Review of levy costs and
allocations
Attachment A
Attachment A
Glossary of abbreviations and terms
Act
Electricity Industry Act 2010
Authority
Electricity Authority
CAP
Code Amendment Principle
Code
Electricity Industry Participation Code 2010
CRA
Charles River Associates
EECA
Energy Efficiency and Conservation Authority
EMS
Energy Market Services (a division of Transpower)
FTR
Financial Transmission Right
GIP
Grid Injection Point
GXP
Grid Exit Point
ICP
Installation Control Point
MBIE
Ministry of Business, Innovation and Employment
MCA
Ministry of Consumer Affairs
MED
Ministry of Economic Development (now part of MBIE)
Minister
Minister of Energy and Resources
NZX
New Zealand Securities Exchange
PPOs
Principal Performance Obligations of the System Operator
TASC
Technical Advisory Services Contract (between the Authority and the
System Operator)
TPM
Transmission Pricing Methodology
Attachment A
Contents
Glossary of abbreviations and terms
C
1.
Introduction and summary
1
1.1
Introduction
1
1.2
Summary of conclusions
1
2.
Statutory framework
3
2.1
Crown funds Authority activities via a levy
3
2.2
Amending the Levy Regulations
4
2.3
Authority needs to demonstrate efficiency gains
5
3.
Current cost structure and allocation
7
3.1
Levy regulations establish cost categories
7
3.2
Levy Regulations determine cost allocation
8
4.
Economic framework for levy design
11
4.1
Levy design should facilitate economic efficiency
11
4.2
Nature of costs to be recovered
11
4.3
The principles applied in 2003 focussed on economic efficiency
13
4.4
Key factors influencing current allocation
14
4.5
Framework applied to TPM needs to be considered
15
4.6
Proposed principles for Levy design
16
5.
Industry Governance Costs
17
5.1
Industry governance costs incurred for benefit of consumers
17
5.2
Applying the principles
17
5.3
Current allocation of industry governance costs
19
5.4
Current allocation of industry governance costs may be efficient
20
6.
Market operations costs
21
6.1
Nature of the costs
21
6.2
Applying the principles to market operations
23
6.3
Wholesale market operations costs
24
6.4
Registry costs
25
6.5
FTR trading costs
27
Attachment A
7.
System operations costs
30
7.1
Nature of the costs
30
7.2
System operation functions
30
7.3
Applying the principles
33
7.4
Current allocation of system operations costs
34
7.5
Conclusion
35
Appendix A
: Statutory framework
37
Overview
37
Levies under s128 of the Electricity Industry Act
38
Appendix B
: Current cost structure and allocation
40
Cost structure
40
Current allocation under the Levy Regulations
42
Appendix C
: Levy provisions under the Act
44
Appendix D
: System Operator activities
46
Tables
Table 1: Expenditure categories in the existing Levy Regulations
Table 2: Allocation of costs of each activity
Table 3: Proposed principles for levy design
Table 4: Market operation service providers
Table 5: Market service provider functions
Table 6: Summary analysis of system operations activities
Table 7: Expenditure categories under the Levy Regulations
Table 8: Allocation of costs of each activity
Table 9: Levy Rates from recent 2013/14 Appropriations Consultation
Table 10: Operations Planning Functions
Table 11: Scheduling functions
Table 12: real time operations functions
Table 13: After the fact analysis functions
Table 14: Support functions
7
8
16
21
23
32
40
42
43
46
46
47
47
48
Figures
Figure 1: Levy allocation for 2013/14 under the existing levy Regulations
Figure 2: Annual costs – estimated 2013-14
9
12
Attachment A
Figure 3: Current allocation of industry governance costs
Figure 4: Annual market operating cost – estimated 2013-14
Figure 5: Overview of system operator functions
Figure 6: Breakdown of annual system operations costs
Figure 7: Current allocation of system operations costs
Figure 8: Overview of existing funding arrangements
20
21
30
31
34
37
Attachment A
1.
Introduction and summary
1.1
Introduction
1.1.1
The Authority has identified a number of issues with its current funding
arrangements. Following a review of the issues and options for addressing them,
the Authority concluded it should progress two key approaches in parallel:
(a)
introduce the ability for the Authority to charge fees in certain
circumstances through seeking an amendment to the Electricity Industry
Act 2010 (Act) and the making of Fee Regulations pursuant to the
amended Act; and
(b)
operate in a modified way within the existing legislative framework including
in particular reviewing the Levy activities identified in Table 1 of the Levy
Regulations to identify areas where more specificity and/or granularity
could deliver a better fit with the beneficiaries/users of particular services
and then seeking appropriate amendments to the Levy Regulations.
1.1.2
The focus of this paper is on approach (b) - to review the Authority’s cost
structures and the allocation to participants, to establish whether the current
allocation is efficient and whether amendments to the Levy Regulations should
be proposed.
1.1.3
This paper follows from, and draws on material from, a report prepared by
Concept Consulting Group (the Concept Report1) and considered by the Board at
its 29 June 2012 meeting.
1.2
Summary of conclusions
1.2.1
Application of efficient levy design principles suggests that:
1
(a)
the industry governance costs should be allocated to participants that
have a strong connection with end-use consumers, through a mechanism
that spreads costs as widely as possible;
(b)
the wholesale market operations costs (pricing, reconciliation,
information and clearing) should be predominantly allocated to generators
and purchasers in the wholesale electricity market based on a charge per
MWh traded;
(c)
the registry costs should be predominantly allocated to retailers and
distributors via a charge per ICP;
Review of Electricity Authority Funding Arrangements; Concept Consulting Group; June 2012
Attachment A
(d)
the FTR Manager costs should be recovered through a broad based
charge, similar to that used for wholesale market operations costs, pending
further development of, and more information on the level of activity in, FTR
trading; and
(e)
there is a case for a range of efficient user-pays charges covering factors
that exacerbate costs (including the provision of late or inaccurate data,
prudential problems, consumer switching, non-compliant and unreliable
assets, and requests for extensive systems analysis made to the system
operator), but these charges would be complex to implement within Levy
Regulations.
1.2.2
The current arrangements for the recovery of costs through the Levy Regulations
are reasonably consistent with efficient levy design principles. Any improvements
that are feasible within the framework of the Levy Regulations are unlikely to lead
to material efficiency gains.
1.2.3
If the Act is amended to allow the Authority to charge fees for its market
operations activities, further consideration should be given to a range of
supplementary user-pays charges within a fees framework.
Attachment A
2.
Statutory framework
2.1
Crown funds Authority activities via a levy
2.1.1
The Act sets out the Authority's functions. These fall into two broad categories:
2.1.2

Industry governance – the Authority makes, administers, and enforces the
rules governing the New Zealand electricity market - the Electricity Industry
Participation Code 2010 (Code)

Market operation – the Authority is responsible for running the central
systems and processes to operate the New Zealand electricity system and
market in accordance with the Code. In practice, the Authority contracts
most of these functions to a range of external service providers.
Section 128 of the Act provides for the Crown (via appropriations in Parliament)
to be the sole funder of all the Authority’s statutory functions. Appendix A
outlines the key features of section 128 including how levies are established and
the process for amending levies. The key points are that the empowering
provisions in the Act:
(a)
require the Crown to fully recover its actual costs via a levy on industry
participants;
(b)
allow for the making of Levy Regulations which specify the amount of the
levy or method of calculating or ascertaining the amount of the levy; and
(c)
provide for different levies for different classes of industry participants.
2.1.3
Although the Authority could charge a fee for activities outside those set out in
the Act, it is unclear what such activities might be. However, they could include,
for instance, the Authority providing assistance and advice to other countries
about electricity market design and hosting international visitors. As stated by the
Controller and Auditor-General in the Good Practice Guide – Charging fees for
public sector goods and services, “Public entities do not need statutory authority
to enter into contracts for commercial transactions. Such transactions are
voluntary for both parties rather than being a matter of statutory duty. An example
of a normal commercial transaction is the Department of Internal Affairs’ provision
of professional translation services to businesses, central and local government,
and private individuals. The Department is not obliged to provide these services.
The amount charged by the Translation Service is a contractual payment agreed
to by the recipient, and not a fee within the scope of this guide”.
2.1.4
Although section 115 of the Act authorises regulations to be made relating to
fees, the requirement under section 128 that the Authority’s costs are fully met
from the levy renders this inoperable for recovery of any costs that relate to the
Authority's statutory functions. It is a general regulation-making power for fees or
Attachment A
charges relating to any matter under the Act (i.e. wider than just the Authority’s
statutory functions) and makes no specific reference of the Authority or the
Minister.
2.2
Amending the Levy Regulations
2.2.1
The Governor-General may, by Order in Council made on the recommendation of
the Minister, make or amend regulations providing for the levy.
2.2.2
Historically, Levy Regulation amendments have been developed and consulted
on by either the Ministry of Economic Development (MED) or by the Electricity
Commission, prior to a recommendation being made to the Minister.
2.2.3
Although the Act specifies neither process nor principles for developing and
consulting on an amendment to the Levy Regulations, for consistency with
undertaking its functions under the Act more generally, the Authority should look
to its statutory objective and Consultation Charter.
2.2.4
Section 15 of the Act provides that the Authority's statutory objective is:
…to promote competition in, reliable supply by, and the efficient operation of,
the electricity industry for the long-term benefit of consumers.
2.2.5
2.2.6
2
The Authority interprets its statutory objective2 as requiring it to exercise its
functions in ways that, for the long-term benefit of electricity consumers:

