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Response to NECA
Transmission and Distribution Pricing
Review Options Papers
Prepared by:
NSW Treasury
17 September 1998
Table of Contents
1.
GENERAL COMMENT ............................................................................................................ 1
2.
OPTIONS..................................................................................................................................... 3
APPENDIX A: RECOMMENDATIONS CONTAINED IN THE NECA OPTIONS PAPERS
OF JULY 1998 .............................................................................................................................. 9
APPENDIX B: A SIMPLE ECONOMIC MODEL OF NETWORK PRICING ............................ 11
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1.
General comment
Since late 1997, NECA has been undertaking a review of transmission and distribution
pricing issues. It recently published an options paper proposing the following
principles in three areas:
1.
regulated transmission and distribution charges;
2.
specification and negotiation of Network charges; and
3.
inter-regional hedging, firm access and a framework for nonregulated interconnectors.
Recommendations presented by NECA in its options papers published in July 1998 are
contained in Appendix A.
The discussion presented by NECA in its options papers is at a very high level. In its
current form the discussion and associated recommendations suffer from the lack of a
clear economic framework. Considerably more analysis and assessment of the options
will be required before judgements can be made as to the preferred course of action.
The Treasury requested Dr Paul Moy of Fay, Richwhite to review the NECA options
papaers and develop an conceptual framework that would assist it to understand the
basis of the NECA recommendations. This paper has been developed as input to the
NECA Network Pricing Review. In summary the paper recommends that:

the impact of network pricing arrangements in the National Electricity Market
should be compared with the benchmark model of full nodal pricing as an aid to
ensure consistency between recommendations and as a means of examining the
full range of impacts of alternative options;

significant further empirical analysis is required before decisions can be made
regarding:
–
deep connection charges and compensation payments can be calculated for
new generators;
–
the balance of CRNP and postage stamp pricing can be determined;
–
standard levels of service can be developed;
–
entrepreneurial interconnectors can be accommodated in the NEM.
The economic framework outlined in Appendix B highlights a number of issues
concerning the preferred NECA options:

The existing NEM institutional arrangements while different to nodal pricing, do
include locational signals in energy prices and regional boundaries. This supports
NECA’s proposal that generators not be required to pay transmission prices.
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
NECA’s proposal in respect of embedded generation and deep connection costs
and benefits is incorrect as it involves compensation for only some parties (new
entrants) and, as a result, encourages inefficient investment.

An economically efficient compensation mechanism that takes into account
network effects is conceptually and computationally complex. Further work is
required to explore these issues; and

Compensation issues cannot be separated from network service standards. Since
service standards are, in part, expectation based they cannot be assessed
adequately within a framework which allows only two broad standards: “firm
access” versus “non-firm access”.
To achieve the required outcome, it will be necessary for NECA to undertake
considerably more work and issue a more detailed and complete options paper before
compiling its final report. The additional options paper would contain the result of
further research on specific proposals for code changes. The Treasury understands
that this will require more time than currently allowed in the review timetable.
However, this further work is required to ensure that the review has been worthwhile.
Treasury officials are able to make themselves available to discuss these issues further
should NECA require such discussions.
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2.
Options
The discussion of a number of issues covered in the NECA options paper would
benefit from a more detailed discussion of the interaction of the market and regulated
sectors of the industry. In particular there is a market-based approach to network
pricing: so-called nodal pricing which provides a benchmark against which to assess
the efficacy of alternative approaches. Because of the regional income distribution
impacts of nodal pricing together with its implications for the ability of networks to
recover average costs, this approach was not adopted by the Governments that
initially established electricity markets in Australia. However, the nodal pricing
model provides an internally consistent framework for examining a number of issues
raised in the NECA options paper. We make some preliminary observations on some
options based on a simple model of the NEM in Appendix B.

