian connection charge is complex and is based on a very generalised assessment of users’ wider benefits of being connected to the HV grid. 
In WEPEX the intention is that new users requesting connection may be potentially required to pay for the costs of wider system augmentation. 
7.2.2	Access charges
Typically one or two key access charges have been implemented to recover the costs of the shared network from users. Who pays for the HV network and on what basis varies significantly across countries. 
	Charges based on assets and load flows
Both Chile and Argentina require users to pay for the fixed costs of the network, via a methodology – according to the area of influence – akin to the CRNP charge. That is, assets are valued and revenue requirements are attached to them, and use of assets is determined via load flow modelling:
•	in Argentina shared network charges are levied on all users; 
•	in Chile the charge is levied on generators only. 

In England & Wales both generators and customers pay for network usage on the basis of a very limited approximation to load flows. Like the generator charge envisaged under the Code, this charge aims to focus on system expansion costs, although it may, in fact, more closely resemble an average charging approach. This charge is complex to determine in practice and raises questions about transparency. In addition:
•	the 75%/25% split between customers and generators appears to lack a clear justification; and
•	this charge does not recover the costs of the shared network and has been supplemented by (apparently) arbitrary £2/MW and £8/MW increments for generators and customers, respectively. 
New Zealand’s transport charge on customers also resembles the CRNP charge; like the England & Wales charges it is levied on peak demand, rather than on energy consumption. Charging on the basis of peak demand may be a reasonable approximation of network costs, if there is little excess capacity, but raise billing issues in that these charges require advance estimates of peak demand. In the case of New Zealand this has been resolved through an extremely complex system of forward nominations. 
	Peak demand charges
Sweden levies a power fee, based on subscribed maximum input and output at connection points, differentiated on a regional basis. 
Norway’s power fee levied on the basis of peak demand is essentially a residual charge to recover those costs of the network not recovered through (deep) connection charges and revenues arising from the settlement residues. It provides no locational signals to users. 
	Average energy charges
WEPEX has implemented direct access end-user access charges ($/kWh), paid by customers at point of delivery, which vary by type of user and by times of the day/year, but not by location within a region. 
	
Differentiated transmission services and charges
In PJM, users must nominate one of three transmission services (network integration service (NIS), firm or non-firm service) and pay charges accordingly:
•	NIS allows load serving entities (LSEs) to access network generation anywhere in PJM. Corresponding charges to customers are single rates based on the costs of the transmission system at point of delivery and are postage stamped. 
•	Customers can request firm or non-firm transmission services from the TP. Charges are higher for firm deliveries, but are not location specific. That is, within the individual franchise areas, different charges are determined individually for firm and non-firm services for different lengths of time, but these do not vary according to the ‘origin’ of the power being wheeled across. Firm transmission customers must pay congestion costs (but are allocated financial network rights in return), while non-firm customers may elect to pay these. 
7.2.3	Common services charges
The Code provides that common services costs should be postage stamped across customers. This is also broadly the approach that has been adopted in some overseas jurisdictions (see the column headed ‘Access (2)’ in Figure 7‑2). 
In England & Wales the uplift charge covers a variety of common services costs, but also the costs of losses (which are locational), the costs of constraints and the cost of a range of ancillary services. Uplift is charged to customers both on a locational and an averaged basis, but the detailed workings of this charge are extremely complex. 
New Zealand levies an access charge to reflect the costs of reserves and ancillary services, but this is based on peak demand, rather than on energy consumption. This may have been intended to reflect the cost drivers for ancillary services in some parts of the network, but would appear to be inappropriate for charges which have no regional cost drivers. 
7.2.4	
Lessons for the NEM
	Generator or customer charges
There is no clear trend in the incidence of charges; customers pay in Argentina, New Zealand, PJM and WEPEX, generators pay in Chile, while both sides pay in England & Wales, Norway and Sweden. It is unclear on what basis costs are allocated to either side; in the case of England & Wales this appears to be arbitrary. 
	Longer term costs of network expansion
Only a limited number of countries have implemented charges with locational network signals (as opposed to locational energy/capacity charges). Both US markets reviewed here charge $/kW charges, independently of location. Where network charges reflect locational costs – in Chile and Argentina via the area of influence approach, in England & Wales via a limited load flow approximation, and in New Zealand via a charge akin to the CRNP charge, these charges are likely to exhibit similar shortcomings as the CRNP charge. In addition, to the extent that such load flow/asset related charges are imposed on generators, these charges are unstable over time. 
	Balance postage stamping and locational signal 
With the exception of charges in PJM and WEPEX which do not vary by location, postage stamped charges tend to be ‘residual charges’, to cover any shortfall arising from line rentals or reflect the cost of common service costs: 
•	in Argentina, a balancing charge is applied to customers; 
•	the England & Wales uplift charge covers common service costs, but also losses and reactive services costs (which are location specific).
	Charging basis
Fixed charges are recovered either on a $/kWh or on a $/kW basis. Whether or not this charging base is appropriate has to be determined with regard to system conditions, in particular the fixed costs of the network. 
7.3	
Investment 
Figure 7‑2 also draws out the respective obligations of market participants and TNSPs in the context of network investment. 
7.3.1	Responsibility for investment 
Responsibility for investment varies across countries, depending on the emphasis of reforms:
•	Argentina, Chile and New Zealand emphasise the responsibility of network users to propose and undertake investments;
•	PJM and WEPEX place the obligation to propose projects on the ISO, customers, generators and other market participants and utilities;
•	in England & Wales, Norway and Sweden, network investment is exclusively undertaken by the grid company who also operates as ISO. 
7.3.2	Governance/regulatory scrutiny
In Argentina and Chile, regulatory approval is required before investment can be undertaken. Argentina has determined a structured process and four options under which transmission investment can be commissioned. Investment proposals are reviewed subject to technical and economic criteria, but can be blocked by coalitions above a minimum size. In practice, these processes have been slow, and it is unclear whether the public benefit criterion applied by the regulator is appropriate. 
The market rules for PJM and WEPEX outline strict processes which must be followed by the ISO and the regulator in the context of an investment request, including investigations of the effect of network investment on other users and on network reliability. The emphasis is on the least-cost option for meeting transmission requirements. While transmission owners must provide the ISO with longer-term investment plans (in particular relating to reliability investment) their role is largely passive. 
7.3.3	
Payment and access rights
In the three countries where network investment is undertaken by the grid operator/ISO, payment for new assets is included in the regulated asset base and charged to network users. Generators in effect have firm access in the event of intra-regional constraints (by virtue of energy market payments).  These costs are passed through to customers. However, in Sweden and Norway the absence of mechanisms to hedge against inter-regional constraints is a source of some criticism. 
In PJM and WEPEX the costs of investment are (at least in part) attributed to the groups benefiting from these investments, but may also be included in the rate base. Investors do not receive corresponding network rights. 
Chile and Argentina’s HV networks have open access provisions, but no firm access rights. Investors in international interconnectors receive corresponding property rights in return, but other rights by private investors in the network have not been clarified. The New Zealand regime is also based on open access, but Trans Power no longer offers hedging contracts. 
7.3.4	Lessons for the NEM 
Where investment is concerned, there is a clear differentiation between the more recently reformed markets, such as PJM and WEPEX, earlier reform models where investment obligations remain entirely with the grid operator/ISO and countries such as Argentina, Chile and New Zealand where the emphasis for initiating investment is largely on customers. 
	