facilitate or encourage increased competition in the markets for electricity
and electricity-related services, taking into account long-term opportunities
and incentives for efficient entry, exit, investment and innovation in those
markets;

encourage industry participants to efficiently develop and operate the
electricity system to manage security and reliability in ways that minimise
total costs whilst being robust to adverse events; and

increase the efficiency of the electricity industry, taking into account the
transaction costs of market arrangements and the administration and
compliance costs of regulation, and taking into account Commerce Act
implications for the non-competitive parts of the electricity industry,
particularly in regard to preserving efficient incentives for investment and
innovation.
The Authority’s Consultation Charter December 2010 (the Charter) sets out
guidelines relating to the processes for amending the Code and for consulting on
proposed amendments. In particular it sets out the Authority’s Code Amendment
As set out in the Authority document “Interpretation of the Authority's statutory objective” February 2011.
Attachment A
Principles (CAPs), and obliges the Authority to have regard to these principles, to
the extent that the Authority considers that they are applicable.
2.2.7
Although amending the Levy Regulations is not a Code amendment, the Charter
and the CAPs are nevertheless relevant. The Charter notes that there are other
matters on which the Authority may seek feedback from interested parties, but for
which the Authority is not required to consult under the Act. In such instances, the
Authority may adopt the general principles and processes described within the
Charter having regard to the materiality of the matter being considered, the
particular feedback sought, and other related factors.
2.2.8
The CAPs include three key high-level principles that Authority should apply to
any proposal to amend the Levy Regulations:

CAP 1 – any change must be lawful;

CAP 2 - any change must demonstrate a clear efficiency gain or resolve a
market or regulatory failure; and

CAP 3 – a quantitative cost-benefit assessment must be applied with a
particular focus on dynamic efficiency impacts.
2.3
Authority needs to demonstrate efficiency gains
2.3.1
Although an amendment to the Levy Regulations is not a Code amendment, the
Authority should adopt an approach that is consistent with the Consultation
Charter and CAPs.
2.3.2
When proposing an amendment to the Levy Regulations, the Authority should
consult with stakeholders, and any amendment should demonstrate a clear net
efficiency gain.
.
Attachment A
3.
Current cost structure and allocation
3.1
Levy regulations establish cost categories
3.1.1
The existing Levy Regulations define a number of expenditure categories or
“activities”, generally with reference to carrying out functions in relation to various
parts of the Code. The current categories are set out in Table 1, and Appendix B
describes in more detail how these categories are used as the basis for the
existing cost allocation.
Table 1: Expenditure categories in the existing Levy Regulations
3.1.2
Category
Description of activities as set out in the Code
Common quality
operations
Activities relating to Part 7 (system operator) and Part 8 (common
quality).
Market
operations
Activities relating to Part 5 (undesirable trading situations), Part 10
(metering), Part 13 (trading), Part 14 (clearing and settlement), and
Part 15 (reconciliation).
Registry and
consumer
operations
Activities relating to Part 11 (registry) and other consumer-related
activities.
Supply reliability
operations
Activities relating to Part 9 (security of supply), and sections of Part
7 (system operator) relating to security of supply, including the
Security and Reliability Council and the functions of the Authority
under section 136 of the Act.
Transmission
operations
Activities that relate to Part 12 (transport) and any costs incurred by
the Crown in preparing electricity supply and demand forecasts and
scenarios.
Electricity
Efficiency
Certain activities of the Energy Efficiency and Conservation
Authority (EECA) relating to the encouragement, promotion, and
support of electricity efficiency.
Customer
switching fund
The costs of the customer switching fund.
Other activities
Any activities not covered by other categories, including the
monitoring and enforcement of the Code.
In some areas one entity (for example, the Authority or the system operator)
undertakes functions that span more than one expenditure category. The Levy
Regulations allow for the Authority to exercise judgment in determining the split of
actual costs across the relevant expenditure categories.
Attachment A
3.2
Levy Regulations determine cost allocation
3.2.1
The Levy Regulations describe the methodology for calculating each participant’s
share of the total costs. The expenditure categories described in the previous
section are a key building block in this methodology.
3.2.2
Table 1 of the Levy Regulations sets out the allocation of each expenditure
category to participant class. It is reproduced as Table 2 in this paper.
Table 2: Allocation of costs of each activity
Activity
Classes of industry participants to whom costs are
allocated
Generators
Common quality
operations
One-third
One-third to
purchasers
Market operations
One-half
One-half to
purchasers
Registry and
consumer operations
-
One-half to retailers
Supply reliability
operations
-
All to purchasers
Transmission
operations
-
Customer switching
fund
-
Other activities
One-third
Establishment costs
relating to transition of
functions to
Commerce
Commission
-
Establishment costs
relating to Energy
Efficiency and
Conservation Authority
-
All other establishment
costs
3.2.3
Purchasers
One-third
All to retailers
One-third to
purchasers
-
All to purchasers
One-third to
purchasers
Distributors
One-third
One-half to
distributors other
than Transpower
All to Transpower
One-third
All to Transpower
-
One-third
Charts illustrating how costs are currently allocated across different activities and
recovered from each participant class are shown in Figure 1.
Attachment A
Figure 1: Levy allocation for 2013/14 under the existing levy Regulations
3.2.4
The charts in Figure 1 highlight that:
(a)
the largest part of the costs is currently allocated to the “market” activity;
(b)
a significant portion of costs is currently allocated to the “common quality”
activity;
Attachment A
(c)
the costs allocated to other activities are relatively small apart from the
“electricity efficiency” costs (which are excluded from consideration in this
paper as a special case);
(d)
purchasers in the wholesale electricity market fund the largest proportion of
total costs;
(e)
generators supplying the wholesale electricity market fund a significant
proportion of the total costs; and
(f)
other participant classes (retailers and line businesses) fund relatively small
proportions of the total cost.
Attachment A
4.
Economic framework for levy design
4.1
Levy design should facilitate economic efficiency
4.1.1
Efficient funding arrangements for the Authority (and associated Levy
Regulations) should exhibit the following broad characteristics:

allocative efficiency - arrangements should provide incentives to
encourage the most useful mix, volume, and standard of services. This
generally means that where costs can be clearly attributed to causers
and/or beneficiaries, those parties should pay for the service in proportion
to their relative contribution to costs/benefits. In cases where it is not
possible to clearly identify specific causers/beneficiaries, the aim should be
to recover costs in the way that causes the least amount of distortion to
decisions and minimises so-called deadweight losses.

productive efficiency - arrangements should provide incentives to
minimise the cost of the services being provided. For example, where
costs vary with the level of output, the charge should generally reflect this
rather than being fixed, and there would ideally be opportunities for payers
to interact with the Authority on service provision decisions.

dynamic efficiency - arrangements should provide incentives to look for
new ways to provide services, to increase benefits or to lower costs over
time. For example it may be important in this context to provide
opportunities for users/beneficiaries and the Authority to alter the shape of
services that are provided over time.
4.1.2
To apply these characteristics it is important to understand the nature of the costs
to be recovered under the levy.
4.2
Nature of costs to be recovered
4.2.1
For the purpose of this paper the costs have been considered within the following
four broad categories, illustrated for the 2013/14 appropriation in Figure 2:

Industry Governance costs – these are costs incurred through making,
administering, and enforcing the rules governing the electricity market (the
Code);

Market Operation costs – these are costs incurred through a range of
external service providers supplying the systems and market operations
necessary to operate the market in accordance with the Code;
Attachment A

System Operation costs – these are costs incurred by the System
Operator supplying the systems and coordinating the power system in realtime to match supply and demand, in accordance with the Code; and

Electricity Efficiency costs – these are a portion of the costs of the
Electricity Efficiency and Conservation Authority (EECA) in relation to the
encouragement, promotion, and support for electricity efficiency.
Figure 2: Annual costs – estimated 2013-14
4.2.2
The Industry Governance category includes all costs associated with the
design, development, and implementation of changes to the Code (and other
associated arrangements) as well as monitoring the electricity market and
enforcing the Code.
4.2.3
The Market Operations costs relate to the services provided under a range of
contestable service provider contracts including the Pricing Manager, Clearing
Manager, Information System Manager, Reconciliation Manager, Registry
Manager, and FTR Manager. For the purpose of this paper, it excludes the costs
of the System Operator Service Provider Agreement (SOSPA).
4.2.4
The System Operator costs arising from the SOSPA have been considered
separately, partly because they are a significant proportion of the total costs to be
recovered under the Levy Regulations, and partly because it is important to
consider the nature of, and influences on, the various activities that are involved.
4.2.5
The Electricity Efficiency costs are determined by the Minister and are currently
allocated to wholesale purchasers. They are not considered as part of this review
because they are outside the Authority's control .
Attachment A
4.3
The principles applied in 2003 focussed on
economic efficiency
4.3.1
The current levy design was established in 2003 following the recommendations
of Charles River Associates (CRA) set out in a report3 submitted to the Ministry of
Economic Development (MED). CRA applied six key principles:

