JOINT MARKET DIRECTION REVIEW
ISSUES AND PRINCIPLES
November 1999
National Electricity Code Administrator Limited
ACN 073 942 775
Contents
1.
Introduction
1
2.
Role and objectives of market direction provisions
1
3.
The components of a direction
3
4.
Current arrangements
9
5.
Participant perspective
11
6.
Principles for directions
11
7.
Consultation questions
13
8.
Appendix
15
9.
References
19
i
1.
Introduction
NECA and NEMMCO are jointly undertaking a review of power system directions in the
national electricity market in accordance with clause 4.8.9(j). The review is to consider the
arrangements under which NEMMCO may issue directions that effect the overall operation of
the power system and market and in particular:

a consistent framework for directions

arrangements for issuing directions

pricing during periods of direction

payments for parties arising from directions, and

funding of those payments
Other NEMMCO powers relating to directions to disconnect loads or generators or detailed
technical aspects such as the characteristics of equipment protection and control systems of
individual participants are not covered by the review. Reserve trader provisions are also not part
of the review.
This paper develops a framework for the review, identifying the objectives and key issues under
consideration. It assesses the current arrangements and develops possible principles for amended
provisions for directions.
Comments and contributions towards the review are sought, particularly on the questions posed
at the end of this paper.
2.
Role and objectives of market direction provisions
The power to direct is a part of the safety net arrangements in the market which are for
NEMMCO to use if one of the normal market mechanisms do not function adequately. The
normal mechanisms include the bidding, dispatch and common clearing price arrangements in
the energy market and the current central ancillary service contracting process.
The safety nets are designed to ensure three essential constraints on the operation of the
competitive market arrangements are maintained. These “essential outcomes” are:

a secure operating state;

public safety and other obligations required under the National Electricity Law and

a reliable operating state
The requirements for secure and reliable operating states are specified in the Code. A secure
operating state ensures the power system is technically viable and is an essential criterion for ongoing operation of the market and hence the ability to supply customers.
A reliable operating state ensures that the balance between supply and demand enables customer
requirements to be met within the standards set by the Reliability Panel.
1
NEMMCO have presented more detailed discussions of the role of market directions is given in
the two papers “Comparison of National Electricity Code Intervention Compensation
Provisions” and Generator Direction Methodology – Draft Determination” which are listed in the
bibliography.
2.1
Criteria for effectiveness
To be effective in their role, it is proposed that the market direction provisions will need to
satisfy a number of criteria including:

Last resort. The provisions should be invoked only in the last resort, when it is clear
that normal mechanisms cannot be relied upon and that issuing a direction is likely to
be an effective means to ensure the essential outcomes are met.

Efficiency. The provisions should be consistent with achieving efficient market
outcomes. In particular:
 Minimise distortion. Ideally, issuing a market direction should minimally distort
market processes.
 Promote cost-effective system security and reliability. Within the context
defined by other Code provisions, the market direction clauses should help
achieve cost effective system security and reliability.
 Transaction cost. The market direction provisions should be cost-effective to
administer.

Equity. Directed participants should be entitled to fair compensation. There
should be no unfair discrimination in selecting which participants are to be subject
to direction. Inequitable impacts on other market participants should be
minimised.

Social objectives. The provisions should be consistent with meeting specified
social objectives such as the maintenance of public safety and the maintenance of
supply to sensitive loads.

Transparency. The processes for initiating and executing directions and
establishing compensation should be clear, open and auditable.

NEMMCO accountability and auditability. The provisions should be designed
so that NEMMCO, as the party responsible for initiating directions, should have
adequate incentives to ensure that directions are only issued when appropriate,
and are then appropriately formulated and executed.

Practicality. The provisions should be practical to implement ‘on the run’ under
control room conditions. They should not require more stringent assessment of
system and market conditions than would reasonably be achievable in such
circumstances.