Firm access rights 
Questions surrounding financial network rights have not been finally resolved in any of the countries reviewed:
•	Financial network rights across a limited number of corridors and hubs have recently been implemented in PJM and are proposed for WEPEX. However, implementation difficulties remain, and it is unclear to what extent these are able to guarantee some form of ‘intra-regional’ access at a sub-regional level. 
•	In Sweden and Norway, generators have guaranteed firm intra-regional access (with corresponding costs to customers), but inter-regional firm access remains a concern. 
•	In the market oriented models, such as Chile, Argentina and New Zealand there are no provisions for firm intra-regional access. 
	Efficiencies in planning and investment 
The more recently reformed markets place greater emphasis on user-driven investment, but it is unclear how this has worked in practice. In Argentina and New Zealand, coalitions of users to support an investment have not emerged; network externalities have also undermined private investment incentives. 
The newly reformed US markets go some way towards clarifying investment and planning responsibilities, and the rights of network users in this context:
•	the ISO is charged with assessing least-cost system expansion options; in contrast, the transmission operator plays a subsidiary role; 
•	market participants are able to initiate investment requests, but must pay some or all of the costs of investment; 
•	investment processes are clearly defined and rely on a clear identification of the costs and benefits of investment (including knock-on effects on other users). 

Figure 7‑2: Overview of transmission charging arrangements for cost-recovery 
Market/ country	Connection charge	Access charge (1)	Access charge (2)	Investment	
Argentina	Recoups cost of connection equipment; is determined in concession contracts as a fixed hourly charge rates, determined according to voltage level. Penalties apply in the case of interruptions. 	Network capacity charge (kW) to users is specified in terms of fixed hourly charges for capacity elements. Charge is allocated among users according to area of influence methodology. Penalty factors apply for unavailability. 	Balancing charge adjusts for revenue shortfalls arising from application of short run charges. 	Responsibility for initiating transmission investment lies with market participants according to specified processes. 
Extensions require a ‘need and suitability’ certificate issued by the regulator after an analysis and public hearings process. Coalitions may block investment proposals. 	
Chile	Cost of connection equipment. 	Recovery of the fixed costs of the grid via charges to generators. Allocation based on the ‘area of influence’ of a generator, defined as the part of the primary transmission system where a generator’s input affects electrical load flows. 	 N/a	Regulator formulates indicative reference plan for generation and transmission expansion and determines least-cost investment plan. Energy Commission’s policy is to minimise the total (discounted) cost of supply of energy. 	
England & Wales 	Connection charges based on the cost of the assets involved at each site. 	Infrastructure charges – determined via Investment Cost Related Pricing methodology – to signal users incremental grid augmentation costs. ICRP used to derive incremental costs on a zonal basis; charge has been set to achieve 75/25 split between customers and generators: 
-	peak demand charges, based on customers’ ‘triad’ demand; 
-	registered generation capacity. 	Uplift charge (in its many components) covers elements of the TNSP’s operating costs which do not vary with system size/ operations, and instances when the system diverges from least cost operations, including network security, losses, constraints, reactive and other ancillary services requirements. 
	NGC required to publish an annual Seven Year Statement containing forecasts and information on the transmission system which can allow companies to make informed judgements about the prospects for connecting new capacity. 	
New Zealand	Connection charges recover the costs of connecting a customer to the HV grid. For generators, connection charges include ‘deeper’ connection assets. 	Transport charges to customers recover part of the costs of providing lines and substations that make up the grid. Charges are location specific and expressed as a $/kW rate, to reflect the differing share of specific grid assets that support services to different connection points. 	Access charges levied on customers for shared/reduced reserve and ancillary services. Charges are based on the highest anytime peak during the contract term of the charge.	Users who are expected to benefit from an expansion are expected to enter into a ‘take or pay’ contract to cover the ‘fixed cost component’ of the project, for instance through additional connection service charges. Trans Power may have to take an active role in establishing coalitions and/or partially financing expansions, on behalf of dispersed stakeholder. 	
Norway

	Connection charge to customers and generators is intended to reflect reliability costs of the transmission grid :
-	customer tariff is based on maximum load at system peak at grid supply point; 
-	generator tariff based on installed winter capacity. 