Economic efficiency - the levy structure should promote efficient market
behaviour (or at least not materially detract from it);

User/causer pays - where the causes of the costs of providing certain
services are identifiable, levies should be structured on a causer pays
basis;

Rationality - where levies are to recover costs that are allocated to
participants or participant classes, there should be a relatively strong logical
nexus between the participants on whom a levy is imposed and the costs
being recovered through that levy;

Simplicity - the levy structure should not create undue transaction costs for
the Commission, which implements and administers it, or for the
participants who must pay it, should consist of as many individual levies as
necessary to recover the costs in an efficient manner taking account of all
other criteria, and should be transparent to industry participants;

Equity - users in similar situations should pay similar amounts and
competitive neutrality should be preserved; and

Comprehensiveness/revenue sufficiency - the levies (together with other
sources of revenue, such as penalty payments) need to be sufficient to
recover the costs borne by the Commission.
4.3.2
These six principles were reconsidered by MED and deemed “fit for purpose” in
subsequent reviews of the Levy Regulations in 2005 (when changes were made
to the Electricity Commission functions) and in 2010 (when the Authority was
established).
4.3.3
Informal discussions with Ministry of Business, Innovation and Employment
(MBIE) officials suggest that these principles are considered to be broadly
consistent with the Treasury “Guidelines for setting Charges in the Public Sector”
(2002) and the Auditor General good practice guide “Charging Fees for Public
Sector Goods and Services” (2008).
3
Recovering the Costs of the Electricity Commission – a Report submitted to Ministry of Economic
Development; Charles River Associates; July 2003
Attachment A
4.4
Key factors influencing current allocation
4.4.1
The overall approach applied by CRA was to allocate all costs based on how
those costs broadly related to various participant classes and then use various
metrics to allocate costs to participants within each class.
4.4.2
The rationale was to strike a reasonable balance between simplicity, on the one
hand, and creating the incentive for participants to take an active role in
monitoring the performance of the Commission and its service providers, on the
other hand. This approach was considered likely to facilitate efficient
development of the arrangements over time (i.e. dynamic efficiency).
4.4.3
Key factors that influenced the overall design of the levy structure included:
4.4.4

allocating readily identifiable costs to participants that were deemed to have
a close nexus to the service being provided;

spreading costs not readily attributable to any particular class of market
participant equally across the major classes of market participants; and

allocating costs to market participants rather than directly to consumers.
Allocating costs to market participants (rather than directly to consumers) was
favoured because:

market participants were considered to have a logical nexus with respect to
the Commission’s activities;

market participants were considered to have the best relevant knowledge of
and influence over the costs being recovered; and

levies to market participants (rather than consumers) were considered to be
more transaction efficient.
4.4.5
CRA also noted that the distinction between the system operator “common
quality” costs (now in Parts 7 and 8 of the Code) and the system operator
“trading” costs (now predominantly in Part 13 of the Code) was relatively arbitrary
because in practice the system operator delivered the services simultaneously
using the same systems.
4.4.6
Overall CRA preferred variable charges over fixed charges. Although fixed
charges were considered to be theoretically “economically ideal” because they
were considered less likely to influence behaviour or distort use, in practice, CRA
suggested that fixed charges can create unintended consequences and
encourage “gaming”.
Attachment A
4.4.7
Further, CRA pointed out that if costs were spread widely any distortions would
be minimised and welfare losses4 from a levy comprising variable charges were
likely to be very small.
4.4.8
CRA concluded that few of the costs incurred in relation to regulation, oversight,
or operation of the market could be traced to a root cause that is consistently
associated with particular classes of participants, and that most of the costs were
“common”, and should therefore be recovered from a broad base of participants.
4.5
Framework applied to TPM needs to be considered
4.5.1
The Authority has recently been considering, and has developed, an economic
framework to apply to transmission pricing methodology (TPM). The framework
has been developed to ensure consistency with the statutory objective and
recognises that the TPM needs to facilitate efficient investment in, and efficient
operation of, the electricity industry.
4.5.2
The economic framework developed for the TPM attempts to deal with the
problem of allocating the costs of a predominantly natural monopoly service in a
manner that enhances efficiency (or at least does not unduly distort the efficient
use of the transmission system). This is a similar problem to designing a levy to
recover statutory monopoly services supplied through the Authority. Accordingly,
the Authority will wish to apply a set of principles to the development of levy
arrangements that is broadly consistent with those developed for the TPM.
4.5.3
The framework developed for considering the TPM applied economic efficiency
principles to establish a preferred hierarchy of pricing approaches comprising:
4.5.4
4
(a)
a first preference for market-based or market-like charges; then
(b)
a second preference for exacerbators pay; then
(c)
a third preference for beneficiaries pay; and then
(d)
alternative charging options, where the costs are socialised across the
users of transmission services.
The higher preferences in the hierarchy are applied unless it is inefficient to do
so. The Authority recognises that the application of the framework may lead to
transmission costs being recovered through a package of market-based,
exacerbators pay, beneficiaries pay, and alternative charging options.
Welfare losses are also known as deadweight losses or excess burdens, and relate to a loss of economic
efficiency that can occur when production and consumption of a good or service is not optimal because, either
people who would have more marginal benefit than marginal cost are not buying the product, or people who
have more marginal cost than marginal benefit are buying the product.
Attachment A
4.6
Proposed principles for Levy design
4.6.1
The proposed principles to apply to the levy design have been developed by
considering the principles developed by CRA in 2003 (and applied by MED in
2005 and 2010) and adapting them to incorporate the recent framework
developed by the Authority and applied to the TPM.
4.6.2
The overarching consideration is economic efficiency - the levy arrangements
should facilitate efficient market behaviour, taking into account the allocative,
productive, and dynamic efficiency effects discussed in section 4.1.
4.6.3
However, it is useful to identify some more detailed principles for levy design that
derive from the application of an economic efficiency criterion. The proposed
principles are described in Table 3.
Table 3: Proposed principles for levy design 5
Principle
Application of Principle
1. Exacerbators /
Where the causes of the cost of services are identifiable, levies
beneficiaries
should be applied to those parties that cause the costs and would
pay
have incentives to modify their behaviour to avoid the cost.
Where the beneficiaries of the costs are identifiable, levies should
be applied that reflect the value of the service to the beneficiaries.
2. Minimise
distortions
Where it is not efficient to levy exacerbators or beneficiaries, some
form of alternative levy allocation that minimises distortions of use
should be applied.
3. Simplicity
The levy structure should not create undue transactions costs for
the Authority or participants.
4. Consider
incentives
Where it is not efficient to levy exacerbators or beneficiaries,
consideration should be given to levying parties that have access to
information, have incentives, and have the capability to influence
the level of activity.
4.6.4
5
In some instances these principles can come into conflict and judgement is
sometimes required to resolve conflicts. In particular, the overall economic
efficiency effects, and the benefits of exacerbators pay and beneficiaries pay, can
be difficult to estimate. Further, the transactions costs associated with varying the
complexity of a levy structure can be difficult to determine.
These principles would also apply to the design of fees, if legislation were to permit the charging of fees at
some future point.
Attachment A
5.
Industry Governance Costs
5.1
Industry governance costs incurred for benefit of
consumers
5.1.1
The Authority’s costs incurred through making, administering, and enforcing the
Code cover a range of activities including:

Monitoring the performance of the electricity market;

Considering and designing improvement to the electricity market;

Implementing changes to the electricity market;

Considering and designing improvement to the arrangements for system
operation, quality of supply, and security of supply;

Implementing changes to the arrangements for system operation, quality of
supply, and security of supply; and