Compatibility. The market direction provisions should be compatible with other
Code provisions and market processes.
Some of these criteria may conflict to some extent and judgement will therefore be required in
order to arrive at a balance that best promotes market objectives.
2
3.
The components of a direction
Directions can be assessed and designed by considering the conditions and circumstances of their
use and impact on the market and individual participants.
3.1
When should a direction be issued?
As noted, directions are intended to be safety net provisions that are to be used when normal
market and administrative processes do not achieve essential security, reliability or public safety
outcomes. The use of and the very existence of a power of direction may introduce distortions
and potentially prejudice the future operation of the normal market processes. For this reason, it
is considered that directions should be a last resort.
It is important that use of the power to direct be restricted to occasions when there has been a
failure to maintain one of the “essential outcomes” within which the competitive market
arrangements are designed to operate – they should not be invoked for the failure of a process
alone. For example, a potential new ancillary service which has been discussed as part of
NEMMCO’s review of ancillary services is described as “spot market trading benefit”. That
service is aimed at improving the efficiency of spot market trading by, for example,
economically enhancing the operational capability of the network. It does not directly address
any of the three “essential outcomes” for market operation described above. If the market
process to acquire this service fail to attract all economic resources able to enhance spot market
trading, but the three essential outcomes have been satisfied, it would represent a failure of the
process for that ancillary service, but not warrant a direction. On the other hand, if the current
ancillary service arrangements failed to attract sufficient capability to meet, say, the frequency
standards, the power system would not be in a secure operating state and a direction would be
warranted.
The accountability and auditability criteria require that NEMMCO clearly and transparently
analyse which one, or more of the essential constraints have not been met. Recent reviews of the
determination of compensation for direction under clause 4.8.9 by NEMMCO (NEMMCO
1999), and a review by NECA (NECA 1999b) of NEMMCO’s exercise of the power to direct
have highlighted the difficulty of currently making this distinction. Thus, if any of the
commercial provisions relating to direction are dependent on the reason the direction is given, it
will be essential that the distinction is very clear.
A number of approaches to provide clarity are possible.
Reliability. The market clearing price for energy is set at the regional reference node, and is set
to VoLL if involuntary load shedding is instituted due to a supply-demand imbalance at the
regional reference node, but not if it is a localised imbalance remote from the reference node.
The Code requires use of ”what if” pricing if a reliability direction is issued but it is not clear
how a localised reliability matter should be handled – this is an example of one of the
deficiencies of the current provisions. Under NEMMCO’s current arrangements, a reliability
direction would only apply where there is a supply deficiency at the regional level, and local
deficiencies are treated as network constraints or alternatively security directions, with that
distinction being unclear.
The matter could be clarified by allowing reliability directions for both regional and local supply
deficiencies, and by making a clear distinction between them as either local and regional
3
reliability directions. Alternatively, reliability directions could be clarified as being limited to
regional imbalances only, as is the current practice. By default, local reliability imbalances
corrected through a direction would then remain security directions, or a network constraint, but
the distinction would need to be clarified to provide transparency and clarity for the associated
commercial consequences.
Similar consideration could apply to ancillary services, although in the absence of market
clearing prices for ancillary services, prices and commercial arrangements are not related to the
reference node. Arising from the above a clearer definition of reliable and secure operating
states is desirable. This matter is discussed further in the section dealing with price impacts.
Secure operating state. Assessment of whether the power system is in a secure operating state
is based on a technical assessment by NEMMCO against operating standards and limits. This is
also discussed further in the section dealing with price impacts and consolidated in the proposed
principles for directions at the conclusion of the paper.
3.2
How should a direction be issued?
It is proposed that the processes for issuing directions should be designed to promote
transparency, accountability and auditability i.e. they should also minimise transaction costs and
the risk of disputes.
The details of particular directions should minimise distortions to market outcomes by restricting
the period of direction and minimising the payments likely to be required to directed and third
parties. This will require consideration of the minimum dispatch level and time of directed
participants.
3.3
The effect on market price
Currently, a common market clearing price is calculated only for energy. In the future there may
be a number of additional half hour markets for various ancillary services, and common market
clearing prices may be calculated for each of these.
There are two principal options for how a market clearing price should be calculated when a
direction has been issued;

“what if” pricing, where the clearing price is calculated as if the direction had not
been issued. This requires a calculation of the market dispatch and, from that, the
price that would have applied in the absence of the dispatch of the directed plant;
and;