	Power fee charged to customers and generators is based on peak (winter) domestic demand conditions. This is a residual charge to recover the costs of the grid. 	 N/a	Grid/ISO undertakes network investment. Investment charges for radial network investment are levied, if a transmission expansion to an established customer is expected to impose costs that are significantly higher than expected income. 	
PJM (US)	Connection charges for direct assignment facilities are specified in service agreements, are subject to FERC approval, and are paid for directly by customers. 	Fixed $/MW charges for transmission applied under Network Integration and firm Point-to-Point transmission services. Charges are applied to loads and vary by zone within PJM, corresponding to the transmission service areas of the historic PJM utility members.
1. Long- and short term firm point-to-point transmission services are charged to users for reserved capacity at point of delivery in $/kW for yearly, monthly and weekly charges and in $/MWh for daily charges. 
2. Non-firm point-to-point transmission services are subject to curtailment or interruption and also charged at point of delivery for monthly, weekly and daily charges in $/kW and on an hourly basis, in terms of $/MWh. 
	N/a	The following processes apply to new requests for firm transmission services: 
-	If sufficient transmission capability does not exist to accommodate a service request, the TNSP must perform a System Impact Study. 
-	If the TNSP cannot accommodate new firm point-to-point transmission services, it directs regional transmission operators to expand or modify the transmission system. 
-	If a need for new facilities is identified, the transmission user is responsible for costs, as consistent with FERC policy. 
-	If transmission constraints may be relieved more economically by redispatching resources in the PJM control area, the user is responsible for redispatch costs, as consistent with FERC policy. 	
Sweden

	Not clear.	Power fee/kW/year levied on customers and generators, varies between locations. 	 N/a	Responsibility for investment with transmission business/ISO. Investment fee applied in special cases, if a new connection requires significant investment. 	
WEPEX (US)	Costs of direct assignment facilities constructed borne by the party requesting connection. Required upgrades may have to be borne by other beneficiaries. Connection agreements must be filed with FERC. 	Direct access end-user access charges ($/kWh) vary by type of user and by time of day and season, but not by location within a region. Access charges are charged at point of delivery and are paid by market participants withdrawing energy from the ISO controlled grid. 
	Bulk access charges between utilities:
-	Non-self-sufficient access charges provide for the ‘dependent’ transmission operator pays an access charge equal to ($/kWh).
-	Wheeling access charges ($/kWh) permit SCs to deliver energy through or out of the ISO controlled grid to serve a load outside the transmission system of a participating transmission operator. 	ISO should evaluate transmission grid and report on the ability to continue existing transmission contracts or the opportunities for upgrades needed to maintain reliability or to increase efficiency. The principal impetus for transmission investment should come from customers. 
The TNSP is obliged to invest, subject to the following processes being followed:
-	It must perform a System Impact of Facility Studies, where the project sponsor or the ISO pay study costs and specify the project objectives. 
-	If this is found necessary, it must invest, subject to a cost recovery mechanism. 	

7.4	Summary
A review of the international experience in transmission pricing in recently reformed countries suggests that:
•	The short run costs of transmission are reflected in some – more or less averaged form – the majority of countries. The extent to which these are reflected in prices to customers largely depends on the extent of averaging that has been undertaken, and in equity objectives. 
•	Where locational charges are employed to recover the fixed cost of investment, these are based on some form of load flow modelling, applied to asset valuations, akin to the CRNP charge. In some instances, this has raised concerns about instability. 
•	The success of investment regimes which rely on user requests only is questionable, and appears to have led to under-investment. In practice, user coalitions have not formed readily, and blocking coalitions have slowed down investment proposals. 
•	The US reform model relies on a greater responsibility for the ISO to implement least-cost planning and investment in the shared network, with TNSPs playing a limited role. Market participants may propose investment, but the payment arrangements have not been clarified. 
•	Financial transmission rights only exist, in a limited form, in PJM. 

8.	Summary and recommendations 
Sections 5 and 6 of this report reviewed Code provisions for transmission pricing and their implementation in the NEM, while Section 7 outlined the international experience. This section summarises the discussion in this report and outlines a set of recommendations in the context of the pricing objectives for transmission described in Section 4. 
8.1	Objectives and an ‘ideal’ pricing system
Given the context of reform and the objectives with which the NEM was established, economic efficiency should play a key role in the design of a framework for transmission pricing. However, in practice, designing a pricing system which meets all efficiency objectives is not an option: 
•	efficient (SRMC) transmission charging does not recover costs and would result in under-investment; 
•	efficient charging involves significant complexities for systems operators and users; given the difficulties in establishing a simpler system such as the NEM rules, such a move may be premature at this time; and
•	efficient charging and cost-reflectivity is likely to raise equity concerns among the jurisdictions. 
Nevertheless it is appropriate to consider a longer term goal for transmission pricing, if only to the extent that this would indicate a direction for change where current provisions are clearly inadequate. A longer term ‘ideal’ pricing framework which meets economic efficiency objectives would then:
•	accurately signal the short term costs of transmission in the energy market, rather than rely on highly averaged approximations and arbitrary regional boundaries; 
•	provide the required financial instruments to permit market participants to hedge the (energy and transmission) price risks associated with such a market; and
•	as far as possible, attribute network costs to those relevant users or user groups. 