Monitoring and enforcing compliance with the Code.
5.1.2
These activities are all undertaken with an overall objective of promoting
competition in, reliable supply by, and the efficient operation of the electricity
industry for the long-term benefit of consumers.
5.2
Applying the principles
Exacerbators / beneficiaries pay
5.2.1
The exacerbators / beneficiaries pay principle suggests that, where the causers
of costs are identifiable, levies should be applied to those parties that cause the
cost (and would modify their behaviour to avoid the cost), or where the
beneficiaries of the costs are identifiable, levies should be applied that reflect the
value of the service to the beneficiary.
5.2.2
Industry governance costs are largely incurred with an objective of ensuring
compliance with the Code, and developing and improving the Code (and
associated arrangements) for the benefit of consumers. The level of costs is
predominantly influenced by the extent of development work on Code changes in
order to address issues with competition and the efficiency of the arrangements.
For example, the industry governance costs incurred by the Authority to date
have been heavily influenced by the requirements of section 42 of the Act for the
Authority to consider certain improvements aimed at enhancing competition and
efficiency, and improving reliability of supply.
5.2.3
To the extent that some parties cause the Authority to incur industry governance
costs, it is most likely to be participants who propose changes to the Code (and
Attachment A
associated arrangements) and participants who oppose changes to the Code.
The costs which could be attributed to the actions of identifiable parties are
expected to be small relative to the overall industry governance costs.
5.2.4
Causer pays charges applied to those participants proposing or opposing
changes to the Code would be counter-productive when considered against the
statutory objective because:

causer-pays charges would tend to deter participants from proposing or
making submissions on changes, and efficiency enhancing opportunities
could be lost; and

the benefit of efficiency enhancing changes will tend to accrue to a wide
range of participants, rather than to the party proposing changes, creating
free-riding problems.
5.2.5
The development of market arrangements to promote competition, reliable
supply, and efficient operation, can benefit a range of stakeholders. However
end-consumers, in the long-term, are intended to be the primary beneficiaries as
a result of enhanced competitive pressures lowering costs and prices, and
delivering reliable supply. Further, the aggregate private benefit is expected to
exceed the aggregate costs, otherwise the industry governance costs would not
be a worthwhile investment.
5.2.6
Application of the exacerbators / beneficiaries pay principle therefore suggests
that the industry governance costs could be charged directly to end-consumers.
A decision to levy end-consumers directly could be supported by a relatively
straightforward levy structure and could have the advantage of reducing the risk
of disputes amongst market participants over allocation of costs that would
otherwise be recovered from them.
Simplicity principle
5.2.7
On the other hand, a straightforward levy structure can just as easily be
developed and applied to market participants – effectively passing on the costs to
end-consumers via the participants. Arguments in favour of this approach are
supported by the simplicity principle because it provides an efficient means of
collecting the levy with low transactions costs.
5.2.8
The most transaction efficient means of allocating costs to end-consumers is via
a levy on purchasers in the wholesale electricity market (since almost all
electricity is traded through the wholesale electricity market), on distributors and
grid connected consumers, or on some combination of these parties.
Considering incentives
5.2.9
In general, market participants also have relevant information about the costs
being recovered, and have the incentives and capability to exert influence over
Attachment A
them, even when these costs are largely common. The Authority consults
annually on its proposed appropriations and indicative levy rates, and most
market participants provide submissions through this process, reinforcing the
arguments about information, incentives and capability.
5.2.10
Market participants also have opportunities to participate in advisory group
processes and to provide feedback in response to formal consultation proposals.
They are more likely to act as an effective restraint on industry governance costs
than final consumers because, for most consumers, electricity is a relatively small
part of costs, and they lack effective means of collective response.
Minimising distortions
5.2.11
To meet the distortion principle, industry governance costs should be allocated
across a broad base of market participants, because this is likely to cause the
least distortion to consumption and production decisions. A levy spread across all
MWh purchased in the wholesale market, or MWh conveyed through
transmission and distribution networks, for example, is unlikely to distort
consumption or production decisions because it will be very small relative to other
electricity purchasing costs, and electricity demand elasticity is low.
Summary
5.2.12
In summary, application of the principles suggests that:
(a)
the industry governance costs should be allocated by levying some
combination of purchasers, distributors, and grid-connected consumers;
and
(b)
the levy should be based on MWh purchased in the wholesale market and
MWh conveyed through transmission and distribution networks.
5.3
Current allocation of industry governance costs
5.3.1
The industry governance costs are currently allocated to various activity areas
(common quality, market operations, consumer registry, supply reliability etc) in
proportion to the estimated relative cost contributions to each area. The costs are
then applied as a levy on classes of participants in accordance with an allocation
determined for each activity area.
5.3.2
The allocation mechanism is based on MWh delivered through GIPs (to
generators), MWh purchased through GXPs (to purchasers), MWh conveyed
through transmission and distribution networks (to distributors and Transpower),
and ICPs supplied by retailers.
5.3.3
The current allocation of industry governance costs is illustrated in Figure 3.
Attachment A
Figure 3: Current allocation of industry governance costs
5.3.4
Figure 3 indicates that industry governance costs are currently allocated largely
to generators, purchasers, and line businesses, with a small allocation to
retailers.
5.4
Current allocation of industry governance costs
may be efficient
5.4.1
Application of the levy design principles suggests an allocation of the industry
governance costs to participants that have a strong connection with end-use
consumers, through a mechanism that spreads costs as widely as possible.
5.4.2
The current allocation of industry governance costs is not inconsistent with this
outcome. While some efficiency gains might be possible from amending the
allocation, they are likely to be modest, particularly when the cost of change is
taken into account. Accordingly, there does not appear to be a strong case for
change from the current approach to allocating industry governance costs.
Attachment A
6.
Market operations costs
6.1
Nature of the costs
6.1.1
The market operations costs relate to the services provided under a range of
contestable service provider contracts as illustrated in Figure 4.
Figure 4: Annual market operating cost – estimated 2013-14
6.1.2
The market operations costs are incurred through a range of external service
providers supplying the systems and market operations necessary to operate the
market in accordance with the Code. A brief description of each service is
included in Table 4
Table 4: Market operation service providers
Service
Supplied
Provider
by
Pricing
NZX
Manager
Description of Service
Calculates and publishes the spot prices at which electricity market
transactions are settled. Prices are derived using sophisticated
models which calculate nodal prices for each trading period based on
generator offer prices and quantities, demand, and system
conditions.
Part 13 of the Code.
Attachment A
Service
Supplied
Provider
by
Clearing
NZX
Manager
Description of Service
Ensures that market participants pay or are paid the correct amount
for the electricity they generated or consumed during the previous
month and monitors prudential security requirements. This involves
combining reconciled quantity information provided by the
Reconciliation Manager with half-hourly pricing information from the
Pricing Manager to determine the amounts owed to and by each
market participant.
Part 14 of the Code.
Information
NZX
Manager
Supplies the electricity market wholesale information and trading
system (WITS) used by electricity market participants to upload their
bids (purchasers) and offers (generators). WITS also delivers pricing,
scheduling, and other market data to participants.
Part 13 of the Code.
Reconciliation
NZX
Manager
Ensures that participants (generators and purchasers) are allocated
their correct share of electricity generation or consumption. The
Reconciliation Manager receives and processes large quantities of
metering data on a monthly basis, reconciles it against a register of
contracts, and passes the data to participants.
Part 15 of the Code.
Registry
Jade
Supplies a national database that contains information on every point
Manager
Direct
of connection on a network from which electricity is supplied to a
consumer site (referred to as installation control points or ICPs) and
records switches between retailers.
Part 11 of the Code.
FTR Manager
EMS
Creates inter-island financial transmission rights (FTRs), allocates
FTRs to industry participants via regular auctions, and undertakes
other activities associated with operating, promoting and developing
the FTR market over time.
Prior to and during each auction the FTR Manager checks with the
Clearing Manager that the amount of security each party holds is
sufficient to validate their bids. The FTR manager also calculates the
proportion of the loss and constraint excess that can be allocated to
settling inter-island FTRs and informs the Clearing Manager, who
uses that money and the auction proceeds to settle payments to FTR
holders each month.
Part 14 of the Code
Attachment A
6.2
Applying the principles to market operations
6.2.1
Table 5 explores the primary cost drivers, exacerbators, and beneficiaries for
each market operation service provider.
Table 5: Market service provider functions
6.2.2
Service
Provider
Primary Cost Drivers
Primary
Exacerbators
Primary
Beneficiaries
Pricing Manager
Complexity of pricing
arrangements
Characteristics of power
system
Number of GXPs and GIPs
Parties
submitting late
or inaccurate
data
Generators
Purchasers
Consumers
Reconciliation
Manager
Number of GXPs and GIPs
Complexity of market
arrangements
Access to metering information
Parties
submitting late
or inaccurate
data
Generators
Purchasers
Clearing
Manager
Number of generators and
purchasers
Complexity of market
arrangements
Prudential arrangements
Parties with
lower credit
quality or
complex
arrangements
Generators
Purchasers
Information
System
Manager
Number of generators and
purchasers
Complexity of market
arrangements
Registry
Manager
Complexity of switching
arrangements
Number of points of
connection (ICPs)
Volume of switches
Switching
consumers and
retailers
submitting late
or inaccurate
data
Retailers
Consumers
Distributors
FTR Manager
Number of FTR traders
Frequency of auctions
The volume of trades
FTR traders
FTR traders
Consumers
Generators
Purchasers
Consumers
Examination of Table 5 suggests that the four wholesale electricity market service
provider functions (pricing, reconciliation, clearing and information) can be
considered as a group, while the registry and FTR trading functions should be
considered separately.
Attachment A
6.3
Wholesale market operations costs
Exacerbators / beneficiaries pay principle
6.3.1
Table 5 highlights that for the four wholesale electricity market service provider
functions (pricing, reconciliation, clearing, and information):

