Variation to the National Electricity Market Access Code · which comprise the NEM Access Code or affect the NEM Access Code. On 5 November 1998, the National Electricity Code Administrator

Decision

Application to vary an access code

Variation to the National Electricity Market

Access Code

Date: 3 March 2004

File no:

Commissioners: M2002/254

SamuelSylvan

McNeillWillettMartin

Contents

GLOSSARY ......................................................................................................................................................... V

1. INTRODUCTION....................................................................................................................................... 1

2. STATUTORY TEST................................................................................................................................... 3

3. PUBLIC CONSULTATION PROCESS................................................................................................... 4

4. CHAPTER 3 OF THE NATIONAL ELECTRICITY CODE ................................................................ 5 4.1 INTRODUCTION..................................................................................................................................... 5 4.2 THE ACCESS CODE APPLICATION......................................................................................................... 5 4.3 SUBMISSIONS FROM INTERESTED PARTIES ............................................................................................ 6 4.4 COMMISSION’S CONSIDERATIONS......................................................................................................... 6 4.5 COMMISSION’S DECISION...................................................................................................................... 7

5. VARIATIONS TO THE NATIONAL ELECTRICITY MARKET ACCESS CODE ......................... 8 5.1 INTRODUCTION..................................................................................................................................... 8 5.2 THE ACCESS CODE APPLICATION......................................................................................................... 9 5.3 SUBMISSIONS FROM INTERESTED PARTIES ............................................................................................ 9 5.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 10

6. REGULATED INTERCONNECTORS, AUGMENTATIONS AND SYSTEM SECURITY COMPENSATION............................................................................................................................................. 12

6.1 INTRODUCTION................................................................................................................................... 12 6.2 THE ACCESS CODE APPLICATION....................................................................................................... 12 6.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 13 6.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 13 6.5 COMMISSION’S DECISION.................................................................................................................... 13

7. SETTLEMENT RESIDUE AUCTION................................................................................................... 15 7.1 INTRODUCTION................................................................................................................................... 15 7.2 THE ACCESS CODE APPLICATION....................................................................................................... 15 7.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 15 7.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 15 7.5 COMMISSION’S DECISION.................................................................................................................... 16

8. SOUTH AUSTRALIAN DEROGATIONS ............................................................................................ 18 8.1 INTRODUCTION................................................................................................................................... 18 8.2 THE ACCESS CODE APPLICATION....................................................................................................... 18 8.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 18 8.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 18 8.5 COMMISSION’S DECISION.................................................................................................................... 18

9. TRADING LIMITS, FUNDING FOR COMPENSATION FOR SYSTEM SECURITY DIRECTIONS, SETTLEMENT BY ESTIMATES AND INTRA-REGIONAL LOSS FACTORS........... 20

9.1 INTRODUCTION................................................................................................................................... 20 9.2 THE ACCESS CODE APPLICATION ....................................................................................................... 20 9.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 21 9.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 21 9.5 COMMISSION’S DECISION.................................................................................................................... 23

Variation to the NEM Access Code: Decision i

10. NATIONAL ELECTRICITY CODE MARK III.............................................................................. 24 10.1 INTRODUCTION................................................................................................................................... 24 10.2 THE ACCESS CODE APPLICATION....................................................................................................... 24 10.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 27 10.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 27 10.5 COMMISSION’S DECISION.................................................................................................................... 31

11. INTRODUCTION OF THE GOODS AND SERVICES TAX......................................................... 32 11.1 INTRODUCTION................................................................................................................................... 32 11.2 THE ACCESS CODE APPLICATION....................................................................................................... 32 11.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 32 11.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 32 11.5 COMMISSION’S DECISION.................................................................................................................... 33

12. AMENDMENTS TO THE NSW DEROGATIONS ......................................................................... 34 12.1 INTRODUCTION................................................................................................................................... 34 12.2 THE ACCESS CODE APPLICATION ....................................................................................................... 34 12.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 35 12.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 36 12.5 COMMISSION’S DECISION.................................................................................................................... 37

13. IRPC CONSIDERATION OF BASSLINK TECHNICAL ISSUES ............................................... 38 13.1 INTRODUCTION................................................................................................................................... 38 13.2 THE ACCESS CODE APPLICATION....................................................................................................... 38 13.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 38 13.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 38 13.5 COMMISSION’S DECISION.................................................................................................................... 39

14. REBIDDING, VOLL SCALING AND SETTLEMENTS STATEMENTS.................................... 40 14.1 INTRODUCTION................................................................................................................................... 40 14.2 THE ACCESS CODE APPLICATION....................................................................................................... 40 14.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 41 14.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 41 14.5 COMMISSION’S DECISION.................................................................................................................... 43

15. VOLL, CAPACITY MECHANISMS AND PRICE FLOOR .......................................................... 44 15.1 INTRODUCTION................................................................................................................................... 44 15.2 THE ACCESS CODE APPLICATION....................................................................................................... 44 15.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 45 15.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 45 15.5 COMMISSION’S DECISION.................................................................................................................... 48

16. ANCILLARY SERVICE AMENDMENTS....................................................................................... 49 16.1 INTRODUCTION................................................................................................................................... 49 16.2 THE ACCESS CODE APPLICATION....................................................................................................... 49 16.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 51 16.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 51 16.5 COMMISSION’S DECISION.................................................................................................................... 53

17. FULL RETAIL COMPETITION AND REGISTRATION OF CODE PARTICIPANTS ........... 54 17.1 INTRODUCTION................................................................................................................................... 54 17.2 THE ACCESS CODE APPLICATION....................................................................................................... 54 17.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 55 17.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 55 17.5 COMMISSION’S DECISION.................................................................................................................... 56

Variation to the NEM Access Code: Decision

ii

18. INTER-REGIONAL TRANSFER OF TUOS, TREATMENT OF LOSSES, IMPROVEMENTS TO PASA, PRICING UNDER EXTREME CONDITIONS, DEMAND SIDE PARTICIPATION AND END-USER ADVOCACY ................................................................................................................................. 57

18.1 INTRODUCTION................................................................................................................................... 57 18.2 THE ACCESS CODE APPLICATION....................................................................................................... 57 18.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 60 18.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 60 18.5 COMMISSION’S DECISION.................................................................................................................... 62

19. NETWORK PRICING AND MARKET NETWORK SERVICE PROVIDERS .......................... 63 19.1 INTRODUCTION................................................................................................................................... 63 19.2 THE ACCESS CODE APPLICATION....................................................................................................... 63 19.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 65 19.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 65 19.5 COMMISSION’S DECISION.................................................................................................................... 69