Such an ‘ideal’ must be tempered by a number of provisos. In practice the time when an efficient market can be implemented in Australia may be some distance away: 
•	The Australian system is small, but dispersed, suggesting that generator market power problems will remain an issue for some time into the future. 
•	It is not clear whether the amount of inter- and intra-regional trading will suffice to support a liquid financial market in corresponding transmission hedges. The New Zealand experience appears to suggest that IRSRs are not sufficient to support risk management instruments. 
•	The New Zealand experience with nodal pricing also suggests that there are considerable implementation difficulties associated with nodal pricing, relating to:
-	the derivation of accurate estimates of network losses; and
-	difficulties in defining the capabilities of individual components of network infrastructure. 
Given current research and network technologies, the prospect of a decentralised framework for investment – such as contract networks – appears remote. The problems may be solved in the medium to longer term, but ideally the regulatory framework should aim to reflect more ‘market driven’ outcomes:
•	investment in transmission should be undertaken on the basis of minimising the overall costs of electricity supply, subject to given standards; 
•	as a general principle, the costs of transmission investment should be allocated to those users who benefit from them; and 
•	the scope for investment proposals to be submitted from a range of users should be widened. 
The following recommendations then present a limited and transitional view for addressing perceived short-comings in the Code. Given the implementation difficulties experienced in the NEM, these measures are more likely to be acceptable in terms of bringing benefits to customers and winning policy support without requiring a fundamental review of the Code. 
8.2	
Short term productive efficiency 
Ensuring that the short term operations of the ESI take place at least-cost requires that the effects of losses and congestion are reflected in locational prices. This summarises the nodal pricing approach developed by Schweppe et al. In principle, nodal pricing sends the ‘correct’ signals to generators and customers, in terms of the efficient use of the system, but it also raises difficult implementation issues 
The energy pricing proposals for the NEM represent an approximation of full nodal spot pricing and reflect the trade-off between:
•	providing a reasonable signal of the (marginal) costs of losses and congestion; and
•	limiting the complexities associated with nodal pricing. 
Similar approaches have been adopted in California (WEPEX), in Norway & Sweden and in Chile. Whether the approximation that is currently used in the NEM is appropriate depends on the trade-off between efficiency and simplicity objectives. It is worth distinguishing between the components of the short run costs as determined in the NEM here.
•	Inter-regional congestion. Prices between regions of the NEM separate in the event that an inter-regional constraint occurs, akin to the effect that would occur between two nodes in a nodal pricing model. 
How regional prices will be determined in the event of inter-regional loop flows – as would arise if SANI were commissioned – has not been clarified in the Code. 
•	Inter-regional losses. Inter-regional losses are approximated via loss equations, the variables (but not co-efficients) of which are updated for every dispatch interval. 
It is unclear to what extent these equations are able to meet statistical tests to ensure that they are not biased and represent the best approximation of actual losses. 
•	
Intra-regional congestion. Intra-regional constraints are not reflected in locational price differences. 
If intra-regional constraints occur too frequently, the Code provides for the creation of new regions, so that the cost of the constraint can be reflected through inter-regional price differences. It is unclear, whether the current Code criterion for determining the number of regions has been properly defined to take into account the benefits (in terms of greater accuracy of pricing signals) and the costs (in terms of greater scope for market power). 
•	Intra-regional losses. Intra-regional losses are reflected as fixed average marginal loss factors between network locations and the reference node. 
The extent to which this averaging of losses is appropriate depends on the underlying variability of losses by time-of-day, season, etc. However, it is clear that the incidence of intra-regional losses differs widely across the regions of the NEM, and greater differentiation may be appropriate, if loss factors exceed a certain criterion. It may also be more appropriate to determine SLFs on the basis of expected future, rather than historical network flows.
To the extent that current approaches for pricing short term transmission costs could be improved by better statistical techniques or a more transparent approach, these options should be pursued. 
Determining whether the trade-offs implied by these approaches, in terms of reduced efficiency (or cost increases) is appropriate requires:
•	the calculation of network congestion costs and the costs of incremental transmission losses in an optimal dispatch model under a diverse range of system conditions for comparison with the price and quantity outcomes under NEM arrangements; and
•	an assessment of whether the differences in the respective outcomes are likely to translate into significantly changed demand and generation profiles and hence resource costs. 
However, any estimated efficiency savings must be balanced against:
•	increased complexities and costs associated with inter- and intra-regional trades; and 
•	implementation costs. 
This is a substantial exercise in its own right and a prerequisite before any moves to introduce an energy pricing regime based on nodal pricing should be considered. 
8.3	
Cost recovery 
In general the very large fixed costs of the transmission network are not recovered by short run (energy market) charges at generally accepted levels of system reliability and security. One of the objectives of transmission pricing is to recover these (fixed) costs in the least distortionary manner. 
The ‘second-best’ pricing approach required for cost recovery also provides a cost signal to customers, and the incentives which such signals provide need to be carefully considered. For instance, charges which are highly averaged suggest that costs are the same across the network, and will encourage corresponding consumption and location decisions. 
In this context, a combination of SRMC and LRMC charges for transmission pricing purposes is appropriate, since:
•	the SRMC signals from the spot market are artificially limited, and the theoretical link between spot market prices and optimal network investment is interrupted; and
•	energy charges to the majority of smaller customers are highly averaged. 
8.3.1	Connection charges
The Code provides for connection charges equal to the directly attributable costs caused by users of (dedicated) connection assets. Provided that these costs are efficient (low cost), allocative efficiency suggests that these costs should be attributed to the customer(s) or generator(s) who cause them and who also benefit from them. 
We do not advocate the approach adopted in Norway, to include in connection charges an estimate of the shared benefits of the network. In comparison with the simplicity and transparency of attributing direct connection costs, this approach is likely to:
•	introduce unnecessary complexity into the charging scheme; 
•	overlap with other provisions for cost recovery of the shared network; and
•	be arbitrary in relation to individual customers. 
8.3.2	
Balance of charges
The majority of the fixed costs of transmission services are currently recovered from customers via postage stamped tariffs and charges based on the CRNP methodology. Given the need to limit high locational costs in parts of the Australian HV network, locational transmission charges to both generators and customers would seem appropriate. There is also a wider governance issue to be considered. That is, to the extent that the costs of the network are recovered from a wider range of users, this is likely to increase scrutiny of TNSPs’ costs. 
8.3.3	Charges to customers
	Common services charges
The Code defines common services as services that maintain power system security and benefit all transmission customers, and which cannot reasonably be allocated on a location basis. If this definition is properly applied, these charges reflect network costs which are truly ‘joint’, that is, in that they arise more or less independently of the number of users. 
Given the definition of these costs, it would seem reasonable to attribute these costs to customers who eventually benefit from the services provided on an averaged basis. This conclusion is also based on a judgement that TNSPs’ incentives for managing these costs is relatively restricted, and that wider governance issues aimed at limiting incentives to increase costs are less important than, say, where TUOS costs are concerned. 
	Postage stamped charges
50% of network costs are currently recovered from transmission customers through postage stamped charges, that is charges, which do not distinguish by location or size of customer, and which effectively represent a ‘surcharge’ on every unit of energy consumed. 
Averaged charges which are levied on customers are simple to implement and operate like a uniform rate tax on customers. They are appropriate where:
•	shared network costs benefit all users to some extent, and hence where cost attribution becomes a problem; and
•	there are equity concerns in relation to locally differentiated charges levied on customers, since all customers pay the same charge per kWh. 