the primary cost drivers mainly relate to the number of GXPs and GIPs, the
number of generators and purchasers, and the complexity of the market
arrangements;

the factors that exacerbate the costs primarily relate to dealing with
“problems” including reconciling late or inaccurate data, and dealing with
credit quality issues;

the primary beneficiaries are generators, purchasers, and consumers.
6.3.2
This analysis suggests that wholesale market operations costs are unlikely to
vary greatly with the volumes traded through the market, and are more likely to
vary with the number of GXPs and GIPs, the complexity of the market
arrangements, and the number of participants.
6.3.3
It also suggests that some form of user pays charges could be efficient for
dealing with late or inaccurate data, and prudential problems. On the other hand,
user charges in this area could also create barriers to entry and have the effect of
lowering competition. Any user-pays charges would need to be carefully
implemented.
6.3.4
The direct benefits of the wholesale market operations accrue mainly to
generators and purchasers, but there are wider benefits to consumers in general
from competition and the information revealed through the process - pricing
information in particular. This suggests that wholesale market operations costs
should be levied predominantly on generators and purchasers.
Minimising distortions
6.3.5
The minimise distortions principle suggests that market operations costs should
be recovered in a manner that causes the least distortion to consumption and
production decisions. There may be a case for fixed membership fees to reflect
costs associated with numbers of participants, but such fees can create undue
barriers to entry and artificial incentives for several parties to trade through one
vehicle.
6.3.6
A levy based on MWh generated and MWh purchased (in the wholesale market)
is unlikely to distort consumption or production decisions because it will be very
small relative to other electricity purchasing costs, and electricity demand
elasticity is low.
Attachment A
Simplicity principle
6.3.7
A levy based on MWh generated and MWh purchased has the advantage of
being relatively simple to implement and is unlikely to create undue transaction
costs for the Authority or participants.
Considering incentives
6.3.8
Wholesale market participants have relevant information about the wholesale
market costs being recovered, and have the incentives and capability to exert
influence over them. In particular, wholesale market participants can be expected
to provide feedback during the annual appropriations consultation process.
6.3.9
Wholesale market participants also have opportunities to participate in advisory
group processes and to provide feedback in response to formal consultation
proposals. They are likely to act as an effective restraint on wholesale market
operations costs.
Summary
6.3.10
In summary, application of the principles suggests that:
(a)
the wholesale market operations costs should be largely allocated to
generators and purchasers in the wholesale electricity market;
(b)
the levy should be based on MWh generated and purchased in the
wholesale market; and
(c)
fees to cover late or inaccurate data, and prudential problems, are likely to
be efficient, but are not practicable within the existing legislative framework.
Current allocation
6.3.11
The wholesale market operations costs are currently allocated 50% to generators
and 50% to purchasers and the mechanism for charging these costs is MWh
generated and purchased in the wholesale market.
6.3.12
The current allocation is therefore consistent with an efficient allocation, given the
limitations of the Levy Regulations.
6.4
Registry costs
Exacerbators / beneficiaries pay principle
6.4.1
Table 5 highlights that for the registry service provider function:

the primary cost drivers relate to the number of points of connection (ICPs),
the complexity of the switching arrangements, and the volume of switches;
Attachment A
6.4.2

the factors that exacerbate the costs primarily relate to the number of
switches and late or inaccurate data from retailers; and

the primary beneficiaries are retailers and consumers, although distributors
also derive some benefit from the registry data because they use it for
billing retailers that supply consumers within their networks.
This suggests that registry costs could be efficiently recovered by a levy to
retailers and distributors based on ICPs, supplemented by a switching fee
charged to retailers6. Any switching fee would need to be set at a level related to
the incremental cost of switches and this is likely to be relatively low. However,
switching fees applied to retailers are not practicable within the existing legislative
framework.
Simplicity principle
6.4.3
A levy based on ICPs has the advantage of being relatively simple to implement
and is unlikely to create undue transaction costs for the Authority or participants.
Considering incentives
6.4.4
Retailers and distributors have relevant information about the registry costs being
recovered, and have the incentives and capability to exert influence over them. In
particular, they can be expected to provide feedback during the annual
appropriations consultation process.
6.4.5
Retailers and distributors also have opportunities to participate in advisory group
processes and to provide feedback in response to formal consultation proposals.
They are likely to act as an effective restraint on registry costs.
Summary
6.4.6
In summary, application of the principles suggests that:
(a)
the registry costs should be primarily allocated to retailers and distributors;
(b)
the levy should be based on a charge per ICP; and
(c)
a switching fee is likely to be efficient, but is not practicable within the
existing legislative framework.
Current allocation
6.4.7
6
The registry costs are currently allocated 50% to retailers and 50% to distributors
and the mechanism for charging these costs is ICPs.
This approach could be implemented as a switching fee shared by the winning and losing retailers, with
residual costs recovered via a broader mechanism.
Attachment A
6.4.8
The current allocation is therefore broadly consistent with an efficient allocation,
given the limitations of the Levy Regulations.
6.5
FTR trading costs
Exacerbators / beneficiaries pay principle
6.5.1
Table 5 highlights that once the FTR trading function is fully established:

the primary cost drivers will likely relate to the number of participants
choosing to trade (FTR traders), the frequency of auctions, and the volume
of trading;

the factors that will exacerbate the costs are likely to primarily relate to the
actions of FTR traders; and