20. QUEENSLAND TECHNICAL DEROGATIONS ............................................................................ 70 20.1 INTRODUCTION................................................................................................................................... 70 20.2 THE ACCESS CODE APPLICATION....................................................................................................... 70 20.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 70 20.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 70 20.5 COMMISSION’S DECISION.................................................................................................................... 71

21. AVERAGING LOSS FACTORS IN DISTRIBUTION NETWORKS ........................................... 72 21.1 INTRODUCTION................................................................................................................................... 72 21.2 THE ACCESS CODE APPLICATION....................................................................................................... 72 21.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 72 21.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 73 21.5 COMMISSION’S DECISION.................................................................................................................... 73

22. NETWORK AND DISTRIBUTED RESOURCES ........................................................................... 75 22.1 INTRODUCTION................................................................................................................................... 75 22.2 THE APPLICATION............................................................................................................................... 75 22.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 76 22.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 76 22.5 COMMISSION’S DECISION.................................................................................................................... 78

23. PRUDENTIAL ARRANGEMENTS: SECURITY DEPOSITS ...................................................... 79 23.1 INTRODUCTION................................................................................................................................... 79 23.2 THE ACCESS CODE APPLICATION....................................................................................................... 79 23.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 79 23.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 79 23.5 COMMISSION’S DECISION.................................................................................................................... 80

24. VICTORIAN FULL RETAIL COMPETITION DEROGATIONS................................................ 81 24.1 INTRODUCTION................................................................................................................................... 81 24.2 THE ACCESS CODE APPLICATION....................................................................................................... 81 24.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 81 24.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 81 24.5 COMMISSION’S DECISION.................................................................................................................... 82

25. NEW SOUTH WALES FULL RETAIL COMPETITION DEROGATIONS ............................... 83 25.1 INTRODUCTION................................................................................................................................... 83 25.2 THE ACCESS CODE APPLICATION....................................................................................................... 83 25.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 83 25.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 83 25.5 COMMISSION’S DECISION.................................................................................................................... 84

Variation to the NEM Access Code: Decision iii

26. DISPUTE RESOLUTION ARRANGEMENTS................................................................................ 85 26.1 INTRODUCTION................................................................................................................................... 85 26.2 THE ACCESS CODE APPLICATION....................................................................................................... 85 26.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 85 26.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 85 26.5 COMMISSION’S DECISION.................................................................................................................... 86

27. FULL RETAIL COMPETITION MK II........................................................................................... 87 27.1 INTRODUCTION................................................................................................................................... 87 27.2 THE ACCESS CODE APPLICATION....................................................................................................... 87 27.3 SUBMISSIONS FROM INTERESTED PARTIES .......................................................................................... 87 27.4 COMMISSION’S CONSIDERATIONS....................................................................................................... 87 27.5 COMMISSION’S DECISION.................................................................................................................... 88

28. COMMISSION’S DECISION ............................................................................................................ 89 28.1 SUMMARY OF REASONING.................................................................................................................. 89 28.2 DECISION............................................................................................................................................ 91

APPENDIX A SUBMISSIONS ................................................................................................................. 92


iv

Glossary

ABARE Australian Bureau of Agriculture and Resource Economics

APC Administered Price Cap

APRA Australian Prudential Regulatory Authority

Commission Australian Competition and Consumer Commission

CPT Cumulative Price Threshold

CRNP Cost Reflective Network Pricing

DCP Distribution Connection Point

DNSP Distribution Network Service Provider

Draft Regulatory Principles

Draft Statement of Principles for the Regulation of Transmission Revenue (ACCC)

DRP Dispute Resolution Process

EPD Energy Policy Division

EPO Electricity Pricing Order

FCAS Frequency Control Ancillary Services

FRC Full Retail Competition

GST Goods and Services Tax

IES Intelligent Energy Systems

IPART Independent Pricing and Regulatory Tribunal

IRH Inter-Regional Hedge

IRPC Inter-Regional Planning Committee

IRSR Inter-Regional Settlements Residue

ITT Invitation to Tender

LNSP Local Network Service Provider

MEU Ministry of Energy and Utilities

Variation to the NEM Access Code: Decision v

MIG Market Implementation Group

MNSP Market Network Service Provider

NCAS Network Control Ancillary Services

NEC National Electricity Code (“Code”)

NECA National Electricity Code Administrator

NEM National Electricity Market

NEM Access Code That part of the Code accepted by the ACCC as an access code under s 44ZZAA of the TPA

NEMMCO National Electricity Market Management Company Ltd

NGF National Generators Forum

NRE Natural Resources and Environment

NSP Network Service Provider

PASA Projected Assessment of System Adequacy

QNI Queensland – New South Wales Interconnector

RIEMNS Review Integrating Energy Markets and Network Services

ROC Rate of Change

RRP Regional Reference Price

SAERSU South Australian Electricity Reform and Sales Unit

SAIIR South Australian Independent Industry Regulator (now known as the Essential Services Commission of South Australia (ESCOSA))

SCADA Supervisory Control and Data Acquisition

SRA Settlement Residue Auction

SRAS System Restart Ancillary Services

SRC Settlement Residue Committee

TCP Transmission Connection Point


vi

TLP Transmission Loss Factor

TNSP Transmission Network Service Provider

TPA Trade Practices Act 1974

TUoS Transmission Use of System

VENCorp Victorian Energy Network Corporation

VoLL Value of Lost Load

VTN Virtual Transmission Node

WACC Weighted Average Cost of Capital

Variation to the NEM Access Code: Decision vii

1. Introduction

On 10 December 1997, the Australian Competition and Consumer Commission (the Commission), under Part VII of the Trade Practices Act 1974 (TPA), authorised the National Electricity Code (Code) (which was initially made by the relevant State ministers under the National Electricity Law). On 16 September 1998, the Commission, under s 44ZZAA of the TPA, accepted as an industry access code Chapters 1, 2, 4, 5, 6, 7, 8, 9 and 10 of version 2.3 of the Code (NEM Access Code).

Since that time there have been a number of Code changes which have been authorised by the Commission under Part VII of the TPA. Those changes also vary components of the Code which comprise the NEM Access Code or affect the NEM Access Code.

On 5 November 1998, the National Electricity Code Administrator (NECA) lodged an application, under s 44ZZAA(6) of the TPA, to vary the NEM Access Code. The Commission consented to the application on 20 January 1999.