Locational signals for generation
NECA’s proposed approach involves the following elements:

generators pay “deep” connection charges;

no “free firm access” for incumbents;

new “embedded” entrants which contribute to the relief of local congestion
should receive an appropriate rebate on network charges.
The New South Wales Government supports the current arrangements where both
generators and customers pay “shallow” connection charges. In principle, there is also
support for the payment of “deep” connection charges. However, there are both
conceptual and implementation issues which need to be resolved in order to determine
whether a workable approach is possible. As a result the option paper proposals on
this issue cannot be supported.
An important issue in considering deep network charges is the concept of network
externalities. Note that economic networks include physical networks such as
electricity transmission and distribution but extend to other “virtual” network
products such as product standards (eg. software, video formats, audio formats etc).
Electricity networks exhibit a range of network externalities. For example, changes in
the pattern of load relative to generation and/or changes in the location of generation
may change the probability and pattern of constraint events and affect both generators
and consumers. Equally, changes in network configuration can change the probability
and pattern of constraints and losses thus altering the benefits and costs to participants
(both generators and customers) in the network.
In an electricity network these patterns of independencies or network externalities are
pervasive but not all are material. This reflects the fact that power flows in a meshed
network follow the path of least resistance, notwithstanding the nature of the financial
contracts between participants. Importantly some interdependence effects are simply
the results of a market working. These effects are termed “pecuniary externalities”
and as such should not be the focus of regulatory arrangements which seek to provide
“compensation” arrangements. In contrast “technological externalities” do provide
grounds for introducing compensation mechanisms (see Liebowitz and Margolis
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(1994)) provided that the interventions materially improve resource allocation. These
issues are considered in more detail in Appendix B.
Recognition of network externalities supports symmetrical treatment of new entrants
and incumbent participants in respect of compensation payments relating to
incremental network costs and benefits. However, not all externalities justify
compensation.
Unfortunately the current NECA proposal dealing with deep
connection charges does not consider these issues in sufficient detail. Moreover the
recommendation does not treat incumbents and new entrants symmetrically. For
example, incumbent generators "should not be shielded from the effects of …. new locational
decisions" whereas new embedded generators "that contribute to the relief of local
congestion should receive an appropriate rebate on network charges". This augmentation
rule encourages investment decisions that impose technological externalities as much
as it encourages investment which reduces congestion costs and losses since a new
entrant benefits irrespective of whether there is simply a shifting of local congestion
costs or a reduction in these costs.
Once a compensation principle is introduced as a means of internalising externalities
(as partly proposed in the NECA paper) there is a requirement to explore in some
detail the mechanism for implementing that principle. Currently, it is difficult to
support compensation mechanisms without detailed analysis of the implementation
mechanism. In these circumstances it is appropriate for NECA to explore in some
detailed implementation issues associated with deep network charges.
The paper makes a casual reference to no firm access to incumbent generators while at
the same time proposing:

compensation for new embedded entrants; and

standards of service.
These issues are dealing with the same network phenomena and should be treated
consistently. While “firm access” may be considered a 100% expectation by a
generator of its ability to evacuate power this is simply a polar case. All generators,
including new entrants, will form conditional expectations as to congestion events.
These expectations will be based on a range of factors including how the network is
operated, maintained and augmented. Notwithstanding that access may not be
guaranteed, determination of service quality standards in effect defines the property
rights and significantly influences expectations of network users.

Generators should not pay transmission network charges
Consideration of the model outlined in Appendix B indicates that if implemented
appropriately there are already strong locational signals in the market arrangements
reflecting loss factors and regional boundaries.
It may the case that the
implementation of these mechanisms for conveying locational price signals could be
improved, however requiring generators to pay network charges simply to “improve
locational signals” does not have any theoretical or practical support. It follows that
the Treasury supports proposal 1.2 that generators should not pay transmission
network charges.

Exploration of more radical alternatives
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Proposal 1.3 is supported as further research should provide insights into the
underlying issues for both pure market institutional arrangements and mixed
market/regulatory institutional arrangements. As noted above however, the research
program needs to focus on detail as well as high level principles.