the primary beneficiaries are FTR traders and consumers.
6.5.2
The direct benefits of FTR trading will accrue mainly to those parties who choose
to trade, but there are likely to be wider benefits to consumers in general from
enhanced competition in the retail market7.
6.5.3
This suggests that on-going FTR trading costs are likely to be most efficiently
recovered by a membership charge (to secure access to auctions) and/or a per
transaction charge reflecting the marginal cost of trading.
6.5.4
However, FTR trading will be an entirely new development for the wholesale
market, and it may take some time for participants to understand its benefits. In
the meantime, user-pays charges may inhibit participation in FTR auctions.
Simplicity principle
6.5.5
User-pays charges based on membership and/or FTR transactions appears to be
feasible in principle, but it would require a new class of participant to be
established (FTR traders,) and may be complex to implement within the Levy
Regulations, and periodic adjustment of charges to avoid over/under recovery
would be necessary.
6.5.6
User-pays charges would be more suited to implementation within a fees
framework if the Act is amended to allow fees.
Current situation
6.5.7
7
The FTR trading function is currently in an implementation phase, with Energy
Market Services (a division of Transpower) appointed as FTR Manager in April
Until the establishment phase is completed (which is likely to extend into the initial trading period as teething
issues are addressed), some costs will be associated with development issues, which are also being incurred
for the long-term benefit of consumers as a whole.
Attachment A
2012 and the first auction scheduled for May 2013. There are uncertainties about
the number of participants that are likely to trade, the frequency of auctions that
will be necessary, and the volume of trading.
6.5.8
In the recent consultation on appropriations for the 2013/14 year, the expected
costs for FTR trading were included as part of the “Market Operations” category
and allocated within the indicative levy arrangements as 50% to generators and
50% to purchasers, based on MWh traded through the wholesale electricity
market. This mechanism will apply unless the Authority decides to include the
FTR costs in a different expenditure category in the existing Levy Regulations or
to amend the Levy Regulations to provide for an alternative allocation.
6.5.9
For the reasons set out in paragraphs 6.5.1 to 6.5.3, the allocation to Market
Operations is not consistent with an efficient allocation of the on-going costs.
6.5.10
Furthermore, the FTR market will trade two types of FTR - option FTRs and
obligation FTRs. The latter can be synthesised by buying and selling offsetting
futures contracts on the ASX8, incurring a transaction fee of $280 (for 1 MW over
a quarter9 - equivalent to $0.13/MWh).
6.5.11
The absence of any volume-related charge for trading FTRs may divert locational
risk trading away from the (fee-based) ASX futures market. This could detract
from the Authority’s goal of deepening the futures market. However, these
concerns are tempered by the following observations:
6.5.12
(a)
examination of confidential trading data suggests that hedging the
underlying energy price risk is the main driver in the ASX futures market,
rather than addressing locational price risks;
(b)
while obligation FTRs can be synthesised in the futures market, this is not
the case for option FTRs – and these are expected to be the product of
greatest interest to participants in the FTR market; and
(c)
despite their similarities, obligation FTRs and the synthetic futures contract
equivalents are not direct substitutes. In particular, payments under
obligation FTRs are subject to scaling in extreme situations (such as
extended grid outages which reduce transmission rentals). By contrast the
futures contract synthetic equivalent would provide firm cover.
Another factor to consider is the current developmental nature of the initial FTR
market. The associated uncertainties about the number of participants, and the
volume of trading make it difficult to determine efficient participant user-pays
charges at this stage. If participant user charges are set in a manner that does
8
For example, by buying an OTA futures contract and selling the equivalent BEN futures contract, a party will
have a close equivalent to the obligation FTR (i.e. OTA – BEN).
9
The fee is $140 for each 1 MW quarterly buy and sell contract.
Attachment A
not reflect marginal cost, there is a risk they could create undue barriers to entry
and reduced competition in the short-term. Further, there are limitations within the
Levy Regulations framework that make it less suited to the application of userpays charges. In particular, it would be necessary to create a new participant
class (FTR traders), determine the charge basis and reflect this in regulations.
Setting volume related charges will require a forecast of annual activity, which is
uncertain at present. This means there will be a need for a subsequent levy
wash-up, further increasing uncertainty for participants.
6.5.13
Taken as a whole, these factors indicate that a user-charge basis should be the
objective, but that it should not be adopted immediately. Instead, the initial FTR
operating costs should be recovered according to the allocation mechanism
assumed for the indicative 2013/14 appropriation (i.e. to generators and
purchasers in the wholesale electricity market).
6.5.14
This arrangement should be reconsidered following a relatively short period of
operation of the FTR market, with a view to determining the likely number of
participants, the frequency of auctions, the likely volume of trading, and other
possible cost drivers. Following this reconsideration it should be possible to
determine whether to amend the Levy Regulations to introduce an “FTR Traders”
participant class, or whether it is possible to introduce FTR fees as a result of
changes to the Act.
Attachment A
7.
System operations costs
7.1
Nature of the costs
7.1.1
The system operator is the market operation service provider responsible for coordinating supply of and demand for electricity in real-time, in a manner that
avoids fluctuations in frequency or disruption of supply. The system operator
processes and functions are predominantly set out in Parts 7, 8, 9, and 13 of the
Code.
7.1.2
System operation requires maintaining a continuous balance between electricity
supply from power stations and demand from consumers. The system operator
achieves this by determining the optimal combination of power stations and
reserve providers for each half-hour trading period, instructing power stations
when and how much electricity to generate, and managing any contingent events
that cause the supply-demand balance to be disrupted. Sophisticated modelling
and communications technologies are involved.
7.1.3
In addition to the real-time dispatch and security management role, the system
operator carries out investigations and planning to ensure that supply can meet
demand and system security can be maintained during future trading periods.
Examples of this are co-ordinating generator and transmission outages,
facilitating commissioning of new generating plant, and procuring ancillary
services to support power system operation.
7.2
System operation functions
7.2.1
For the purpose of understanding the various functions and the cost drivers
behind them, the system operation functions are usefully considered within the
process framework defined by the TSO Comparison Group10. This framework is
illustrated in Figure 5
Figure 5: Overview of system operator functions
10
See the paper entitled “Benchmarking system operation processes for 22 international transmission system
operators” by Bart Franken* (KEMA), Laith Ahmed Albassam (Saudi Electricity Company), CM Mak (CLP
Hong Kong), Albert Dicaprio (PJM), and Oliver Scheufeld (KEMA); 2008.
Attachment A
7.2.2
7.2.3
The framework identifies five distinct functions which can be summarised as
follows:
(a)
Operations planning – preparing plans for meeting security and quality
standards, procuring ancillary services, developing emergency
management plans, and plans for coordinating outages;
(b)
Scheduling –forecasting demand, planning day-ahead operations, and
notifying participants of expectations;
(c)
Real-time operations – dispatching power stations and ancillary services,
monitoring and supervising operations, and coordinating the various
participants;
(d)
After the fact –monitoring and reporting market outcomes, and
investigating events; and
(e)
Support – providing systems infrastructure, providing modelling and
analytical support, monitoring compliance, and supporting participants and
the Authority with analysis of various issues.
The breakdown of costs associated with each of these activities has been
estimated11 and is illustrated in Figure 6, in order to identify the materiality of the
costs in each area.
Figure 6: Breakdown of annual system operations costs
11
This breakdown has been estimated by evaluating full-time equivalent staffing in each area and apportioning
infrastructure cost – it should be considered as indicative, but serves the purpose of confirming that the costs
are of material significance in each area.
Attachment A
7.2.4
In order to explore the primary cost drivers, the exacerbators of cost, the
beneficiaries, and the activities in each area, have been identified and analysed
in Appendix D. A summary of this analysis is included in Table 6.
Table 6: Summary analysis of system operations activities
Support
Activity
Primary Cost Drivers
Primary
Exacerbators
Primary
Beneficiaries
Operations
Planning
Characteristics of power system
Non-
Generators
Complexity of market
arrangements
compliant
asset owners
Consumers
Characteristics of power system
Unreliable
Generators
Complexity of market
arrangements
generators
Purchasers
and
transmission
Distributors
Characteristics of power system
Unreliable
Generators
Complexity of market
arrangements
generators
Purchasers
and
transmission
Distributors
Characteristics of power system
Unreliable
Generators
Complexity of market
arrangements
generators
Purchasers
and
transmission
Distributors
Characteristics of power system
Authority and
Generators
Complexity of market
arrangements
participants
Purchasers
seeking
support
Distributors
Complexity of security policies
Scheduling
Real-time
operations
Complexity of security policies
Grid consumers
Consumers
Number of participants
After the fact
Support
Complexity of security policies
Grid consumers
Consumers
Number of participants
7.2.5
Table 6 highlights that for the system operations activities:

the primary cost drivers relate to the characteristics of the power system,
the complexity of quality and security policies, and the complexity of the
market arrangements;

the factors that exacerbate the costs primarily relate to dealing with
“problems” including non-compliant asset owners and unreliable generators
and transmission, and providing support to the Authority and participants;
and
Attachment A

7.3
the primary beneficiaries include generators, purchasers, distributors and
consumers.
Applying the principles
Exacerbators / beneficiaries pay principle
7.3.1
System operations costs are largely incurred with an objective of ensuring that
electricity supply meets demand on a continuous basis for the benefit of most
participants in the electricity market. The overall costs are mostly influenced by
the characteristics of the power system, the mix of assets and ancillary services,
and the complexity of the market arrangements and security policies – and these
do not vary significantly with the volume supplied through the transmission grid.
7.3.2
To the extent that some parties cause system operations costs it is most likely to
be related to non-compliant or unreliable assets, or participants and the Authority
requiring support analysis. These costs may be significant in some cases,
particularly (for example) where a participant requires extensive systems
integration studies associated with potential new power station or transmission
assets.
7.3.3
This suggests that the bulk of system operations costs should be allocated widely
to generators, purchasers, and distributors, and recovered in a manner that
causes the least distortion to consumption and production decisions. However,
there may be a case for applying charges to reflect costs imposed by noncompliant or unreliable assets, and where participants require extensive systems
analysis12.
7.3.4
A levy based on MWh generated, MWh purchased, and MWh conveyed through
the distribution system, is unlikely to materially distort consumption or production
decisions because it will be very small relative to other electricity purchasing
costs, and electricity demand elasticity is low.
Simplicity principle
7.3.5
A levy based on MWh generated, MWh purchased, and MWh conveyed through
the distribution system will have the advantage of being relatively simple and is
unlikely to create undue transaction costs for the Authority or participants.
Considering incentives
7.3.6
12
Generators, purchasers, and distributors have relevant information about the
system operations costs being recovered, and have the incentives and capability
It is noted that analysis undertaken by the System Operator for the Authority is already subject to a form of
fees via the Technical Advisory Services Contract (TASC) .
Attachment A
to exert influence over them. In particular, they can be expected to provide
feedback during the annual appropriations consultation process.
7.3.7
Generators, purchasers, and distributors also have opportunities to participate in
advisory group processes and to provide feedback in response to formal
consultation proposals. They are likely to act as an effective restraint on system
operations costs.
7.4
Current allocation of system operations costs
7.4.1
The system operations costs are currently allocated through two steps as follows:
(a)
they are apportioned 50% to “common quality” and 50% to “market
operations”; and
(b)
“common quality” costs are then allocated 33% to generators, 33% to
purchasers and 33% to line businesses, while “market operations” costs
are allocated 50% to generators and 50% to purchasers.
7.4.2
The allocation mechanism is based on MWh delivered through GIPs (to
generators), MWh purchased through GXPs (to purchasers), MWh conveyed
through transmission and distribution networks (to distributors and Transpower).
7.4.3
The current allocation is illustrated in Figure 7 which highlights that the bulk of
charges are allocated to generators (42%) and purchasers (42%), with the
balance (16%) allocated to lines businesses.
Figure 7: Current allocation of system operations costs
Attachment A
7.5
Conclusion
7.5.1
Application of the levy design principles suggests an allocation of the system
operations costs to generators, purchasers, and line businesses, through a
mechanism that spreads costs as widely as possible without distorting production
and consumption decisions.
7.5.2
There may be a case for user-pays charges to reflect costs imposed by noncompliant or unreliable assets, and where participants require extensive systems
analysis, but this may be complex to implement within the Levy Regulations.
7.5.3
The current allocation of system operations costs is reasonably consistent with
an efficient allocation, given the limitations of the Levy Regulations. Any
efficiency gains that could be possible from amending the allocation are likely to
be small. Accordingly, there does not appear to be a strong case to change from
the current approach to allocating system operations costs.
Attachment A
Appendix A : Statutory framework
Overview
A.1
The Act sets out the functions of the Authority. These fall into two broad
categories:

Industry governance – the Authority makes, administers, and enforces the
rules governing the New Zealand electricity market (called the Electricity
Industry Participation Code 2010 or “Code”)

Market operation – the Authority is responsible for running the central
systems and processes to operate the New Zealand electricity system and
market in accordance with the Code. In practice, the Authority contracts
most of these functions to a range of external service providers.
A.2
Section 128 of the Act provides for the Crown (via appropriations in Parliament)
to be the sole funder of all the Authority’s statutory functions. The Act requires
the Crown to fully recover its actual costs via a levy on industry participants. As
provided under the Act, the levy also funds certain other electricity sector costs
including in particular the electricity efficiency programmes delivered by the
Energy Efficiency and Conservation Authority (EECA), and facilitating customer
switching through the Powerswitch website overseen by the Ministry of
Consumer Affairs (MCA).
A.3
The funding flows are shown in Figure 8. The key aspects of the current
Authority funding arrangements, and the regulatory context by which they can be
amended, are discussed in more detail in the following subsections.
Figure 8: Overview of existing funding arrangements
appropriation
consultation
Electricity
Authority
appropriation
funds
Crown
levy
payments
levy
payers
Attachment A
Levies under s128 of the Electricity Industry Act
A.4
Section 128 of the Act sets out the legislative framework for the existing levy
arrangements, including the making of levy regulations pursuant to the Act.
A.5
The levy is collected under the Electricity Industry (Levy of Industry Participants)
Regulations 2010 (the Levy Regulations).
A.6
Every industry participant (or prescribed class of industry participant) must pay to
the Authority on behalf of the Crown the levy prescribed by regulations. The levy
must be prescribed on the basis that all of the Authority’s costs should be met in
full out of the levy. The levy also funds certain other electricity sector costs
including some of the costs of EECA and MCA.
A.7
The empowering provisions in the Act allow the regulations to (among other
things):
(a)
specify the amount of the levy or method of calculating or ascertaining the
amount of the levy;
(b)
include or provide for including in the levy any shortfall in recovering the
actual costs; and
(c)
provide for different levies for different classes of industry participants.
A.8
The Authority sets the levy rate each year based on its expected costs, and then
invoices the relevant participants in monthly instalments across the year. An
annual reconciliation process adjusts for any under or over-recovery.
A.9
The Levy Regulations set out the formulae for allocating annual costs to levy
payers and the process by which levy payers are invoiced for the amounts they
are each liable to pay. The key steps can be summarised as follows:
(a)
determine the cost of each activity by allocating the estimated costs to the
activities listed in Table 1 of the Levy Regulations (common quality
operations, market operations, registry and consumer operations, supply
reliability operations, transmission operations, electricity efficiency
operations, and customer switching fund);
(b)
determine the costs payable by each participant class for each activity by
allocating the costs of each activity to the classes of industry participants
according to the proportions set out in Table 1 of the Levy Regulations (for
example, one third each to generators, purchasers, and distributors for
common quality operations, one half each to generators and purchasers for
market operations); and
(c)
determine the annual levy rate per unit of electricity
generated/purchased/conveyed, or per consumer connection, as the case
may be, by dividing the costs payable by each class of participant per
activity by the relevant number calculated in accordance with Table 2 of the
Levy Regulations. Where a cost is allocated to generators, the per unit cost
Attachment A
is based on the estimated total quantity of electricity to be generated by
generators during the financial year. Where a cost is allocated to
purchasers/distributors, the per unit cost is usually based on the estimated
total quantity of electricity to be purchased/conveyed during the financial
year, but in some cases is based on the estimated average total number of
consumer connections (installation control points or ICPs) during the
financial year.
A.10
The outcome from applying these steps is the annual levy rates for the financial
year. The Authority is required to publish a notice in the Gazette setting out the
annual rates as soon as practicable after they have been calculated. The
Authority generally makes the calculation once the appropriation has been
received (end of May) and gazettes the rates in June for the financial year
beginning 1 July.
A.11
As part of its annual appropriations consultation in October, the Authority also
calculates and publishes indicative levy rates for the coming year based on
estimated expenditure.
A.12
Levy rates may, at the Authority’s discretion, be adjusted (and gazetted) during
the financial year in certain circumstances including if:

the estimated costs change significantly;

the costs of an activity change significantly;

the amount of levy money estimated to be collected is too much or too little
because the quantity of electricity generated/purchased/conveyed is
significantly different to what was estimated, or the number of consumer
connections has significantly changed; or