On 10 May 2002, the Commission received a further application from NECA to vary the NEM Access Code. NECA states:

The variations sought to be included in the approved NEM Access Code are:

• all other provisions of the Code not subject to the Commission’s approval of the NEM Access Code granted on 20 January 1999 (including chapter 3 for the first time); and

• those changes to the Code identified in Schedule A [to the application].

The granting of such approval would mean that the Code in its entirely would form the approved NEM Access Code for the purposes of section 44ZZA of the Trade Practices Act 1974, except for those Code changes which only have interim authorisation.

Schedule A to NECA’s application lists the Code changes from 20 January 1999 to 16 May 2002 that have received final authorisation by the Commission. These changes include:

Market operations for Y2K;

Regulatory test for new interconnectors and network augmentation;

Derogation for deferral of compensation;

Removal of market operations for Y2K changes;

Settlement residue auctions;

South Australian Derogations;

Trading limits;

Funding of compensation for system security directions;

Settlements by estimates and intra-regional loss factors;

Third tranche amendments (less Queensland ramp rate clauses);

Variation to the NEM Access Code: Decision 1


Capacity mechanisms;

Goods and Services Tax (GST) implementation;

Third tranche amendments (Queensland ramp rate derogation removal);

New South Wales (NSW) transmission network service pricing derogation;

Rebidding and revision of settlement statements;

Introduction of the GST;

Value of Lost Load (VoLL) scaling, implementation of VoLL, capacity mechanisms and removal of zero price floor;

Basslink technical issues;

Ancillary services;

Full Retail Competition (FRC) and registration of code participants;

Victorian FRC Derogations;

End-user advocacy, inter-regional transfer of Transmission Use of System (TUoS), treatment of losses, improvements to Projected Assessment of System Adequacy (PASA), pricing under extreme conditions; demand-side participation;

Extension of Queensland technical derogations;

Averaging of loss factors in distribution networks;

Network pricing and market network service providers;

Prudential arrangements: security deposits;

NSW FRC Derogations;

Network and distributed resources;

Dispute resolution arrangements; and

FRC.


2. Statutory test

Under section 44ZZAA of the TPA, an industry body may give a written code to the Commission setting out rules for access to a service. The Commission may accept the code, if it thinks it appropriate to do so having regard to the following matters:

(a) the legitimate business interests of providers who might give undertakings in accordance with the code;

(b) the public interest, including the public interest in having competition in markets (whether or not in Australia);

(c) the interests of persons who might want access to the service covered by the code;

(d) whether access to the service is already the subject of an access regime;

(e) any matters specified in regulations made for the purpose of [s 44ZZAA(3)];

(f) any other matters that the Commission thinks are relevant.

Regulation 6J of the Trade Practices Regulations 1974 sets out the following matters for the purpose of s 44ZZAA(3):

(a) government legislation and policies relating to ecologically sustainable development; and

(b) social welfare and equity considerations, including community service obligations; and

(c) government legislation and policies relating to matters such as occupational health and safety, industrial relations and access and equity; and

(d) economic and regional development, including employment and investment growth; and

(e) the interests of consumers generally or of a class of consumers; and

(f) the competitiveness of Australian businesses; and

(g) the efficient allocation of resources.

Section 44ZZAA(4) requires the Commission to publish the proposed code and invite and consider submissions.

Under s 44ZZAA(6), the industry body may ‘withdraw or vary the code at any time, but only with the consent of the Commission’. Although s 44ZZAA does not set out a statutory test or consultation procedure to apply to an application under s 44ZZAA(6), the Commission, in relation to NECA’s application of 10 May 2002, has applied the criteria in s 44ZZAA(3) and reg 6J (set out above) and followed the process in s 44ZZAA(4).


3. Public consultation process

As noted in Chapter 2, while the TPA does not specify the process that the Commission must follow when assessing a variation to an access code the Commission has followed a public process by publishing NECA’s application, inviting submissions and having regard to the statutory criteria set out s 44ZZAA(3) of the TPA.

The Commission received NECA’s application on 10 May 2002. Notification of the application and a request for submissions was advertised in the Financial Review on 31 May 2002, placed on the Commission’s website and subject to a direct mail out. Interested parties were requested to make submissions to the Commission addressing the criteria in s 44ZZAA(3) of the TPA.

As noted in Chapter 1, the Code changes which NECA has included in its application to vary the NEM Access Code have all been assessed as part of the Commission’s authorisation determinations or they are the result of NECA complying with the Commission’s authorisation conditions. These Code changes have been subject to extensive public consultation, through both NECA’s Code change process and the Commission’s authorisation process.

The National Generators Forum (NGF) (28 June 2002) and TransGrid (28 June 2002) provided submissions relating to NECA’s application. Both submissions have been placed on the Commission’s public register.

The Commission produced a Draft Decision setting out its analysis of the proposed variations to the NEM Access Code according to the statutory criteria outlined in Chapter 2. Following the release of the Draft Decision on 16 July 2003, the applicant and interested parties were provided with the opportunity to make further submissions in relation to the application.

The Commission received a further submission from TransGrid dated 22 August 2003. This submission has been placed on the public register.

On 5 November 2003, the Commission wrote to the NGF and TransGrid to clarify the Commission’s position as outlined in the Draft Decision and invited further comment on this position. The Commission received no further submissions.


4. Chapter 3 of the National Electricity Code

4.1 Introduction

On 10 May 2002, NECA submitted Chapter 3 of the Code to the Commission to be incorporated as part of the NEM Access Code for the first time.

Chapter 3 of the Code sets out the market rules. The market rules detailed the procedures which govern the operation of the market relating to the wholesale trading of electricity and the provision of ancillary services and include provisions relating to:

prudential requirements to be met for participation in the market;

the operation of the spot market;

bidding and dispatch;

spot price determination;

the determination of ancillary services prices:

NEMMCO clearing house and trading functions;

market information requirements and obligations;

the conditions and procedures for market suspension; and

settlements.

The market rules typically apply to NEMMCO, all market participants and scheduled generators. However, Chapter 3 also imposes obligations on Network Service Providers (NSPs), Jurisdictional Regulators and Local Retailers in respect of network losses, constraints and Projected Assessment of System Adequacy (PASA).1

4.2 The Access Code Application

In its application of 10 May 2002, NECA states that the operations of the NEM and the inter-relationship between the market rules and access provisions are becoming increasingly greater. As a result it seeks to vary the NEM Access Code to take account of these developments and improve the administration of the NEM Access Code. NECA, therefore, argues that the inclusion of Chapter 3 of the Code in the Access Code is sensible, from the viewpoint of completeness, and necessary, to the extent that Chapter 3 of the Code contributes part of the access regime for Market Network Service Providers (MNSPs) and is effectively a condition of access for many connection applicants.