“out-turn price”, where clearing price is calculated in the normal manner from
dispatched bids and offers including the impact of the direction.
If a reliable operating state is not achieved, or is forecast not to be achieved, it indicates a
deficiency or limitation in the energy market outcomes at the time. A direction may bring
additional resources to the energy market to remove or reduce the shortage. “What if” pricing
ensures the market scarcity signal is restored and signals the need for additional market response
and also fully remunerates participants in the market at the time. Similarly, if a direction has
been issued for an ancillary service due to a failure to meet the requirement for a secure system,
then ideally the ancillary service clearing price could also be a what if price in the relevant
4
ancillary service market. In practice however the transaction cost and complexity of what if
pricing for ancillary services may mean it should not be pursued.
A further consideration is that dispatch in one market will often be reflected in other markets
regardless of whether it is the result of a direction or a market response. It may therefore be
considered distortionary to calculate a what-if price in other markets based on the absence of the
direction in the first. If this were the case it would result in a signal for extra capacity in, say, the
energy market due to a shortage of an ancillary service.
On the other hand if outturn price is used for all market clearing prices when a direction is
issued, the market prices will be the level that they would have been if the deficiency had not
occurred. There would therefore be no signal of a shortage in the relevant market to provide an
incentive for it to be redressed through the market. Perversely, market price may fall as directed
plant enters the market if it has a minimum loading level. This is distortionary and
counterproductive. It also suggests that where one of the essential outcomes is not achieved in an
area of the market where a clearing price is not used (eg current ancillary service arrangements)
“what if” pricing should not apply in any part of the market.
Although market-clearing prices are likely to be introduced over time for some of the
mechanisms to achieve a secure operating state, it is unlikely that this will be the case for all
mechanisms.
Overall, what if pricing is inherently more complex than outturn pricing. However, outturn
pricing during a direction can be distortionary and require more complex compensation regimes
to provide equity. This issue is further discussed in Section 3.4 which deals with payments to
affected parties.
The impact on when to issue a direction. Section 3.1 discussed the need for clearer definition
of categories of direction, and noted that the design might be influenced by the wider market
implications on price. Further, before the principal of using a what-if price in the directed
market is applied, it is important to assess how practical this will be.
As discussed earlier, the failure to achieve a reliable operating state may be defined as a supply
imbalance either at the regional reference node only, or, at any node. If it is the former then
reliability directions would be able to be issued only if a supply imbalance occurred at the
reference node. All reliability directions would result in ‘what if’ pricing. Imbalances at other
nodes, for example due to local network constraints would, by default, be system security
violations or network constraints. Alternatively, directions could be subdivided into regional and
local directions. Only regional imbalances, corrected by a direction, would result in ‘what if’
pricing.
Similar considerations apply to system security, where for example a localised deficiency in
reactive supply could only be resolved with a localised direction – if a market clearing price was
being set at a regional reference node for regional reactive supply it would not be appropriate to
use a what if price for the entire region.
Where a single “essential outcome” has not been met it will be possible to relatively simply
define the sector of the market in which a directed market outcome has occurred. However,
where more than one of the essential outcomes have not been satisfied the situation is more
complex. For example, if a network element becomes overloaded because of a breakdown of a
5
generator and, as a result there is insufficient generation capacity to supply demand, then action
will be needed to restore the network loading to a safe level - a security issue - and to balance
supply and demand - a reliability issue. A number of approaches are possible to clarify this
matter. A priority could be assigned to the essential outcomes or incremental restoration of each
outcome sought through multiple directions – necessitating complex multiple ‘what-if’ pricing or
alternatively assignment of a principal cause on the basis of rules. Of these, a priority to
maintaining a secure operating condition is proposed as the most sound and pragmatic approach.
This is predicated on the need for a secure operating state as a pre-condition for commercial
trading.
If reliability is still below the relevant standard after a secure operating state has been restored, a
direction to achieve a reliable operating state could follow. This is consistent with the role of
ancillary services as the means of allowing the market to operate safely within a trading interval.
Once a direction has restored a secure operating state it may no longer be necessary, and it
should be removed, ideally to be replaced with a normal mechanism such as a revised network
constraint, but if necessary a reliability direction.
It is also possible to consider having no distinction on the basis of why the direction is given.
Whilst this would reduce the complexity of the arrangements it does not allow efficient prices to
be generated in the current environment where there is a mix of pricing arrangements which
include half hour spot prices, contract prices and codified obligations. As has already been
noted, if a generator was directed to alter its dispatch to provide an ancillary service normally
provided under contract, the energy market outturn price correctly reflects the energy market
supply and demand balance. It is not an option to operate the energy market unless a secure