All of these issues arise in the NEM to some extent, and a limited proportion of averaged charges may therefore be appropriate. At the same time postage stamped charges are, by definition, not cost reflective and distort efficient energy consumption patterns. Full reliance on postage stamped charges for shared network assets:
•	encourages inefficient investment at more distant parts of the grid; and
•	encourages bypass by large customers in central parts of the grid. 
In turn, this suggests that fully postage stamped network charges are likely to encourage inefficient network expansion by TNSPs. 
	CRNP charges
The remaining 50% of network costs are recovered from customers via the CRNP methodology. CRNP charges are intended as an approximation of the LRMC of the HV network and serve to allocate the fixed and sunk costs of the network to customers on a locational basis. 
CRNP charges:
•	are stable over time, if they are applied to customers and load growth in different locations of the network is reasonably steady; 
•	can support dynamic efficiency objectives relating to limiting cross-subsidies and improving locational decisions by customers; and
•	are more equitable than full postage stamp pricing, since those customers further away from the centres of generation also pay more.
The CRNP methodology also has a number of acknowledged drawbacks:
•	like all cost allocation methodologies in networks, it is to an extent arbitrary; 
•	it only reflects historical expenditure, although the ODV approach, which revalues assets according to a ‘used and useful test’ and is based on replacement costs, may mitigate against this to an extent; 
•	it may encourage bypass and a ‘downward spiral’ effect in remote parts of the network, although this may be mitigated by negotiated outcomes in some circumstances; and
•	it is unclear how inter-regional flows would be addressed, and some form of transfer payment between regions would be required. 

We consider the CRNP charge to be broadly appropriate for the current market as a means of signalling the longer term costs of network expansion to customers. In combination with an extended requirement for customers to pay for shared radial network services, this would provide for locational signals of network costs. 
Concerns about spiralling price increases, if certain large customers leave, are partly addressed in the Code:
•	through side constraints that limit the price increases following a revision of the CRNP charge; and
•	since under-recovered amounts (revenue excesses or deficits) are defined to be common service costs, and hence recovered on a non-locational basis. 
In addition, it may be appropriate to define a framework for negotiation between TNSPs and customers in the context of network bypass, in order to minimise any revenue shortfalls that the TNSP may encounter. 
	Balance of CRNP and postage stamped charges
The present 50/50 split between CRNP and postage stamped charges set out in the Code was initially determined as a pragmatical approach for estimating LRMC across the shared network. This approximation may hold for South Australia, Victoria and New South Wales, but is more likely an underestimate for Queensland where projected network investment is high. It may therefore be appropriate to review the balance of these charges to account for different starting points. 
Determining the appropriate balance between the postage stamped and the CRNP charge requires an investigation of the relationship between LRMC and average network costs, and may lead to different balances across regions. This suggests that the Code should provide some leeway on this issue, but only on the basis of actual network costs. That is, the onus should be on TNSPs in the regions of the NEM to show that the current 50/50 split between postage stamped and CRNP charges is not consistent with the cost structure of the network. 
	Charging basis
Common service and postage stamped charges to customers are recovered in all regions on a c/kWh basis. CRNP charges are currently levied on the basis of fixed components, nominated peak demand and $/kWh charges.