1 Clause 3.1.3 Code


4.4 Commission’s considerations

4.4.1 Previous Access Code determinations

Regarding the NGF’s submission that the relevant clauses of Chapter 3 of the Code have

ces Act 1974 (TPA) the Commission accepts as

It also stated: of the applicant’s response to the access code draft decision, the Commission has accepted as

Further, in its 20 January 1999 decision the Commission reiterated this point:

On September 16 the Commission accepted as an industry access code chapters 1, 2, 4, 5, 6, 7, 8, 9 and 10

4.3 Submissions from interested parties

4.3.1 Inclusion of Chapter 3 of the Code in the NEM Access Code – pre Draft Decision

The NGF contends that it is inappropriate, and beyond the Commission’s power, for the market rules to be included in the NEM Access Code because the market rules define and regulate the operation of a competitive market, while the NEM Access Code sets out the rules for access to services provided by means of a facility. The NGF also states that there is no reason why the NEM Access Code and market rules should be identical as the two are separate and distinct although some provisions are common to both.

4.3.2 Inclusion of Chapter 3 of the Code in the NEM Access Code – post Draft Decision

Transgrid argues that Chapter 3 does contain some provisions which impose obligations on network service providers and that it is conceivable that some of these provisions are at least necessarily incidental to the access provisions contained in other chapters of the Code.

4.3.3 Previous NEM Access Code decisions

The NGF argues that the NEM Access Code as accepted by the Commission on 16 September 1998 and varied on 20 January 1999 incorporates those provisions of Chapter 3 of the Code that are rules for access to a service and, as a result, NECA’s application to include the whole of Chapter 3 in the NEM Access Code is unnecessary and should be withdrawn.

already been accepted by the Commission as part of the NEM Access Code; in its 16 September 1998 decision. The Commission stated:

Under Part IIIA, section 44ZZAA(3), of the Trade Practian access code chapters 1, 2, 4, 5, 6, 7, 8, 9 and 10 of version 2.3 of the National Electricity Code as submitted to the Commission on 28 August 1998.2

On the basisan access code chapters 1, 2, 4, 5, 6, 7, 8, 9 and 10 of version 2.3 of the National Electricity Code as submitted to the Commission on 28 August 1998.3

of version 2.3 of the National Electricity Code (Code).4

2 ACCC, NEM Access Code, 16 September 1998. p i. 3 Ibid p xii.


The Commission explicitly noted that ‘some of the code changes relate to chapter 3 of the Code and are beyond the scope of the NEM access code’.5

4.4.2 Inclusion of Chapter 3 of the Code into the NEM Access Code

The Commission agrees with the contention of Transgrid that elements of Chapter 3 are necessary and incidental to the operation of other access provisions contained elsewhere in the Code (for example, the settlement residue auctions provisions and the arrangements relating to market network service providers). However, the Commission does not consider that it is necessary to include all the provisions of Chapter 3 in the NEM Access Code. While the Commission agrees with NECA that the inter-relationship between the market rules and access provision are becoming increasingly greater, at this point in time, not all of the provisions in Chapter 3 appear to relate to the rules of access as required by s 44ZZAA(1) of the TPA. Although including the entire Chapter 3 in the NEM Access Code would simplify the future administration of the NEM Access Code, this could still be achieved by including in the NEM Access Code such provisions in Chapter 3 as, from time to time, are necessary or incidental to the operation of the other Chapters.

4.5 Commission’s decision

The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. In light of the submissions by Transgrid and NGF that not all of the provisions in Chapter 3 are ‘rules for access to a service’ as required by s 44ZZAA(1), the Commission does not consent to NECA’s NEM Access Code application to the extent that it seeks to vary the NEM Access Code by including the entire Chapter 3. However, the Commission would consent to the NEM Access Code being varied to include such provisions in Chapter 3 as are necessary or incidental to the operation of the other Chapters that form the NEM Access Code.

4 ACCC, Variations to the NEM Access Code, 20 January 1999 p 1: 5 Ibid p 3:


5. Variations to the NEM Access code

5.1 Introduction

NECA, in its application of 10 May 2002, has sought to include, in the NEM Access Code, all provisions of the Code authorised by the Commission until 8 May 2002. The amendments relating to the inclusion of Chapter 3 of the Code were dealt with in Chapter 4 above. The remaining amendments of the Code that NECA has applied to incorporate in the NEM Access Code include:

Market operations for Y2K;

Regulatory test for new interconnectors and network augmentation;

Derogation for deferral of compensation;

Removal of market operations for Y2K changes;

Settlement residue auctions;

South Australian Derogations;

Trading limits;

Funding of compensation for system security directions;

Settlements by estimates and intra-regional loss factors;

Third tranche amendments (less Queensland ramp rate clauses);

Capacity mechanisms;

GST implementation;

Third tranche amendments (Queensland ramp rate derogation removal);

NSW transmission network service pricing derogation;

Rebidding and revision of settlement statements;

Introduction of the GST;

VoLL scaling; implementation of VoLL, capacity mechanisms and removal of zero price floor;

Basslink technical issues;

Ancillary services;

Full retail competition and registration of Code participants;


Victorian Full Retail Competition Derogations;

End-user advocacy; inter-regional transfer of TUoS; treatment of losses; improvements to PASA; pricing under extreme conditions; demand-side participation;

Extension of Queensland technical derogations;

Averaging of loss factors in distribution networks;

Network pricing and market network service providers;

Prudential arrangements: security deposits;

NSW Full Retail Competition Derogations;

Network and distributed resources;

Dispute resolution arrangements; and

FRC.


In its application, NECA states that there have been a number of Code changes advanced by NECA and authorised by the Commission which have varied those components of the Code which comprise the NEM Access Code or affect the NEM Access Code. It seeks to vary the NEM Access Code to ‘take account of these developments and improve the administration of the NEM Access Code’. NECA notes:

Each of these Code changes have been assessed as part of the Commission’s authorisation determination in Division 1 of Part VII of the Trade Practices Act 1974. These Code changes have been the subject of industry and public consultation through the Code change processes set out in Chapter 8 of the Code and the Commission’s authorisation process.


5.3.1 Submissions lodged prior to the Draft Decision

Both the NGF and TransGrid raise concerns about NECA’s application which is based on the Commission having previously authorised the Code changes. They contend that NECA’s approach treat the amendments to the NEM Access Code as a procedural step. Both parties also note that while the tests contained in Part VII and Part IIIA of the TPA are similar (in that they both relate to public benefits), the tests require different matters to be taken into consideration. As a result, TransGrid requested an extension to time within which to make submissions.6

6 The Commission granted TransGrid an extension to the original timetable in which it could submit additional information in support of its first submission. However, the Commission notes that TransGrid did not lodge an additional submission this time.