Balance of CRNP & postage stamping / network bypass
As noted above the current institutional arrangements reflect Government policy
objectives relating to income distribution, cost recovery and other social policy issues.
This bears on two proposals in the NECA paper:
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1.4
dealing with the balance of CRNP and postage stamp pricing; and
2.3
network bypass.
The appropriate balance between CRNP and postage stamp pricing involves a
judgement as to the final impact on customer prices of these methodologies. Thus, in
part, it is an empirical issue. It follows that participants understanding and assessment
of this issue would be facilitated by empirical work undertaken by NECA.
Conceptually, the balance between CRNP and postage stamp pricing provides
resource allocation signals. To the extent that this is the case, the structure of charges
is also important. The balance of connection, demand and energy charges should not
be determined in isolation from decisions on the balance of CRNP and postage stamp
pricing. Since uneconomic bypass is an outcome of postage stamp price regulation
these two issues needs to be considered together.
Given that Government’s have expressed a desire to implement postage stamp in the
past, the Treasury would support the general direction of proposals 1.4 and 2.3. Less
prescription in this area is probably desirable given that the materiality of potential
distributional effects is likely to vary substantially between regions.

Standards of service / pass-through of network benefits / firm access
Proposals 2.1, 2.4 and 3.3 are concerned with the general issues discussed in relation to
deep connection charges. Particularly intra-regional firm access is simply one aspect
of network service standards. Changes in these areas impact on the implicit or explicit
property rights of market participants. These issues go to the core of the market
design implemented in Australia which combines competitive wholesale and retail
markets with regulated network businesses. These are complex issues and the
Treasury considers that the research undertaken to date has not facilitated a better
understanding of these issues individually or their inter-relatedness.

Unbundled charges / network utilisation information
Proposals 2.2 and 2.5 deal with information. In general better quality information and
more transparency improves both market and regulatory processes. Given that the
institutional structure underpinning the NEM involves a high level of regulatory
intervention, particularly in the area of network investment and pricing, enhanced
information is a critical issue. By itself however it will not be sufficient to ensure
efficient network investment or its substitutes. The recent experience with the
proposed NSW/South Australian interconnect is a case in point.
While unbundling of TUOS and DUOS charges is consistent with greater transparency,
more work is required before a conclusion could be drawn that this will have a
material impact on resource allocation. Both the structure of charges and the
estimation method require higher priority consideration than disaggregation.
Separation of incorrectly structured and estimated charges may not led to a material
improvement in resource allocation.