Where these variabalised charges are concerned there is a question whether a greater proportion of these costs should not be recovered via a fixed charge, given that the majority of network costs are fixed. Fixed charges tend to distort consumption less, better reflect the costs of the network and would be more ‘visible’ to customers (and generators). There is also a governance issue here, relating to the question whether it is appropriate to widely average costs so that they are no longer visible to all but very large users. However, a move to greater fixed cost charging would need to be coordinated with the distribution NSPs who would have to modify their billing procedures accordingly. 
More generally, there is an issue as to whether the Code should be formulated in a more restrictive manner, to ensure that the recovery of these costs is consistent with regional cost drivers. That is, the basis on which charges are recovered – e.g. energy consumption, peak demand, or on a fixed basis should bear some relation to key network cost drivers. 
8.3.4	Charges to generators
The generator LRMC charge is intended to signal the incremental cost of expanding the network to meet additional generation at that location, based on a 30-year grid expansion program. While it reflects indicative cost signals, this charge:
•	lacks transparency; 
•	requires very good forecasting skills on the part of TNSPs, for a long way into the future; and
•	is not stable, from one review period to another, as capacity becomes more or less scarce in different parts of the network. 
However, in some respects these short-comings are a general feature of locational charges to customers or generators: 
•	to the extent that such charges aim to capture (historical or forward looking) costs of the network, they are based on complex calculations; and 
•	where network capacity changes over time, locational charges should change too. 

The approaches for charging generators internationally exhibit similar shortcomings. For instance, charging on the basis of load flows, as in New Zealand, Argentina and Chile exposes generators to similar fluctuating shared network charges where the locational signal can change from year to year.
In principle we consider that a generator charge incorporating some form of user-pays principle to capture locational network costs is appropriate. The alternative would be a framework, where the costs of locational decisions by generators would automatically be passed through to customers, and incentives for generators to consider the costs of network expansion would be limited. However, consideration should be given to mitigating some of the less desirable characteristics of the generator charge outlined in the Code:
•	Rebalancing. Some of the instability of the charge (arising from the requirement to ‘rebalance’ individual generator payments) may be reduced, if the charge was not required to raise a fixed sum of revenue. This would also mean that the arrival/departure of a generator in a particular region would have a lesser impact on the charges paid by other generators. 
•	Averaging. It may be that a greater degree of averaging could reduce some of the complexity of the charge, without necessarily reducing the signalling function. It could be argued that the generator charge as presently defined in the Code is some way removed from being ‘cost-reflective’ (to the extent that this is possible). That is, the charge is currently calculated on the basis of a number of assumptions about the type of generator locating at a particular node. Given that these assumptions are only approximations in the first place and are subsequently scaled to meet specified generation increments, it may be simpler and more transparent to determine fixed generator charges on a zonal basis. Such a simpler charge may also be more stable over time. 
8.4	Investment efficiency 
Commentators on the ‘regulated’ approach to network pricing and investment have highlighted that market participants’ commercial interests play a limited role in how network investment is traditionally undertaken by TNSPs. However, the alternative, to encourage decentralised investment by market participants, has serious drawbacks and has failed to work in practice to date. Where this is part of the regulatory system, private investment in the shared network has not materialised (New Zealand), or only following long delays and ‘spoiling tactics’ by opposing interests (Argentina). 

The practical experience reflects the theoretical concerns with decentralised investment processes in transmission: 
•	the need to address network externalities, making the definition of TCCs highly complex in practice;
•	likely under-investment arising from economies of scale, coordination losses and free-rider problems; 
•	‘perverse’ investment incentives which incentivise some market participants to pursue (or block) certain investment against the public interest; and 
•	the need to revert back to familiar regulatory mechanism, to ensure that only appropriate transmission investment are undertaken. 
The following recommendations then take as a starting point the notion that:
•	network planning and investment is not appropriately undertaken by groups of decentralised investors; but that 
•	appropriate governance and structural provisions must be put in place, to clarify investment processes, ensure that network investment is least-cost, and that the interests of market participants, but also those of customers who will eventually bear the majority of these costs, are appropriately represented. 
8.4.1	Access rights 
The Code distinguishes between inter- and intra-regional access to markets by generators. Generators have no implied access rights to other regional markets, but the concept of ‘firm access’ in the context of intra-regional congestion is referred to (but not clarified) in the Code. The extent to which rights of access to markets for generators either exist or can be purchased has implications for the competitiveness of the energy market, in terms of:
•	reducing the risk associated with independent generation investment; and
•	increasing the availability of hedging contracts and incentives for competitive intra- and inter-regional trades.
Implementing inter- or intra-regional access rights within meshed networks is a complex undertaking, given the predominance of loop flow effects and difficulties in defining transmission capacity. We understand that even within a very large market such as PJM, where prices are posted at 1,600 nodes, the number of contract paths for which TCCs can be purchased is limited. 

However, while such financial instruments may not realistically be introduced in the Australian context in the short- to medium term, soft- and hardware obstacles may be surmountable to make TCCs a realistic longer term instrument for hedging price risks. Unlike the firm access arrangements which have been canvassed in the NEM, TCCs are managed by a system operator, rather than the TNSP and imply a shift in governance arrangements. To the extent that the NEM moves more closely to a nodal pricing arrangement, such TCCs will be required by market participants. 
	Inter-regional access
In the short- to medium term, the existence of IRHs is likely to bring benefits to market participants and wider competitive benefits to the NEM. 
IRHs financed on the basis of the IRSR should, in principle, facilitate inter-regional contracting and hence trade and be self-financing. However, this general statement masks significant practical complexities, which has limited progress in implementing IRHs to date. Practical issues arise in:
•	defining transmission capacity for specified links;
•	ensuring that the body coordinating inter-regional trades is neither exposed to residual risks, nor has a financial interest in market outcomes; 
•	assuring the liquidity of the market in IRHs; and 
•	ensuring that the form of financial rights does not encourage ‘perverse’ investment incentives. 
These concerns appear to have been addressed in some markets, such as the PJM, where fixed transmission rights (FTRs) have been introduced for trades between PJM trading ‘hubs’ via a ring-fenced body under the auspices of the ISO. These instruments limit the risk exposure to the IRT, by distributing any rental shortfalls (or excesses) pro rata across market participants holding FTRs. However, we would also highlight the New Zealand experience, where losses and congestion rentals have turned out substantially below expectations, as a result of:
•	difficulties in accurately tracking power flows and corresponding levels of losses in an AC system through DC software; and 
•	generator gaming which led to fewer network constraints being reached, and hence system rentals accruing to generators, rather than the system operator.