The NGF contends that NECA’s application is inadequate and insufficient to enable the Commission to assess it in accordance with the administrative law principles it applies in relation to access code variations. The NGF argues that in the absence of NECA providing quantitative support in its application, the Commission cannot make an informed assessment as to:

whether NECA’s application for variation falls within the scope of Division 6 of Part IIIA; and

if so, whether it would be appropriate to consent to the variation having regard to the matters set out in s 44ZZAA(3).

5.3.2 Submissions lodged post Draft Decision

Following the Draft Decision, the Commission received a further submission from Transgrid. In the submission Transgrid contended that in approving prior authorisations in chronological order for inclusion into the NEM Access Code, the Commission would be including authorisations that have been amended by subsequent authorisations. Transgrid stated that this approach would result in superseded Code amendments being accepted into the NEM Access Code and that the Commission should only approve a consolidated version of the relevant section of the Code being accepted into the NEM Access Code.


The Commission concurs with the NGF that it could not consent to the amendments to the NEM Access Code if it only had access to the information provided in NECA’s application. However, the Commission has consulted widely on the changes in the course of its authorisation processes and has already considered the provisions in depth through those processes7. Additionally, through the course of its authorisation processes, the Commission obtained a substantial amount of material on which to base its current assessment on whether to consent to the proposed variations to the NEM Access Code. The Commission agrees with the NGF and TransGrid that there are sufficient differences between the criteria in Part IIIA and Part VII to warrant consultation with interested parties on NECA’s NEM Access Code application. However, submissions were only received from two parties by the Commission in the context of this decision and neither party raised any new issues for the Commission to consider. For this reason, the Commission believes that it is sufficient for it to rely on its authorisation analysis in considering NECA’s variations to the NEM Access Code. Each of the amendments to the NEM Access Code and the Commission’s decision is outlined in the subsequent chapters. The Commission notes that some of NECA’s amendments to the NEM Access Code are either outdated, relate to interim authorisations or are gazettal changes. Regarding the outdated provisions of the Code (such as the IRSR provisions which were authorised by the Commission after NECA lodged its NEM Access Code application), the Commission will

7 The Commission’s authorisation determinations are available on its website at www.accc.gov.au.


continue is dialogue with NECA to determine the most efficient manner in which to progress future amendments to the NEM Access Code. Those amendments that NECA has sought to include into the NEM Access code which relate to interim authorisations include: Capacity mechanisms;

GST implementation; and

Third tranche amendments (Queensland ramp rate derogation removal).

The Commission therefore only assessed these amendments in the context of the authorisation determination, not the interim authorisation.

The amendment relating to NECA gazettals which did not receive authorisation from the Commission was the removal of market operations for Y2K changes. The Commission authorised the amendments relating to Y2K on 20 October 1999. However NECA subsequently removed those provisions relating to the Y2K changes from the Code. Therefore, the Commission decided not to assess the arrangements in this decision.

In relation to Transgrid’s submission following the release of the Draft Decision, the Commission considers that the inclusion in chronological order of prior amendments to the Code into the NEM Access Code does not pose significant problems. The Commission considers that each authorisation will only be included in the NEM Access Code to the extent that it has not been superseded by a subsequent amendment.

The following sections deal with each individual amendment to the NEM Access Code.


NEMMCO approached the Commission to undertake a review of the existing criterion as part

6.2.2 Compensation payments for system security directions

A description of the compensation payments for system security directions changes is in

s to

until the earlier of:

6. Regulated Interconnectors and Augmentations and System Security Compensation

6.1 Introduction

On 23 July 1999 the Commission received applications for authorisation (Nos A90701, A90702 and A90703) of amendments to the Code, relating to the replacement of the Customer benefits test for new regulated interconnectors and network augmentations with a regulatory test to be determined by the Commission. The amendments also deferred NEMMCO’s obligation to make compensation payments to generators for system security directions.

The Commission authorised the regulated interconnectors and augmentation and system security compensation changes to the Code on 20 October 1999. The Code changes were gazetted by NECA on 18 November 1999.

On 10 May 2002, NECA submitted the regulated interconnectors and augmentation, and the system security compensation changes to the Code to the Commission to be incorporated as part of the NEM Access Code.


6.2.1 Regulated interconnectors and network augmentations

A description of the regulated interconnectors and network augmentations changes is outlined on page 3 of the Commission’s authorisation determination8. However, in brief the regulated interconnectors and network augmentations changes to the Code were introduced following NEMMCO’s rejection of the application for the proposed regulated South Australia – NSW interconnector under the Customer benefits test. NEMMCO found the Customer benefits test to be highly volatile and, as a result, the NSW Government placed it on the issues register which meant that the NEM would not commence until the issue was resolved.

of the Commission’s Draft Regulatory Principles. In light of this, NECA proposed amending the provisions of the Code replacing the Customer benefits test with a regulatory test.

outlined on pages 3 and 4 of the Commission’s authorisation determination. However,brief, at the time of the application, NECA was planning to submit Code changes to the Commission describing the methodology for NEMMCO to make compensation paymentgenerators for system security directions. The amendments deferred NEMMCO’s obligation

8 ACCC, Amendments to the National Electricity Code: Market Operations for Y2K, Regulated

Interconnectors and Augmentations and System Security Compensation, 20 October 1999, pp 2-4.


sation; or

According to NECA, this would ensure that the appropriate funding mechanism was in place bef ation were processed.

the Access Code Application in relation nd system security compensation code

changes. The parties who provided submissions in response to the authorisation applications

ork augmentations

The Commission’s consideration of the issues is outlined in pages 6-9 of its authorisation ges to the Code would

provide a public benefit, as the move to a regulatory test would encourage least cost network

ly pre-empt nor distort potential unregulated augmentations and therefore imposed a condition requiring the relevant clauses relating to comparing network options

security directions

The Commission accepted the argument that the proposed arrangements would provide a t increase participant fees and

that no claims for compensation are processed prior to the appropriate funding mechanism

matters in s 44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access

Two months after the Code is amended to provide a mechanism for NEMMCO to fund compen

31 January 2000.

ore claims for compens


The Commission did not receive any submissions onto the regulated interconnector and augmentations a

are listed on page 5 of the Commission’s authorisation determination.


6.4.1 Regulated interconnectors and netw

determination9. The Commission believed that the proposed chan

expansion.