the Authority’s costs are reallocated between activities.
Attachment A
Appendix B : Current cost structure and allocation
Cost structure
B.1
The existing Levy Regulations define a number of expenditure categories or
“activities”, generally with reference to carrying out functions in relation to various
parts of the Code. These categories, as defined in the Levy Regulations, are set
out in Table 7. They are used as the basis for the existing cost allocation under
the Levy Regulation, discussed in section 3.2 of this paper.
Table 7: Expenditure categories under the Levy Regulations
Category
Description of activities
Common quality
operations
means the activities of the Authority that relate to the following
parts of the Code:
(a) the common quality operations referred to in Part 7, system
operator:
(b) Part 8, common quality
Market
operations
means the activities of the Authority that relate to the following
parts of the Code:
(a) Part 5, regime for dealing with undesirable trading situations:
(b) Part 10, metering arrangements:
(c) Part 13, trading arrangements:
(d) Part 14, clearing and settlement:
(e) Part 15, reconciliation
Registry and
consumer
operations
means the activities of the Authority that relate to Part 11, registry
information management, of the Code and other consumer-related
activities
Supply reliability
operations
means—
(a) the activities of the Authority that relate to Part 9, security of
supply, of the Code:
(b) the security of supply operations referred to in Part 7, system
operator, of the Code:
(c) the activities of the Security and Reliability Council appointed
under section 20 of the Act:
(d) the activities of the Authority that are associated with the
Whirinaki agreement and any activities of the Crown that are
associated with the Whirinaki generating plant after the Whirinaki
agreement is terminated:
(e) the functions of the Authority under section 136 of the Act
Attachment A
Category
Description of activities
Transmission
operations
(a) means the activities of the Authority that relate to Part 12,
transport, of the Code; and
(b) includes the costs incurred by the Crown in relation to
developing and publishing regional electricity supply and demand
forecasts and scenarios, and related information and analysis, for
the purpose of assisting investment planning by industry
participants
Electricity
Efficiency
means the functions, powers, and duties of the Energy Efficiency
and Conservation Authority under the Energy Efficiency and
Conservation Act 2000 that—
(a) relate to the encouragement, promotion, and support of
electricity efficiency; and
(b) give rise to the costs that are within the portion of total costs
that is determined by the Minister to be the portion to be met by
levies under section 128(3)(c) of the Act
Customer
switching fund
fund means the fund set up to meet the costs referred to in section
128(3)(d) of the Act, subject to the limits in that provision
Other activities
(a) means the functions, powers, and duties of the Authority under
the Act or the Code, other than the activities to which costs are
separately allocated13 as listed in column 1 of table 1 in regulation
7(2):
(b) includes—
(i) the monitoring and enforcement of the Code by the Authority, the
Rulings Panel, and any investigator appointed under the Electricity
Industry (Enforcement) Regulations 2010:
(ii) the costs of processing applications for exemptions from Part 3
of the Act (which relates to separation of distribution from certain
generation and retailing):
(c) includes the costs of collecting the levy
B.2
13
In some areas one entity (for example, the Authority or the system operator)
undertakes functions that span more than one expenditure category. The Levy
Regulations allow for the Authority to exercise judgment in determining the split of
actual costs across the relevant expenditure categories.
That is, not already included in the categories described in all the other rows of this table.
Attachment A
Current allocation under the Levy Regulations
B.3
The Levy Regulations describe the methodology for calculating each Participant’s
share of the total costs. The expenditure categories described in the previous
section are a key building block in this methodology.
B.4
Table 1 of the Levy Regulations sets out the allocation of each expenditure
category to participant class. It is reproduced here as Table 8.
Table 8: Allocation of costs of each activity
Activity
Classes of industry participants to whom costs of
activity are allocated
Generators
Purchasers
Common quality
operations
One-third
One-third to
purchasers
Market operations
One-half
One-half to
purchasers
Registry and
consumer operations
-
One-half to retailers
Supply reliability
operations
-
All to purchasers
Transmission
operations
-
Customer switching
fund
-
Other activities
One-third
Establishment costs
relating to transition of
functions to
Commerce
Commission
-
Establishment costs
relating to Energy
Efficiency and
Conservation Authority
-
All other establishment
costs
One-third
All to retailers
One-third to
purchasers
-
All to purchasers
One-third to
purchasers
Distributors
One-third
One-half to
distributors other
than Transpower
All to Transpower
One-third
All to Transpower
-
One-third
Attachment A
B.5
The levy rates that result from this methodology change from year to year. A
copy of the levy rate table for 2013/14 is reproduced in Table 9.
Table 9: Levy Rates from recent 2013/14 Appropriations Consultation
Participant
Class
Common
Quality
Market
Registry
Supply
Security
Transmission
Electricity
Efficiency
Customer
Switching
Other
Activities
$ per unit (MWh / ICP's)
Generators
0.1699
0.4391
Purchasers
0.1705
0.4408
Retailers
Distributors
(incl
Transpower)
Distributors
(excl
Transpower)
Transpower
0.0480
0.0086
0.3101
0.8962
0.0482
1.5602
0.0949
0.0268
0.8965
0.0167
Attachment A
Appendix C : Levy provisions under the Act
Section 128 Levies
(1) Every industry participant (or prescribed class of industry participant) must pay to the Authority on behalf
of the Crown a levy prescribed by regulations.
(2) The Governor-General may, by Order in Council made on the recommendation of the Minister, make
regulations providing for the levy.
(3) The levy must be prescribed on the basis that the following costs should be met fully out of the levy:
(a) the costs of the Authority in performing its functions and exercising its powers and duties under this Act
and any other enactment; and
(b) the costs that are associated with the Whirinaki agreement referred to in section 127, and any costs
incurred by the Crown that are associated with the Whirinaki generating plant after the Whirinaki
agreement is terminated; and
(c) a portion of the costs of the Energy Efficiency and Conservation Authority in performing its functions
and exercising its powers and duties under the Energy Efficiency and Conservation Act 2000 in relation
to the encouragement, promotion, and support of electricity efficiency, where the size of the portion to
be met by levies under this Act is determined by the Minister; and
(d) the costs incurred by the Crown before 1 May 2014 in promoting to customers the benefits of
comparing and switching retailers, subject to both of the following limits:
(i) a limit of $5 million per financial year; and
(ii) an overall limit of $15 million for the period commencing on 1 November 2010 and ending with 30
April 2014; and
(e) the costs of the Rulings Panel; and
(f) the costs of establishing and operating any regulated dispute resolution scheme in respect of the
electricity industry under Schedule 4; and
(g) the costs incurred by the Crown in relation to developing and publishing regional electricity supply and
demand forecasts and scenarios, and related information and analysis, for the purpose of assisting
investment planning by industry participants; and
(h) for the first financial year to which the levy applies, the costs incurred by the Crown on or after 1
January 2010 relating to establishing the Authority, disestablishing the Electricity Commission,
transferring functions to other agencies, and preparing the initial Code; and
(i) the costs of collecting the levy money.
(4) The levy may be prescribed on the basis that any actual cost that could have been, but has not been,
recovered as a levy shortfall for a year may be recovered (along with any financing charge) over any period
of up to 5 years.
(5) The regulations may—
(a) specify the amount of the levy or method of calculating or ascertaining the amount of the levy:
(b) include or provide for including in the levy any shortfall in recovering the actual costs:
(c) refund or provide for refunds of any over-recovery of those actual costs:
(d) provide for different levies for different classes of industry participants:
(e) specify the financial year or part financial year to which a levy applies, and apply that levy to that
financial year or part financial year and each subsequent financial year until the levy is revoked or
replaced:
(f) provide for the payment and collection of levies:
(g) require payment of a levy for a financial year or part financial year, irrespective of the fact that the
regulations may be made after that financial year has commenced:
(h) exempt or provide for exemptions from, or provide for waivers of, the whole or any part of the levy for
any case or class of cases.
(6) The levy for a financial year that starts after the Authority begins to carry out any additional function under
this Act or any other Act may cover the costs of performing that additional function, irrespective of the fact
that the regulations may be made and come into effect after the start of the financial year.
Attachment A
(7) The amount of any unpaid levy is recoverable in any court of competent jurisdiction as a debt due to the
Authority on behalf of the Crown.
(8) The Authority must pay into a Crown Bank Account, and separately account for, each levy payment.
Section 129 Consultation about request for appropriation
(1) The Authority and the Energy Efficiency and Conservation Authority must, before submitting a request to
the Minister seeking an appropriation of public money for the following year, or any change to an
appropriation for the current year, that relates to costs that are intended to be recovered by way of levies
under section 128, consult about that request with—
(a) those industry participants who are liable to pay a levy under that section; and
(b) any other representatives of persons whom the Authority believes to be significantly affected by a levy.
(2) Each Authority must, at the time when the request is submitted, report to the Minister on the outcome of
that consultation.
(3) The Ministry must consult in a like manner in respect of a levy to recover costs referred to in section
128(3)(g).
(4) This section applies to requests in respect of the financial year beginning 1 July 2011 and later financial
years.
Attachment A
Appendix D : System Operator activities
Table 10: Operations Planning Functions
Operations Planning
Primary Cost Drivers
Primary
Exacerbators
Primary
Beneficiaries
Planning to meet
Security Policy and
PPOs
Complexity of Security Policy and
PPOs
Characteristics of power system
Non-compliant
asset owners
Generators
Consumers
Emergency planning
Characteristics of power system
Number of participants (generators,
grid consumers and distributors)
Procuring Ancillary
Services
Complexity of arrangements (marketbased or simple procurement)
Assessing network and
generation capability
Characteristics of power system
Generators
Consumers
Outage management
planning
Number of generators
Transmission system characteristics
Generators
Purchasers
Grid Owner
Security of supply
forecasting
Characteristics of power system and
mix of generation types
Generators
Consumers
Generators
Consumers
Non-compliant
asset owners
Generators
Consumers
Table 11: Scheduling functions
Scheduling
Primary Cost Drivers
Primary
Exacerbators
Primary
Beneficiaries
Short-Term demand
forecasting
Number of grid supply points
Assessing network and
generation capability
Characteristics of power system, mix
of generation types and ancillary
services
Unreliable
generators and
transmission
Generators
Grid Owner
Distributors
Day-ahead security
planning
Characteristics of power system, mix
of generation types and ancillary
services
Unreliable
generators and
transmission
Generators
Consumers
Preparing schedules
Complexity of wholesale market
arrangements
Number of participants
Generators
Purchasers
Grid
consumers
Generators
Purchasers
Grid
consumers
Notifying market
participants
Number of participants
Characteristics of participant systems
Generators
Purchasers
Distributors
Generators
Purchasers
Distributors
Asset commissioning
New transmission, distribution and
generation
Grid Owner
Distributors
Generators
Grid Owner
Distributors
Generators
Consumers
Attachment A
Table 12: real time operations functions
Real Time Operations
Primary Cost Drivers
Primary
Exacerbators
Primary
Beneficiaries
System operation and
dispatch
Number or participants
Complexity of arrangements
Complexity of Security Policy and
PPOs
Generators
Purchasers
Generators
Distributors
Purchasers
Consumers
Supervising operations
Number or participants
Complexity of arrangements
Charcteristics of power system
Coordinating ancillary
services
Number of Ancillary Service (AS)
Providers
Complexity of arrangements
Generators
Distributors
Purchasers
Consumers
AS Providers
Generators
Consumers
AS Providers
Primary
Exacerbators
Primary
Beneficiaries
Table 13: After the fact analysis functions
After the fact (Ex-post)
Analysis
Primary Cost Drivers
Ancillary Services
monitoring
Number of Ancillary Service (AS)
Providers
Complexity of arrangements
Market monitoring and
providing market
information
Complexity of market arrangements
Characteristics of power system
Degree of non-compliance
Generators
Purchasers
Distributors
Grid
consumers
Generators
Purchasers
Distributors
Grid
consumers
System Operator
reporting
Complexity of market arrangements
Characteristics of power system
Generators
Purchasers
Distributors
Grid
consumers
Generators
Purchasers
Distributors
Grid
consumers
Investigating issues and
analysing events
Complexity of market arrangements
Characteristics of power system
Generators
Purchasers
Distributors
Grid
consumers
Generators
Purchasers
Distributors
Grid
consumers
Generators
Consumers
AS Providers
Attachment A
Table 14: Support functions
Support Activity
Primary Cost Drivers
Primary
Exacerbators
Primary
Beneficiaries
Providing and supporting
systems infrastructure
(control centres, IT,
communications etc)
Complexity of market arrangements
Characteristics of power system
Number of participants
Generators
Purchasers
Distributors
Consumers
Modelling, scheduling and
operational tool
development
Characteristics of power system
Complexity of market arrangements
Generators
Purchasers
Distributors
Grid
consumers
Participant support
Characteristics of power system
Complexity of market arrangements
Number of participants
Participants
seeking
support
Generators
Purchasers
Distributors
Grid
consumers
Service Provider
compliance
Characteristics of power system
Complexity of market arrangements
Compliance arrangements
System
Operator
System
Operator
Authority support
Developing the market arrangements
to deliver competition, efficiency and
reliability
Authority
Consumers