Hedges that were initially provided by Transpower have now been withdrawn from sale. 
Provided then that Australian transmission rentals reach a minimum required level, the implementation issues referred to above could be addressed by limiting IRHs (at least initially) to simple, standardised and relatively easily tradeable instruments. The PJM approach which removes all market risk from the ring-fenced IRT may also address concerns about risk-exposure by entities which have a role in market making. 
	Intra-regional access 
In addition to the investment and competitive risks affecting generators highlighted above, intra-regional firm access relate directly to:
•	the investment incentives for TNSPs, which will depend on the nature of the firm access rights which generators are entitled to; 
•	the investment incentives for generators, which depend substantially on the intra-regional price setting mechanism; 
•	the corresponding costs to customers associated with different forms of firm access rights; and 
•	if TNSPs are required to compensate constrained on and –off generators, their role in the competitive market. 
The energy market pricing provisions for intra-regional constraints do not provide financial guarantees corresponding to firm access rights to generators who are constrained on or –off. In fact current provisions:
•	are arbitrary, in that a generator is more likely to receive its bid price, if it is located in close proximity to the regional reference node; 
•	are likely to encourage generator gaming, since a constrained on generator may determine the system price (depending upon where they are located in respect of the regional reference node); and
•	are inconsistent, since constrained off generators receive no equivalent compensation payments.
While there is no doubt that the question of firm access raises substantial definitional and practical issues that need to be addressed, we would argue that, given the concerns about network investment and the competitiveness of the market, some provisions need to be put in place, at least until a more sophisticated solution emerges. 

We would propose that firm access rights should be defined by limited constraint payments and the distinction between whether or not a constrained on or –off generator effectively performs a network service. That is, where it is determined that generation is the least-cost option for supplying electricity in the context of network constraints, such payments should be made by the TNSP. These payments could be contractually agreed. 
In effect, this approach would correspond to a distinction between the meshed and the radial network by recognising that:
•	within the meshed network, generators (and loads) are in some instances cost-effective alternatives to network augmentation, and that this should be reflected in TNSPs’ investment incentives; and
•	establishing ‘cause and effect’ relating to network investment may be possible in the radial network, but is unlikely to be either equitable or practicable in the meshed network. 
The preferred approach is therefore to limit firm access rights to existing and new generators connected to the meshed network. Within these confines, constrained on or -off generators would receive corresponding compensation payments. In effect, these would represent financial rights to firm access. 
Beyond the meshed network, that is, in the radial network, no firm access rights should be deemed to exist, and no constrained on or -off payments should be made. Instead, generator requests for capacity augmentation should be addressed via a framework for generator payments for shared network assets. This limitation on firm access aims to remove TNSPs’ incentives to undertake costly network augmentation which only benefit specific generators. 
A number of issues would have to be determined in detail:
•	the nature of information requirement on TNSPs to delineate the meshed and the radial network and to post network capacities; 
•	the nature of any potential liabilities and risks which may be imposed on TNSPs;
•	the respective roles of the TNSP and the ISO; 
•	how constrained on and –off payments should be determined;
•	whether audits of generators’ costs may be appropriate; and
•	the limitations and exclusions to the extent of firm access, e.g. in terms of the types of network contingencies that might be covered.
8.4.2	
Network investment 
Chapter 5 of the Code sets out a framework for planning and augmentation of networks for TNSPs. TNSPs must analyse the expected future operation of networks, identify network limits and consult on options to address these. NEMMCO plays a key role where inter-regional investment is concerned. 
	Governance
The Code criteria for inter- and intra-regional investment appropriately focus on the least-cost provision of services to customers. In a restructured and more commercially focused ESI it is unclear how the interests of customers in the efficient provision of network services are represented. While some Australian TNSPs view this as part of their current role, such wider objectives may disappear, once TNSPs are privatised. The options for ensuring that customers’ interests in the context of network expansion are properly recognised include:
•	requiring the regulator to ensure that network investment which will be paid for by customers is least-cost;
•	conversely, that network investment which will minimise the costs of electricity to customers will be undertaken; and
•	placing a similar monitoring responsibility on the ISO, i.e. some body akin to NEMMCO. 
	Coordinated planning
A key concern relates to the extent to which network investment is undertaken by TNSPs on a separate regional basis, rather than in the context of the integrated network of the NEM. Greater regional integration and trade in the NEM have implications for the role of the networks, and an understanding of TNSPs as separate network planning bodies is likely to lead to least-cost investment outcomes in the longer term. This applies both at the inter- and the intra-regional level, that is, for the relationship between TNSPs and between TNSPs and distribution NSPs. 