operating state exists and hence the energy market price should be seen as independent of how
the ancillary service was brought to market. Importantly though, the ancillary service pricing
arrangements should ideally reflect a shortage condition.
Secondary effects between markets may occur for example due to a manually determined level
of dispatch under direction in one market perturbing the dispatch in another from what it would
otherwise have been had the SPD optimised the initial dispatch. These secondary effects on
market price pragmatically could be neglected and direction in one market assumed to have no
effect on market price in other markets. This would avoid the need for a range of additional
compensation in those markets.
Although many situations requiring use of a reliability safety net will be based on a forecast of
an unreliable condition, shortages will be manifested in real time by operation of the power
system outside secure operating state limits. To avoid confusion, it may therefore be desirable to
provide a set of guidelines for the categorisation of directions at certain points in time. One
option may be to require that a security direction be reviewed as soon as possible, but after no
more than, say, 15 minutes. If it is necessary to continue a direction after this time, the
guidelines could require that it be replaced, ideally with a normal market mechanism or with a
reliability direction, providing that a secure operating condition is maintained. The security
direction should stay in place if a reliability direction would be ineffective in resolving the
original problem.
3.4
Payment to affected parties
There are arguably two categories of affected party
6
Directed parties. A directed party is likely to incur costs and may lose commercial
opportunities at other times, but will have delivered a service to the market as a result of
complying with a direction. The criteria of minimising distortion and providing equity in making
payments to affected parties must be carefully balanced.
Payments to directed parties can be based on fair market value for the service provided or
designed to return the directed party to the position they would have been in, in the absence of
the direction. This second goal is achieved through payment of out-of pocket expenses only.
Distortion can occur if the incentives created by these payment are too high or too low.
Considerable concern has been expressed at various times at the potential for manipulation of the
calculation of market value. It is likely that the opportunity to unfairly influence market price
will only exist where a competitive real time market process is being used to acquire the service
in the first instance. These processes may fail because they were inadequately designed – in
which case a redesign should be undertaken, or alternatively because there is insufficient
competition for that service at that time and the directed party believes their commercial position
is better served by forcing direction. If the price or other payment is not related to prevailing
market conditions the potential for manipulation is much less of an issue.
Out of pocket expenses as the basis for payment has the advantage of removing any incentive to
manipulate the arrangement to achieve a higher revenue, but may provide a perverse incentive
for the directed party to claim an inability to respond to the direction. Where it currently exists
in the Code, out-of-pocket expenses, as a principle for payment, is part of an overall intervention
package. It acts as an incentive for parties to participate in the market and in reserve trader
contracting, as it is understood that a direction may be applied if these processes do not result in
satisfactory outcomes. The reliability safety net arrangements are based on establishing a market
rate for reserve contracts as the first level of intervention and thus recognises the value of the
delivered service. Payment of out-of pocket expenses on the other hand does not attempt to
recognise the value of the service provided .
Distortion will occur if the balance of risk and reward under direction provides an incentive for
participants who can reasonably participate in the market to withdraw at a time when they are
likely to be directed to re-enter and, receive a higher effective return. In this instance the market
price will be uneconomically increased by withdrawal and use of what-if pricing, yet the
participant is assured of payment. If this is considered to be the most likely scenario, limiting
payment to out-of–pocket expenses for direction can be considered as a punitive measure to
discourage this tactic.
Distortion can also occur if the reward as a result of direction creates an incentive for
participants likely to be directed to uneconomically remain in the market in order to avoid
direction, as the lesser of two evils. In this instance, the market price will be depressed by the
participant remaining in the market and therefore stifle the incentive for cost effective market
based responses. There may also be an incentive for the participant to withdraw but claim an
inability to respond to direction.
In practice both situations may occur. Since the start of the NEM directions have been
predominantly for short notice events. In some instances the direction may arguably have been
avoided by additional participation but in others the situations arose at such short notice there
was no opportunity for withdrawal to force a higher payment.
7
A balance between these issues might be achieved if the level of direction payment leaves
directed participants indifferent to whether they voluntarily participate or accept direction, but
offers the potential for higher return from voluntary market participation. This principle would
aim to balance the competing issues of meeting a legitimate need for adequate payment; paying a
fair value for the directed service, restraining opportunities for un-competitive manipulation that
may otherwise be perceived and offer an incentive for wider participation in the market. Details
of the arrangements would be designed to minimise disputation and aim to be simple and cost
effective to administer. A critical element would be the use of defined methodologies and
decisions in advance about how a fair market price would be determined if a direction occurs.
An outline of payments under the proposition are as follows:

under direction, the market price would be set to the “what-if” level in the directed
market only.

directed participants would be entitled to a fair market value for the directed service.

the assessment of fair market value would be based on a predetermined set of
specific guidelines set down in the Code so that the methodology is as well defined
as possible;

a participant would be entitled to present a claim that payment of the fair market
value under the predetermined approach would not cover costs incurred plus a
commercial return

Full details to substantiate the claim would be required from the participant.
Further details of this proposal are presented in the proposed principles for directions which
appear at the conclusion of this paper.
Payment to third parties. Where either the price or volume of a third party is affected by the
direction, compensation may be necessary to provide equity to those parties.
In principle this payment could also be designed to pay out-of-pocket expenses or fair market
value. There has been little argument that fair market value should be adopted for third parties
on the grounds of equity and a view that these parties are unlikely to have distorted the need for
the direction. Use of the what-if price as the market clearing price automatically adjusts
payments and charges for price impacts for dispatched plant. The what-if price, however, means
that for those participants whose dispatch was effected by the direction, the market price and
their dispatch are no longer consistent. This is an unavoidable consequence of the use of what-if
pricing.
If payment is made to adjust for volume effects on third parties at the difference between the
what-if spot price and the bid/offer price, participants will have the opportunity to manage
exposure to hedge contract obligations, but only in relation to dispatched volumes. Absent
contracts, payment at this rate would, however, pay the profit component of foregone dispatch at
the what-if price. This may be seen as an over-payment. Alternatively it may be considered as
providing an equitable payment for capacity presented at a time of scarcity and only not fully
dispatched because there was insufficient offered in aggregate by other participants,
necessitating direction. It should be noted that third party effects on dispatch are more likely to
occur before or after the time of potential shortage. This may occur, if a generator is directed to
dispatch at a minimum level in advance of a shortage or to provide reserve to ensure it is in
8
service at the time of the potential shortage. At times when the potential shortage would have
occurred it is less likely that there will be an effect on dispatch of third parties as all plant will be
dispatched. This effect should be taken into consideration in the selection of who and when to
direct.
3.5
How are the payments funded?
Funding of payment for directions may be based on identifying the implicit purchaser of the
service that was acquired under direction. The amount to be raised from those purchasers and
paid to the suppliers has been discussed in the preceding section on payments. The alternative of
attempting to identify the parties causing the need for a direction or benefiting is fraught with
problems and considered to be impractical. A particular direction may be due to legitimate or
contrived reductions in supply capability, errors in demand forecasting or inadequate risk
management activity by customers including as a consequence of genuinely extreme conditions,
or, inherent limitations in market mechanisms or design. The causer party would be likely to
vary from case to case and would be open to dispute.
Section 2 discussed direction as a substitute for a failed market process. On this basis the parties
who would have paid for the service or commodity in the normal market process are the
purchasers, but through direction rather than the normal process. This suggests that where it is
possible to identify the normal purchaser of particular services, funding should be from those
parties. In the case of a reliability direction, payment would therefore be on the basis of
purchased electricity by market customers. The funding of ancillary services directions would
be sourced from the parties responsible for funding the particular ancillary service – perhaps on
the basis of recent history where a market clearing price is not applicable. Where an incentive
can be introduced it is feasible for a reduced funding obligation for parties who have acted to
reduce the need for the direction by their action in the normal process to acquire the service or
product.
This approach is consistent with the criteria for minimising distortion, is simple and transparent
as it is based on the normal market funding sources.
There may also be residual payments not normally a part of the market, for example, due to a
direction to ensure public safety. There has been one instance of this since the start of the NEM.
On one hand, public safety can be seen as a pre-condition for trading and thus, shared between
all participants. On the other hand, it is to the benefit of the community at large and best borne
by retailers on behalf of end use consumers.
4.
Current arrangements
The current provisions of the Code and the National Electricity Law allow for directions for
reliability, power system security and ancillary services as separate categories of direction. Each
of the powers to direct is required to be used as a last resort.
Reliability Directions. Provisions for reliability direction are closely linked to those for reserve
trader. Reliability directions are triggered by a failure to meet capacity reserve threshold levels
which are calculated to ensure overall reliability meets the standard set by the Reliability Panel.
Market price is calculated on a what-if basis.
9
Payment to directed parties for directions for reliability is currently determined by an
independent expert on the basis of out-of-pocket expenses. A code change arising from a recent
review by NECA (ref) for this to be based on market value has been submitted to the ACCC.
This is part of a package of changes which includes the replacement of the existing reserve trader
arrangements with a more flexible reliability safety net and proposed changes to VoLL. To date
all interventions for reliability have been through short term direction – there have been no
occasions when the longer term reserve contracting arrangements have been appropriate or a
practical option.
Funding is on the basis of energy consumption by wholesale purchasers. The Code change
which deals with payment arrangements also seeks a change to exclude demand side bidders
from the obligation to contribute to the payment as recognition that reserve capacity is not
required to be held for demand side bids, as these loads have bid to be interrupted at high prices.
Ancillary services. Schedule 9G and Clause 3.11 state, in part, that ancillary services are
essential for the management of power system security and recognise that some ancillary
services will be contracted by NEMMCO and others obtained through other means including
connection agreements between participants and network service providers.
Ancillary services contracted by NEMMCO are paid for at the contracted rates. Clause 5.8 of
Schedule 9G allows NEMMCO to issue directions to acquire ancillary service capability,
providing the normal contracting provisions have been complied with. Payment for directed
ancillary services is the higher of:

market value of the ancillary service provided under the direction (determined by
taking into account any existing agreements for provision of the service); and