Inter-regional hedging
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Proposals 3.1 and 3.2 deal with the vexing issue of inter-regional price risk. The
Treasury supports recommendation 3.1 and considers an effective inter-regional
hedging mechanism as a key aspect of the NEM design. This issue needs to be
progressed with a very high priority.
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
Entrepreneurial links
Recent experience with NEMMCO’s consideration of the application for the South
Australia/NSW interconnector to be a regulated interconnector has highlighted
significant deficiencies in the Code with regard to its treatment of new regulated
interconnectors. This situation raises real questions about the ability of the National
Electricity Market to meet its major objectives. NSW strongly urges NECA to more
fully explore the issues that surround the treatment of entrepreneurial interconnectors
and develop appropriate guidelines within a reasonably short period of time.
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Appendix A: Recommendations contained in the NECA
Options Papers of July 1998
1.
Regulated Transmission and Distribution Charges
1.1
locational signals for new generation should be provided by a requirement for
generators to pay “deep” connection charges in specific defined circumstances :
where substantial investment in the shared radical network is required as a
result, where the benefits of that investment accrue to one user and where the
costs can be clearly identified. Existing generators should not be shielded from
the effects of those new locational decisions, ie there should not be free “firm
access” for incumbents. On the other hand, new generators embedded in the
sub-transmission or distribution networks and that contribute to the relief of
local congestion should receive an appropriate rebate on network charges;
1.2
although NECA would welcome further views on this issue, the balance of the
arguments on efficiency and equity grounds for seeking to provide locational
signals for all, including existing, generators by requiring generators to pay a
share of network charges is probably not proven;
1.3
more radical alternatives or refinements to network charging arrangements
should continue to be explored but may not be feasible or sensible in the
timescale of the review; and
1.4
in the meantime, network charges should continue to be based on a combination
of CRNP and postage stamping, although a new balance between those two
components may be appropriate.
The Code should generally be less
prescriptive, especially in relation to the calculation of DUOS charges. DUOS
charges should, however, include a demand-based element to encourage
demand-side management initiatives.
2.
Specification and Negotiation of Network Charges
2.1
benchmark standards of service should be developed, in the first instance for
transmission NSPs, and monitoring arrangements put in place. Performance
against those benchmarks should be reflected in future years’ revenue caps. A
negotiating framework, which might also be used more widely, should be put in
place to allow the development of premium standards of service for which users
would pay entirely outside the regulated revenue arrangements;
2.2
TUOS and DUOS charges should be unbundled, certainly for those customers
who wish to see separate charges;
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2.3
there should be no restrictions on bypass, at least in the longer-term. NSPs
should, however, be able to offer discounts on network charges to seek to avoid
bypass, and be able to recoup at least a proportion of the costs of those discounts
with the approval of the regulator;
2.4
here should be a framework for negotiations on the pass-through of network
benefits as a result of embedded generation. The paper sets out an outline of a
possible framework; and
2.5
additional information should be available through transmission NSPs’ annual
planning reviews and new annual statements of network utilisation by
distribution NSPs to allow a clearer and wider assessment of the alternatives to
network augmentation.
3.
Inter-regional hedging, firm access and a framework for non-regulated
interconnectors
3.1
endorses the need for facilitated link-based inter-regional hedges, at least on a
trial basis. If the arrangements developed by the NEMMCO industry-based
working group gain broader acceptance, they should be implemented as soon as
possible;
3.2
supports further work to explore the practicalities of fully firm inter-regional
hedges;
3.3
suggests that the negotiation of enhanced service standards by NSPs might
provide at least part of the benefits of intra-regional firm access and might
represent a more practical way forward, at least in the immediate future. The
scope for intra-regional firm access should, however, continue to be considered
in the light of experience;
3.4
floats the option of long-term hedges against variable network charges; and
3.5
identifies the key issues surrounding a framework for non-regulated
interconnectors as a basis for further discussion
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Appendix B:
Pricing
A simple economic model of Network
We outline below a simple economic framework for considering network pricing. We
start with a simple model of a market-based networked electricity industry in which
energy costs and transportation costs are reflected in spot prices ie “nodal prices”. For
simplicity we focus on the revenue flows between one location in the network which
generates power (node i) and another location which consumes power (node j). There
are many other producing and consuming locations which interact with i and j but for
ease of exposition we ignore the revenue flows associated with each of these nodes.
Assume in the first instance that:
1.
energy and transportation charges are derived from the spot market as
modified by contracts;
2.
a supply node “i” and a load node “j”;
3.
Pi and Pj are the locational prices at i and j;
4.
Pc are contract prices; and
5.
Pc is referenced to Pj.
The underlying logic of a market model of the electricity industry can be captured by
tracing through the types of transactions which participants will engage in.
In the absence of contracts in period 1, generator i receives revenue ( Ri1 ) equal to
Pi1 * q 1 and load pays Pj1 * q1 . In other words the generator receives the price at her
location (i) on the network and “load” pays the price at her location (j) on the network.
To the extent that Pi and Pj differ, a “settlement residue” accrues. This is in effect the
transportation payment.
In order to hedge intertemporal price risk parties i and j enter into a contract for
differences for volume q1 at price Pc. Thus the contract generates an additional cost for
j in period 1 of  ( Pc1  Pj1 ) * q `1 .
Since the contract is referenced to node j the generator is exposed to revenue risk of
( Pj1  Pi1 ) * q1 as a result of losses and congestion. These revenues are potentially
volatile reflecting price movements at both nodes. This volatility provides an incentive
for parties to write transmission contracts to hedge the price risk. In other words
locational price differences ( Pji  Pi1 ) can be captured in a transmission contract
between i and j for volume q1. Thus, j is fully hedged if actual energy produced q1 is
fully contracted with both energy contracts and transmission contracts. There is
debate, however, on the effects of these hedging arrangements (see for example,
Hogan (1992); Bushnell & Stoft (1996); Wu et al. (1996) and Chao and Peck (1996)).
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