However, the Commission was of the view that proposed regulated augmentations should not unnecessari

with generation and demand side options, to also consider any market network service provider option as part of the assessment.

6.4.2 Compensation payments for system

benefi to the public by ensuring that NEMMCO did not have to

being in place.


The Commission has considered the

seekers. The Commission believes that, in relation to this chapter, the analysis it conductedin its determination of 20 October 1999 is relevant to its assessment under s 44ZZAA. The Commission considers that NECA’s Access Code application satisfies s 44ZZAA(3) of the TPA in that the variations to the Access Code facilitate least cost network expansion, and

9 Ibid, pp 6-9.


’s also ensure that the system security compensation function is operated efficiently, and are, therefore, in the public interest. The Commission, therefore, proposes to consent to NECAAccess Code Application to vary the NEM Access Code by incorporating the regulated interconnector and augmentation and system security compensation changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations.


NECA lodged amendments to the applications on 24 May 1999, 22 June 1999 and

The Commission authorised the Settlement Residue Auction (SRA) amendments to the Code

On 10 May 2002, NECA submitted the SRA arrangements to the Code to the Commission to


A description of the application is outlined on pages 5 and 8 of the Commission’s ns of the

ghts to


The Commission did not receive any submissions on the Access Code Application in relation


The Commission’s consideration of the issues is outlined in pages 10 to 24 of its changes

ion d

7. Settlement Residue Auction

7.1 Introduction

On 20 May 1999, the Commission received applications for authorisation (Nos A90688, A90689, and A90690) of amendments to the Code. The proposed amendments enable an auction of portions of the inter-regional settlement residue (IRSR) to be undertaken by NEMMCO. The auctions are designed to facilitate inter-regional trade in electricity and increase retail competition by giving retailers the ability to manage inter-regional trading risk.

9 November 1999.

on 22 December 1999. The Code changes were gazetted by NECA on 3 February 2002.

be incorporated as part of the NEM Access Code.

authorisation determination10. In brief the SRA changes enable an auction of portioIRSR to be undertaken by NEMMCO providing a risk management tool to market participants by providing them with access to inter-regional hedges in the form of rispecified portions of the IRSRs.

to the SRA changes. The parties who provided submissions in response to the authorisation applications are listed in Appendix A on page 27 of the Commission’s authorisation determination.

authorisation determination. Generally, the Commission considered that the SRAwould facilitate inter-regional hedging and thus inter-regional trade in the NEM. The Commission considered that this would result in public benefits, with greater competitleading to greater economic efficiency and potentially lower energy prices through increaseretail competition. A summary of the main issues and the Commission’s considerations is outlined below.

10 ACCC, Amendments to the National Electricity Code: Settlement Residue Auction Process, 22 December

1999, p.1.


7.4.1 Limited auction participation

Concerns were raised by interested parties about the criteria for the exclusion of particular parties from the auction process. As a result, the Commission imposed a condition in the authorisation determination which required that the criteria for exclusions be included in the Code rather than in documents residing outside the Code.

The Commission also considered that the exclusion of Transmission Network Service Providers (TNSPs) would enhance the public benefits of the code amendments because of their ability to influence the SRAs through their involvement in the auction process. Additionally, the Commission agreed that South Australian generators should be excluded on the grounds that they could influence the South Australian regional spot price due to the frequency of constraints on the Heywood interconnector.

7.4.2 Pricing arrangements

Interested parties expressed concern at the need to set a reserve price for each unit of settlements residue to be auctioned. The Commission concluded that by enabling NEMMCO to set a reserve price end use customers are guaranteed a minimum benefit and the opportunity for auction participants to make windfall arbitrage gains is decreased.

7.4.3 NEMMCO’s discretion and rule change processes

A number of parties raised concerns about NEMMCO’s ability to exercise its discretion to suspend or cancel auctions; to choose the valuations which make up the reserve price and to set conditions on auction participation.

The Commission recognised that the creation of the Settlement Residue Committee (SRC) gives an opportunity for consultation and cooperation of market participants in creating auction rules. However, it was concerned that giving the SRC discretionary power to determine exclusions from participation was undesirable. It therefore imposed a condition to clarify the intent of the Code on this issue.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 22 December 1999 is relevant to this assessment. The Commission considers that NECA’s NEM Access Code application satisfies s44ZZAA(3) of the TPA in that the variations to the NEM Access Code increase the ability of market participants to manage the risks associated with inter-regional trade as well as facilitate increased competition in the NEM and is therefore in the public interest. The Commission, therefore, proposes to consent to NECA’s Access Code application to vary the NEM Access Code by incorporating the SRA changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations.

The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections


were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


8. South Australian Derogations

8.1 Introduction

On 28 October 1999, the Commission received applications for authorisation (Nos A90719, A90720 and A90721) of amendments to the Code, relating to the South Australian derogations. The Commission authorised the South Australian derogations changes to the Code on 25 January 2000. The Code changes were gazetted by NECA on 3 February 2000.

On 10 May 2002, NECA submitted the South Australian derogation changes to the Code to the Commission to be incorporated as part of the NEM Access Code.


A description of the application is outlined on page 3 of the Commission’s authorisation determination11. In brief, the amendments include derogations from clauses 2.2.1(a) and 2.5(a) of the Code. The derogations are a consequence of the leasing structure adopted by the South Australian government and are essentially designed to remove the obligation of the relevant lessor corporations or its successor in title, as the owner of the leased network and generation assets, to register as a Code participant.


The Commission did not receive any submissions on either the Access Code Application in relation to the SA Derogations or to the authorisation determination.


The Commission’s consideration of the issues is outlined in page 4 of its authorisation determination. Generally the Commission considered that, in light of the proposing leasing arrangements for the sale of South Australia’s electricity infrastructure assets, that the removal of the obligation for the asset owners to register as Code participants will not have a substantial impact on competition in the market and is likely to assist the transition into a fully competitive market.


The Commission has considered the matters in s 44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 25 January 2000 is relevant to its assessment under s 44ZZAA. The Commission considers that NECA’s Access Code application satisfies s 44ZZAA(3) of the

11 ACCC, Amendments to the National Electricity Code: SA Derogations, 25 January , p3.


TPA in that the variations to the Access Code facilitate a fully competitive market in South Australia. The Commission, therefore, proposes to consent to NECA’s Access Code Application to vary the NEM Access Code by incorporating the South Australian Derogations made to the Code to the extent that they have not been amended by subsequent authorisations.