the additional cost incurred in complying with the directions.
plus constraint payments, which are designed to compensate for the impact of the direction on
the participant’s energy market position.
System security and the National Electricity Law. Clause 4.8.9 of the Code and section 76 of
the NEL empowers NEMMCO to issue directions for reasons of public safety or the security of
the electricity system. Prior to exercising the power NEMMCO is obliged to use reasonable
endeavours to comply with processes in chapter 3 in relation to use of market based mechanisms
to, for example, acquire ancillary services. Clause 4.8.9 also requires NEMMCO to develop a
method for generator direction compensation for power system security directions. NEMMCO
completed this review in July (NEMMCO 1999a) and proposed that payment for directions for
system security be aligned with those for ancillary services. NEMMCO also sought a derogation
to delay payment until funding provisions had been codified. A derogation to this effect has
recently been authorised.
Under the current arrangements, “what-if” pricing is used if a direction for reliability is issued
but “out-turn” price is used for directions for ancillary services or power system security. This is
consistent with the conclusion of the earlier discussion in relation to minimising market
distortion.
The current arrangements suffer from inadequate transparency and are also less than practical to
implement. The difference between the need for a direction to maintain system security, to
provide ancillary services and at times for reliability is problematic and potentially open to
10
dispute. NEMMCO (1999a) discusses the inherent and unavoidable difficulty of deciding in all
cases which power to exercise under the current arrangements.
Examples of events that are difficult to classify as reliability, system security or ancillary service
problems are provided in an Appendix and in submissions to NEMMCO’s review of
compensation. NEMMCO could currently respond to such events using any of the three types of
direction. Concern was expressed in a number of submissions that the different types of
direction available to NEMMCO placed NEMMCO in a difficult position and that the market
design could encourage NEMMCO to prefer one type of direction over another.1
It has already been noted that ancillary services are a means to achieve a secure operating state.
It therefore appears that there is little reason to maintain separate powers and materially different
market outcomes for ancillary services and other system security directions.
The very specific nature of the current arrangements is also not readily adapted to the emerging
conclusions of the current NEMMCO ancillary services review, in particular, how a direction for
one service will impact the market in others.
NEMMCO have found that in practice there are high transaction costs associated with the
assessment of compensation for ancillary services. These arise because there is greater scope for
dispute on the value of the ancillary services provided than is the case with reliability directions.
Assessment of compensation amounts under the current provisions for reliability directions has
proved much more cost effective, though still expensive to administer. This is due to the much
more prescriptive arrangements for reliability directions than for ancillary service compensation
arrangements.
5.
Participant perspective
A participant effected by a direction is most likely to be concerned with the impact on their
volume and / or price. It is anticipated that they will be much less concerned with the reason the
direction occurred than with obtaining a fair payment for the affect the direction had on their
operations. To determine the size of the effect it is necessary to identify what the market
outcome would have been in the absence of the direction.
This is achieved by “what-if” pricing in the directly affected market. It is the same outcome that
was derived from a market incentive analysis and the objective of minimising distortion in
section 3.
Further, it is anticipated that a directed participant will most likely seek a market value for
services acquired. Subject to control of any monopoly power and un-competitive opportunities
this approach is also consistent with earlier analysis.
6.
Principles for directions
NECA and NEMMCO agree with participants who have called for a review of the provisions in
the Code for directions. The lack of clarity and transparency in the current provisions carries too
Submissions received as part of NEMMCO’s consultation on a payment methodology for system
security directions — see NEMMCO (1999a).
1
11
high a burden of transaction cost and potential for dispute. Table 1 illustrates the range of options
for type, impact on market price, payment and funding.
This section presents for consultation and comment, a set of consolidated principles which
emerge from our consideration of the major issues in this paper. The proposed principles are
designed to balance the objectives and criteria presented in the discussion above. Consultation
questions seek views on the proposed objectives, criteria and principles.
6.1
When to direct?
Directions should be a last resort if any of the following conditions is not being met, or is
forecast not to be achieved:



a secure operating state;
public safety, or other relevant obligation under the National Electricity Law; or
a reliable operating state;
Directions may be given in respect of a region or a part of a region.
6.2
How to direct?
A direction should be issued to achieve a secure operating state and public safety in the first
instance, by directing to acquire additional ancillary services where possible.
A further direction to achieve a reliable operating state could be issued if necessary in addition to
the security direction, or after the security direction is removed. Directions to ensure a secure
operating state should be reviewed regularly, say each 15 minutes, and where it is effective
replaced with normal market process such as a network constraint or with a reliability direction.
Directed parties should be chosen to minimise the length of time of direction and any payment to
directed or third parties. Dispatch of directed plant should be minimised.
Directed participants will be entitled to remain in or re-enter the market after a direction has
ceased, in this circumstance provision for offsetting cost based claims could operate – see below.
NEMMCO are currently able to disallow a planned network outage on the basis of reduced
system security or reliability. This is not currently defined as a use of a power of direction. No
change is suggested to this for regulated networks as they are not a part of the energy market and
the outage does not form a part of ancillary service arrangements. This position should be
reviewed if network participation in energy market or ancillary service processes is amended.
Directions to market network service providers should however by regarded as a direction in the
relevant market.
6.3
Market clearing price
For those segments of the overall market where a half hourly clearing price is set what if price
should ideally be used for any market where a direction has been given. The practicability of
using a what if price for ancillary service markets has not yet been assessed.
Outturn price in other market segments.
12
Directions which do not directly effect participation in a market where a half hourly clearing
price is set would not result in use of what if prices in any market segment.
6.4
Payment to directed parties
Payment should in principle be a competitive market value.
Assessment of market value should be designed to ensure it is a fair market value. It should be
based on a methodology established in advance. The methodology should seek to minimise the
risk of disputation, be transparent and cost-effective.
The market value can be established from:

where relevant, the prevailing market price where it was accepted, in advance, that is
was likely to be competitive during a period of a direction;

prevailing contract rates for that service (for example for ancillary services) ;

previous bid and offer prices of the directed participant over an extended and defined
period of time. This would be taken as an indication of the price that the participant
believed was a fair return. A rule based methodology would need to be developed;

industry benchmark prices determined in advance on expert advice; or

cost plus a commercial rate of return
If after receiving a direction a participant remains in or re-enters the market later in the same
trading day, claims for costs in excess of the prevailing fair market rate could be offset against
any market revenue in excess of bid/offer prices after the direction ceases.
6.5
Payment to third parties
In principle payment should be revenue neutral to the direction itself but provide an incentive for
participation in the market.
No adjustment beyond that which flows from use of what-if pricing described in section 6.3
should be made for price effects.
Consultation input is sought on the merits of paying a compensation for volume effects of
scheduled units whose dispatch has been effected by direction. Section 3.4 discussed the issues
in relation to this matter.
6.6.
Funding
Where feasible funding should be from parties which normally fund the product or service.
Otherwise (eg for public safety direction) from a customer or market levy.
Targeted exemptions from funding would be included to recognise behaviour and action to
reduce the need for direction.
A flow chart which illustrates these design principles is attached.
13
7.
Consultation questions

Is the role of directions proposed in section 3 appropriate?

Are the criteria for effectiveness of directions (section 3) appropriate?

Is the assessment that the current arrangements are unsatisfactory supported in
particular that the different power and treatment of directions for system security and
ancillary service should not be retained and that the current arrangements lack
clarity?

Are the proposed principles for the design of provisions in relation to when and how
to direct and the impact on market price, payments and funding appropriate?
Submissions are requested by Friday 10 December 1999 to either
Murray Chapman:
Email to:
murray [email protected]
Fax:
02 9251 6380
Greg Thorpe
Email to:
[email protected]
Fax:
08 8213 6300
Submissions received after this date may not be taken into account.
14
Directions and Market Price Flow Chart
Normal Market
Processes
Direct A.S *
Y
Regional A.S.?
Y
Is
clearing price set ?
Subject to further
consideration:
What if price for
directed A.S.
N
Y
N
Secure?
Resolve
by direction
for defined
A.S?
N (Local)
N
Outturn price
for all A.S.
Direct
(Other) *
Y
* Review after 15 Minutes
N
Safe?
What if price
for energy
Y
Y
N
Reliable?
Direct
Regional
Direction?
Outturn price
for energy
N (Local)
Y
When to direct
(Last Resort)
How to direct
Market Price
Appendix: Test Scenarios
In assessing the comprehensiveness and clarity of the framework for interventions, it is often
helpful to consider how a number of scenarios would be dealt with by the arrangements. The
following scenarios are put forward to help assess the success of any proposed changes to the
existing framework.
Test Scenario 1
Consider a case where the power system is operating in a satisfactory operating state, but
analysis shows that it would not remain in a satisfactory operating state following a single
credible contingency event.
In such a case, the power system is not in a Secure Operating
State, so that NEMMCO is required to take action to restore security. Under the current
arrangements, the options for NEMMCO may include:
Impose a network constraint to constrain on or off generation as appropriate; or
Issue a power system security direction to direct generators to outputs that differ from the
dispatch targets calculated by the dispatch algorithm; or
Issue an ancillary services direction to provide network loading control, frequency control or
voltage control depending upon the type of power system security violation – this would
inevitably involve some change in the level of energy generation, but would not result in “what
if” pricing.
In this case, the desired approach is considered to be for an appropriate network constraint to be
invoked at the earliest possible time. If it is necessary to issue a system security direction or
ancillary services direction prior to applying the constraint due to time limitations, then there is
an issue as to whether this direction should also be treated as a network constraint, as to do
otherwise would result in two different commercial outcomes depending on the time of
converting from one form of constraint to another.
Test Scenario 2
Consider the case where the power system is not in a secure operating state due to network
limitations, and one option to resolve the situation is to constrain a generator on. The generator
is capable of operating, but the availability offered to the market is zero. Under these conditions,
the options available to NEMMCO would be:

Issue a power system security direction to the generator to have it operate at a
specified output level to resolve the issue – “what if” pricing would not apply, and
compensation would be payable under clause 4.8.9; or