To observe the impact of all possible transactions we combine spot revenue Pi1 * q 1 ,
energy
P
1
j
contract


revenue
P
1
c

 Pj1 * q1

and
transmission
contract
revenue
 Pi1 * q1 . Revenue for j in period 1 under full hedging is:
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R i1
=
P
=
q1 Pi1  Pc1  Pj1  Pj1  Pi1
=
q 1 * Pc1
1
i
 
  
 
* q1  Pc1  Pj1 * q1  Pj1  Pi1 * q1


A number of issues arise from this simple model:

Price is equal to short run marginal cost (SRMC), and in capital intensive
industries, such as generation and transmission/distribution, SRMC < AC
(average costs).
Thus only under very strict assumptions regarding the
composition of plant (the SRMC profile), the nature of losses, the probability of
congestion events and the absence of regulatory limits on prices will the industry
cover its fixed costs;

fixed costs will be covered under full hedging if Pc covers average generation costs
and transmission contracts cover average transmission costs. If, as observed in
competitive electricity markets, Pc  f ( Pj , Pi  Pn ) rather than Pc = AC, fixed
costs may not be covered. Consider also the impacts of full hedging on Pj …Pn as
discussed in the NSW Government's 3rd tranche vesting contract authorisation
application ie. full hedging with swap contracts encourages spot prices to reflect
SRMC; and

electricity networks exhibit technological externalities resulting from changes in
supply, load and network capacity/augmentation. The literature is inconclusive
on the extent to which full hedging with market priced transmission contracts
internalises these externalities. Nevertheless, this is an important issue and is
explicitly considered in the NECA pricing review. See discussion below;
As noted above, the benchmark model of full nodal pricing has not been implemented
in Australia. These departures from the "benchmark" market model reflect a range of
policy objectives including network pricing arrangements designed to deal with:

the recovery of fixed cost; and

the distributional impacts of locational price differences.
These departures from the benchmark model involve extensive regulatory
interventions. It is the nature of these interventions which are the focus of the NECA
review.
We can adapt the simple market model above to reflect the broad institutional
arrangements incorporated into the NEM. We then use the model to examine the issue
of “compensation” payments for technological externalities as partly proposed in the
NECA Options paper.
Under the NEM:
1.
Network charges are separated from energy charges;
2.
congestion costs are reflected in regional boundaries and locational price
differences; and
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3.
intra-regional losses are reflected in “static loss factors”.
Ignoring for the moment the effectiveness of these arrangements, the revenue position
of generator i as presented in the nodal pricing model above is modified as follows:
Ri1  Pi1 * q 1
where:
Pi1  Pj1 * li
Note l i is the static loss factor for node i relative to the reference node and
conceptually represents the expected average of the projected marginal losses at i. In
practise it is estimated using historical data but could be estimated prospectively using
load flow modelling. Note that under the interim market arrangements static loss
factors are estimated so as not to result in settlement residues whereas this constraint
will not apply under the NEM proper. Under the NEM, settlement residues will
accumulate and be redistributed through rebates on network charges. The switch in
method can be expected to change locational signals and distributional impacts
depending on the choice of revenue distribution method.
Assume in period 2 that a new entrant embedded generator has caused a change in
expected losses and congestion costs. However, as noted above, not all network effects
give rise to a theoretical case for compensation. To understand this point a clear
distinction needs to be drawn between technological externalities (an equilibrium with
unexploited gains from trade) and pecuniary externalities which reflect financial
impacts resulting from trade (see Liebowitz & Margolis (1994)). An example of the
latter is where a new entrant generator locates at a node with relatively high losses
resulting in a reduction in the losses at that node and a market driven change in the
pattern of dispatch. In turn this will impact on revenues accruing to other generators.
In effect pecuniary externalities simply reflect the operation of the market. In practice
the distinction between pecuniary and technological externalities may be difficult to
draw thus bringing in to question the efficacy of the compensation approach.
We focus on this issue because NECA’s proposals include one element of a
“compensation” rule ie. new entrants receive payments for external benefits
(notwithstanding that post entry, another entrant may invest so as to mitigate the local
benefits created by the original entrant).
If we assume that technological externalities are concerned with changes in congestion
costs and changes in the pattern of losses are primarily pecuniary externalities we can
separate out the effects to be covered by compensation payments. Note that,
depending on the network, this may not be a robust assumption.
A comparison of R i1 and R i2 (revenue post entry of embedded generation) provides
the framework for considering the internalisation or compensation payments.
From above Ri2  Pi 2 * q 2 where Pi 2  Pj2 * l i2 .
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Other things being equal, except for the externality creating entry, the impact of the
externality on generator i is the change in revenue due to a changed loss factor plus the
changes to congestion costs. The former is represented as:

q 2 * Pi 2  Pi 2*

where:
Pi 2*  Pj2 *
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l i1
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Revenue changes due to congestion effects are given by:

Ri1  Ri2  q 2 * ( Pi 2  Pi 2* )
=
=
=
P
1
i
 

 
* q1  Pi 2 * q 2  q 2 * ( Pi 2  Pi 2* )
P
i
1


* q 1  q 2 Pi 2  Pi 2  Pi 2*
P
1
i


* q1  q 2 2Pi 2  Pi 2*



Under our limiting assumption, a compensation rule requires payments (both +ve and
–ve) equal to the change in revenues due to changed congestion costs to be made to
incumbents prior to any net benefit payment to the new entrant.
Note that this approach applies a broad rule for separating pecuniary and
technological external effects which may not be robust.
The compensation principle reflects the maintenance of a defined standard of service
(in this case an expectation of future congestion costs) and is consistent with NECA’s
broad approach. But it must apply to both incumbents and entrants.
Since the simple model encompasses only a single bilateral relationship there are a
number of implementation issues:

conceptually all prices and quantities are expectations (future values) therefore
estimation is, in part, subjective. This puts an added burden on the regulator who,
presumably would be responsible for estimating the impacts; and

when extended to all possible network interactions this approach becomes
computationally complex (perhaps intractable). However, simulations based on
this approach could inform on the materiality of potential technological
externalities arising from network investment irrespective of whether the
investment is alternative forms of network augmentation or embedded
generation.
The simple analysis of compensation for technological externalities highlights that
symmetrical treatment of incumbents and entrants is important and that
implementation is problematic. This issue requires considerably more work before a
final decision is made.
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References
Bushnell, J.B and Stoft, S.E (1996)
Electric Grid Investment Under a Contract
Network Regime, Journal of Regulatory
Economics, 10, 61-79
Chao, H and Peck, S (1996)
A Market Mechanism for Electric Power
Transmission, Journal of Regulatory
Economics, 10, 25-29
Hogan, W (1992)
Contract Networks for Electric Power
Transmission Journal of Regulatory
Economics, 4, 211-242
Liebowitz, S.J and Margolis, S.E (1994)
Network Externality:
Tragedy,
Journal
Perspectives, 8
An
of
Uncommon
Economic
Wu, F; Varaiya, P; Spiller, P and Oren, S Folk Theorems on Transmission Access:
Proofs and Counter examples Journal of
(1996)
Regulatory Economics, 10, 5-23
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