9. Trading limits, Funding for compensation for system security directions, Settlement by estimates and Intra-regional loss factors

9.1 Introduction

On 10 September 1999, the Commission received applications for authorisation (Nos A90708, A90709 and A90710) of amendments to the Code. The proposed amendments relate to trading credit limits for market participants, funding for compensation for system security directions, settlement by estimates and intra-regional loss factors for new generation and transmission customers.

NECA lodged amendments to its applications on 23 September and 15 October 1999.

The Commission granted interim authorisation to the Code changes on 10 November 1999.

The Commission authorised the trading limits, funding for compensation for system security directions, settlement by estimates and intra-regional loss factors changes to the Code on 2 February 2000. The Code changes were gazetted by NECA on 24 February 2000.

On 10 May 2002, NECA submitted the Trading limits, Funding for compensation for system security directions, Settlement by estimates and Intra-regional loss factors changes to the Code to the Commission to be incorporated as part of the NEM Access Code.

9.2 The Access Code application

9.2.1 Trading limits

A description of the Trading limits application is outlined on page 3 of the Commission’s determination12. In brief, the trading limit changes to the Code sought to redefine the trading limit for market participants to represent the product of the prudential factor and the greater of:

(i) the market participant’s maximum credit limit; or

(ii) the credit support provided by the market participant.

9.2.2 Funding of compensation for system security directions

A description of the funding for compensation for system security directions application is outlined on page 5 of the Commission’s determination13. In brief, the funding of compensation payment changes to the Code allowed NEMMCO to recover compensation

12 ACCC, Amendments to the National Electricity Code: Trading limits, Funding for compensation for system

security directions, Settlement by estimates and Intra-regional loss factors, 2 February 2000, p 3. 13 Ibid., p 5.


paid to generators for system security direction from market customers in proportion to their energy usage in the relevant trading intervals.

9.2.3 Settlement by estimates

A description of the settlements by estimates application is outlined on page 6 of the Commission’s determination14. Generally, the proposed amendments allowed NEMMCO to facilitate settlement using estimated data (to be calculated using principles and processes developed by NEMMCO) where, for example, there has been a major failure of metering data processing, communications or the settlement processing systems.

9.2.4 Intra-regional loss factors

A description of the intra-regional loss factors application is outlined on page 7 of the Commission’s determination15. The amendments included:

an appropriate process for the calculation of intra-regional loss factors for new generator and transmission customers where no historical data exists;

the replacement of the term ‘twelve months’ with ‘financial year’ when describing the time period for data used in the calculation of intra-regional loss factors; and

the correction of some typographical errors.


The Commission did not receive any submissions on the Access Code Application in relation to the Trading limits, Funding for compensation for system security directions, Settlement by estimates and Intra-regional loss factors changes. Synergen was the only interested party to lodge a submission in response to the authorisation application.


The Commission’s considerations on the authorisation applications and issues raised in response to the authorisation applications are contained in pages 4 to 9 of its authorisation determination16. A summary of the main issues and the Commission’s considerations is outlined below.

9.4.1 Trading limits

The Commission expressed concern in its original authorisation determination of the Code regarding the number of prudential requirements contained in the Code, and argued that these demands could act as barriers to entry for new participants. The importance that these

14 Ibid., p 6. 15 Ibid., p 7. 16 Ibid., p 9.


requirements played in ensuring confidence and security in the NEM was recognised, however, and the majority of the prudential requirements were authorised.

The Commission argued that the trading limits amendments would be likely to result in a decrease in the aforementioned barriers to entry. The Commission also noted that granting participants the ability to increase their credit limits would invariably lead to more frequent or higher levels of trading, therefore improving liquidity and the efficiency of the market.

9.4.2 Funding of compensation for system security directions

In its 19 October 1998 determination, the Commission agreed that, in principle, the transparency of market arrangements would be improved, and the risk of disadvantage to particular generators reduced, if there was broad consistency between the methods of compensation provided in relation to the different types of directions. The Commission noted that as system security directions and ancillary services directions have the similar goal of maintaining power system security, it would not be unreasonable to use a similar method for determining compensation. However, this did not imply that such a method would always be the most accurate, or that compensation methods should be uniform.

Despite the above concerns and given the backlog of over fifteen directions at the time, the Commission understood the importance of providing a reasonable method of compensation prior to the completion of NECA and NEMMCO’s Joint Market Direction Review.17

9.4.3 Settlement by estimates

The Commission agreed that there were definite public benefits to be gained from reducing risk for market participants by providing increased certainty of cash flows during market failures.

The only potential problem identified by the Commission involved the method used to determine estimates in individual circumstances, however this was deemed unlikely to result in an anti-competitive outcome. The Commission noted that the potential for these problems to arise would be alleviated through NEMMCO’s consultation with market participants.

9.4.4 Intra-regional loss factors

The Commission agreed that the absence of an appropriate process for determining loss factors for new connection points was a considerable omission from the Code. Without these loss factors it becomes difficult for the market to function properly and is also likely to cause difficulties for new entrants. While the proposed changes were not the most precise method, the Commission recognised the need to have a method in place to increase market certainty, until NECA’s review was completed. It therefore supported the inclusion of a sunset clause to ensure the process was refined and replaced by a more efficient method by 31 December 2000.

17 This review – examining power system security and reliability direction, including how compensation

payments for directions should be funded – formed part of NECA’s derogation contained in the Commission’s 20 October 1999 determination.


In terms of the time periods for data collection, the Commission acknowledged the need to match time frames (ie matching financial year to financial year) in order to incorporate seasonal changes and peak load periods. Setting loss factors in April for the next financial year therefore necessitated that the previous financial year’s data be used. This requirement implied that the data used would be anywhere between 9 and 21 months old. While the Commission authorised this change to the Code, it strongly recommended that NECA consider these issues in its review into the scope for integrating the energy market and network services.


The Commission has considered the matters in s 44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 2 February 2000 is relevant to its assessment under s 44ZZAA. The Commission considers that NECA’s Access Code Application satisfies s 44ZZAA(3) of the TPA in that the variations to the Access Code facilitate the more efficient operation of the NEM by lowering potential barriers to entry, improving reliability, and reducing risk and uncertainty. The Commission proposes to consent to NECA’s Access Code application to vary the NEM Access Code by incorporating the trading limits, funding for compensation for system security directions, settlement by estimates and intra-regional loss factors changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


10. National Electricity Code Mark III

10.1 Introduction

On 28 August 1998, the Commission received applications for authorisation (Nos A90671, A90672 and A90673) of amendments to the Code. The proposed amendments facilitate the Mark III changes to the Code.