Given network externalities, inter-regional knock-on effects and economies of scope, the distinction between intra-regional and inter-regional network investment would seem inappropriate, and joint planning processes with the objective of facilitating the least-cost expansion of the ESI should be encouraged. Such joint planning processes are important at all levels of the network. There are some limits to which this can be achieved:
•	It is important that an emphasis on increased inter-regional planning is counter-balanced by strengthened governance, greater scrutiny and clarified objectives at this level. In the absence of such measures, the outcome would be the emergence of a (supra-regional) body in the NEM with limited accountability. 
•	A requirement for greater integrated planning at an intra-regional level may yield to unwieldy and bureaucratic outcomes, if extensive coordination between TNSPs and distribution NSPs is required. It would also be difficult to define such detailed requirements in practice. 
We would recommend strengthened requirements for TNSP consultation and joint planning procedures, for both intra- and inter-regional investment, to ensure that investment is coordinated and undertaken at least cost to customers. At the same time the Code objectives for NSPs and for NEMMCO as they relate to investment should be clarified, to ensure that investment is undertaken at least cost to customers. 
	Network investment processes 
Greater participation by users in determining network investment in transmission assets – along the lines implemented in PJM and WEPEX – could take place according to the following principles: 
•	Investments above a certain size can be proposed by a range of interested parties, including the TNSP and the ISO, but are evaluated by an independent planning body, but subject to clear investment objectives.
•	At least those proposed investment above a certain cost, should undergo an economic cost-benefit test where projects that result in the lowest cost of production are approved. If this cost-benefit criterion is not met, investment should be financed by the proponent, under regulatory oversight. 
•	
Also for those proposed investment above a certain cost, the requirement to determine the least-cost option should be strengthened to include not just generation and DSM alternatives, but also alternatives at other levels of the network. 
•	The cost of investment which does meet the cost-benefit test should be shared between beneficiaries, under regulatory oversight. Implications of investment for other users should be evaluated to identify positive and adverse network effects.
	Information provision 
The Code requires that alternatives to network investment, such as generation or DSM initiatives be considered in the course of network planning processes, and also permits private investment in electricity networks. To be effective and to limit the potential for disputes, this requirement needs to be supported by strengthened obligations on TNSPs for the timely and transparent publication of network requirements at particular locations and associated opportunities for generators, DSM options or opportunities for private network investment. 
Greater information provision requirements by the TNSPs are appropriate in the following areas:
•	User payments for the shared network. The calculation of generator and customer payments towards deep network assets relies on the existence of load forecasts and associated network augmentation plans. 
•	Alternatives to network investment. Where small-scale generation or DSM services can represent a cost-effective trade-off to network expansion or augmentation, such opportunities should be posted early on. 
•	Firm access. Firm access provisions require a specification of network capabilities and future augmentation plans. 
More generally, increased private sector participation is likely to increase pressure on TNSPs to provide longer term network development plans. 
8.4.3	Customer/generator investment 
The discussion about generator charges emphasised that these are complex to determine in practice and raise difficult governance issues. This represents an argument in favour of direct payments by users for network investment that may be required on their behalf. 

However, allocating the costs of investment in the shared network to a specific user (customer or generator) is inequitable, if:
•	loop flows imply that investments substantially benefit other users as well; 
•	the augmentation effectively becomes part of the meshed shared network; or 
•	subsequent users benefit from economies of scale requiring initial ‘over-investment’. 
Direct payments by network users in return for connection requests that may require further investment are therefore inappropriate in the meshed network. 
Nevertheless, there are also instances where a user can be considered to ‘cause’ investment in the radial shared network that is unlikely to confer a benefit on other customers for some foreseeable term. Where asset construction benefits one user, requiring TNSPs to undertake this reinforcement on their behalf (and including this in the rate base) raises the following issues:
•	whether the NSP (and implicitly customers) should be required to bear the costs of business decisions by specific users, which are unlikely to benefit them, even over the longer term and which may present associated asset stranding risks; and
•	the longer term impact on least-cost network expansion, if all requests for network augmentation must be financed and undertaken by the TNSP. 
Direct payments by market participants for investment – along the lines implemented in PJM and WEPEX – in transmission assets offer an avenue for recouping the costs associated with generator location decisions and limiting adverse incentive effects. At least in principle, determining the cost that a particular user should bear could also be determined with reference to the ‘with/without’ test developed by the Independent Pricing and Regulatory Tribunal of New South Wales (IPART). 

However, such planning and payment provisions:
•	entail a move away from a charging framework which effectively only attributes the costs of connection investments to users;
•	become increasingly inappropriate and contentious, the greater the investment impacts on the shared meshed network; 
•	require information and associated governance provisions for the TNSPs, in particular with respect to current network investment plans; and
•	are likely to be contentious in practice and require the development of charging guidelines, as well as regulatory involvement.
8.4.4	Private network investment 
The Code refers to privately financed (entrepreneurial) inter-regional links and appears to suggest that (a portion of) the IRSR should be attributed to such inter-regional links. 
The proposal to attribute the IRSR to private owners of inter-regional links has some short-comings:
•	it is unlikely that these revenues would suffice to finance these assets; and
•	to the extent that payment of losses and congestion rentals to private transmission owners in effect confers link-based rights, this approach provides the owner with an incentive to degrade the link, in order to raise revenues. 
Nevertheless, it is difficult to determine other ways of how such investments could be financed. Where network loop flows occur – that is, in the meshed network, which is likely to include any parallel interconnectors – standard network charging methodologies would require other network users to automatically have to pay for a privately financed asset as well. Unless this asset has passed a public benefits test, this is not appropriate. 
We conclude that unregulated transmission investments are appropriate for inter-regional and radial links, but not in the meshed network, where attributing specific line rentals or putting in place specific charging regimes is not an option. In either case, this would require that technical Code requirements would have to be met. 

For both inter-regional and radial links, the IRSR would be attributed to investors. However, in each case, the day-to-day control of the asset would have to be left to the ISO, and the day-to-day management, including O&M, would have to be left to the TNSP, to reflect the integrated nature of transmission networks and to mitigate against any adverse investment incentives.