Direct the generator to bid available (a power system security direction) and then
apply a network constraint. Again, no “what-if” pricing would apply, and whilst the
Code provisions for compensation are not entirely clear for this case, a likely
outcome is that compensation could only be sought from the Network Service
Provider (NSP) for the period while the generator is being constrained on by the
16
network constraint. In any case, the lack of clarity in the Code for cases such as this
is of concern.
As the circumstance is derived from a network limitation, NEMMCO would aim to implement
the second of these options if time permitted, and would issue the first if time was a limiting
factor in terms of arranging for offers to be resubmitted and formulating and implementing the
network constraint. Again, there is an issue in that the two options can result in different
commercial outcomes.
Test Scenario 3
Consider the case where the South Australia region (SA) has only just sufficient reserve
(260MW) to satisfy Reliability Panel Reserve requirements. Assume that a 260MW generator
trips, and the Victoria to South Australia transfer level increases from 500MW to 760MW,
resulting in a number of Gas Turbine generators (GTs) receiving dispatch signals to start. One
GT generator then responds by reoffering its availability to zero, and NEMMCO issues a
direction for that generator to start. This could be classified in one of the following ways:
a) A power system security direction due to transfer level being beyond a secure
operating limit (no what if pricing ); or
b) A network loading ancillary service direction, the aim of which is to control
Network loading (no what if pricing) ; or
c) A reliability direction since by the gas turbine generator’s re-offering as
unavailable has resulted in the total reserve in SA falling below the intervention
level (what if pricing would be invoked).
Because of the critical time element in this case, NEMMCO could only immediately implement
options a) or b), and it would take 30 minutes or more to set up required constraints for option c).
17
References
ACCC (Australian Competition and Consumer Commission) 1997, Authorisation of
the National Electricity Code – 10 December 1997, ACCC, Melbourne.
(URL http://www.accc.gov.au/electric/authorisations.html, accessed 24
May 1999).
Eastern Energy 1999, Correspondence from Eastern Energy to NEMMCO, June 8
(URL http://www.nemmco.com.au/nem_resources/polproc/marketops/m
o_dc996v001c03.pdf).
Hazelwood Power 1999a, Correspondence from Hazelwood Power to NEMMCO, 9
June
(URL http://www.nemmco.com.au/nem_resources/polproc/marketops/m
o_dc996v001c04.pdf)
Hazelwood Power 1999b, Correspondence from Hazelwood Power to NEMMCO, 28
June
(URL http://www.nemmco.com.au/nem_resources/polproc/marketops/m
o_dc1050v001c02.pdf ).
NECA (National Electricity Code Administrator) 1998, The National Electricity
Code, Version 1.0, 19 October, NECA, Adelaide.
— 1999a, Capacity mechanisms in the national electricity market, Final Report,
NECA,
Adelaide,
July.
(URL http://www.neca.com.au/files/CMR_Final_Report).
— 1999b, NECA assessment of NEMMCO directions,
NECA,
Adelaide
(URL http://www.neca.com.au).
November
NEMMCO (National Electricity Market Management Company) 1998a, Operating
Procedure: Intervention and Direction, Document Number
SO_OP3707,
NEMMCO,
Melbourne,
13
October.
(URL http://www.nemmco.com.au/nem_resources/polproc/systemops/s
o_op204v004.pdf, accessed 23 August 1999)
—— 1998b, Operating Procedure: Ancillary Services, Document Number
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NEMMCO,
Melbourne,
30
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(URL http://www.nemmco.com.au/nem_resources/polproc/systemops/s
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—— 1999a, Generator Direction Compensation Methodology Draft Determination,
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——1999b, Ancillary Service Review – Notice of Consultation, NEMMCO
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(URL http://www.nemmco.com.au/nem_resources/work_groups/ancillar
y/mo_as1151.htm, accessed 20 August 1999)
18
——1999c, Consultation on Fast Start Dispatch Enhancements, NEMMCO
Communication No. 246, NEMMCO, Melbourne, 14 July.
(URL http://www.nemmco.com.au/nem_projects/market_implementatio
n/market_development/market_design/consultation_papers/mo_di1104.
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——1999d, Operating Procedure: Dispatch, Document Number SO_OP3705,
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Melbourne,
31
August.
(URL http://www.nemmco.com.au/nem_resources/polproc/systemops/so
_op101v008.pdf, accessed 1 September 1999)
—— 1999e, Comparison of National Electricity Code Intervention Compensation
Provisions, NEMMCO Communication No. 211, NEMMCO, Sydney,
25
May
1999.
(URLhttp://www.nemmco.com.au/nem_resources/polproc/marketops/mo
_dc988v001.pdf)
Snowy Hydro Trading 1999, Submission to NEMMCO Consultation for Power
System
Security
Direction
Compensation,
June
(URL http://www.nemmco.com.au/nem_resources/polproc/marketops/m
o_dc996v001c01.pdf)
19