NECA lodged additional amendments on 16 September, 22 September, 2 October, 6 October, 20 October, 26 October, 5 November, 20 November 1998 and 7 June 1999.

The Commission granted interim authorisation to the amendments on 7 October 1998, 25 November 1998, 6 January 1999 and 9 June 1999.

The Commission authorised the Mark III changes to the Code on 22 December 1999. The Code changes (less the Queensland ramp rate clauses) were gazetted by NECA on 2 March 2000; the Queensland ramp rate derogation removal clauses were gazetted on 20 July 2000.

On 10 May 2002, NECA submitted the National Electricity Code Mark III changes to the Code to the Commission to be incorporated as part of the NEM Access Code.


10.2.1 Amendments relating to market arrangements

A description of the applications is outlined on pages 8-27 of the Commission’s determination18. However, in brief these changes to the Code related to the following issues:

Establishment costs

It was proposed NECA and NEMMCO be able to recover their establishment costs through participant fees.

Credit Support Arrangements

The market for credit support was broadened to include building societies or credit unions prudentially supervised in Australia as well as central borrowing authorities of an Australian State or Territory.

Technical derogations for Energy Brix

Units of the Energy Brix Morwell Power Station were exempt from providing reactive power support or power system stabilising action.

18 ACCC, Amendments to the National Electricity Code: National Electricity Code (Mark III), 22 December 1999, pp 8-27.


Maximum total payments

The amendments sought to clarify the extent of NEMMCO’s liability under the Code for energy and reallocation payments to market participants in the event of default by another participant.

Ancillary services

The amendments included extending the ancillary services arrangements in place at the time as well as introducing transitional “who pays” provisions.

Sensitive loads

The amendments specified that jurisdictional coordinators may nominate loads for which approval from the jurisdictional coordinator must be obtained before supply could be interrupted or reconnection occurs.

10.2.2 Changes to the NEM Access Code


Ring-fencing

The amendments to the Code introduced a set of guidelines for establishing ring-fencing provisions. The proposed amendments allowed for the ring-fencing guidelines to be developed by the Commission.

Embedded generators

The amendment specified that the NSP and generator must negotiate in good faith to establish amounts passed through to the generator for avoided TUoS charges that would otherwise have been payable by the NSP if the embedded generator was not connected to the distribution network.

Other changes to the NEM Access Code

Other amendments included the introduction of information disclosure requirements.

10.2.3 Transitional derogations


Queensland spot price determination (rate of change constraints and settlement) derogation

The derogation sought to address the issue of market prices in dispatch periods where generators are rate of change (ROC) constrained in a period of increasing load. That is, periods where the generator’s ability to increase its output (its ramp rate) is not sufficient to match the increase in load. In such circumstances higher cost generation plant is dispatched

19 Ibid., pp 28-33. 20 Ibid., pp 35-75.


to meet the ROC requirement. It was proposed that in such instances market price would be set ignoring ramping constraints. Plant operated to satisfy the increase in load would be paid their bid price only for that volume of output generated in response to the change in demand, rather than for the plant’s entire output in the dispatch period.

South Australian derogations

The amendments to the South Australia derogations included:

defining the South Australian jurisdictional regulator;

extension to the transmission and distribution loss factors arrangements;

setting the standards and protocols applying to South Australian networks;

allowing South Australian TNSP additional time to adopt NEMMCO’s standard terminology for use in South Australian networks;

the arrangements applying to the distribution of settlement settlements residue auction proceeds;

the methodology for the calculation of TUoS charges;

specifying that South Australia must be treated as one region until 31 December 2002;

the registration of the Osborne Cogeneration facility;

specifying the role of the South Australian jurisdictional regulator with respect to the regulation South Australian distribution networks;

allowing a government body appointed by the State Minister to have an “oversight” role in system planning within the State; and

specifying that for transmission and distribution network pricing, the regulatory instruments that must be applied by the regulator are the Electricity Act, the Independent Industry Regulator Act and the Electricity pricing Order (EPO).

New South Wales settlement surplus derogation

This derogation permitted the settlements surplus accruing to New South Wales from trade on inter-connection assets between Victoria and New South Wales to be distributed firstly to Snowy Hydro Trading and then to TransGrid to enable reductions in network charges as proposed in the Code. It was proposed that the derogation would cease by declaration by the relevant Minister that effective inter-regional hedging arrangements are available, or by 31 December 2002 at the latest.

10.2.4 Other issues raised

As part of their application, NECA and NEMMCO requested a re-authorisation of the entire Code.



The Commission did not receive any submissions on the Access Code Application in relation to the NEM Mk III Code changes. The parties who provided submissions in response to the authorisation applications are listed on page 99 (Appendix A) of the Commission’s authorisation determination.


10.4.1 Amendments relating to market arrangements

The Commission’s considerations of these issues are outlined in pages 8-27 of its authorisation.21

Establishment costs

The Commission appreciated that neither NECA or NEMMCO had the power to levy the participating jurisdictions in order to recover establishment costs, and having incurred the debt of establishment costs, recovery of this debt would have to be borne by Code participants.

The allocation of costs to market participants for the recovery of establishment costs could be guided by the “beneficiary pays” principle. However, in the absence of any clear-cut indication of who should pay, then notions of equity such as a 50/50 sharing of costs should be considered between generators and retailers.

Credit Support Arrangements

The amendment widened the range of potential credit support providers that market participants could access, however the Commission noted that the effect of the Code amendment was to restrict credit support provision to only some of the bodies supervised by the Australian Prudential Regulatory Authority’s (APRA). The Commission considered that the proposed amendment to the Code should be changed via the imposition of a condition to reflect the stated intentions of the applicants, and widen the market for credit support arrangements to all entities under the prudential supervision of APRA.

Technical derogations for Energy Brix

The Commission accepted that these technical derogations were required to avoid unnecessary and costly equipment upgrades, but had concerns regarding the cost implications of the technical derogations, in particular upon new entrants.

Maximum total payments

The Commission agreed with the applicants that NEMMCO should not bear the risk of default by other market participants and hence it was important to clarify the extent of NEMMCO’s liability, as set out in the proposed amendments.

21 ACCC, op.cit., pp 8-27.


Ancillary services

With respect to the Extension of Schedule 9G and clause 9.35.7, the Commission considered that given the timing constraints, the applicants had little option but to seek an extension to the chapter 9 ancillary services derogations that existed at the time. The Commission considered that such an extension provided for the best way forward, given the completion of the ancillary services review, and the inadequacies of the provisions of 3.11 of the Code.

The Commission considered that the “who pays” arrangements that existed at the time (where only market customers pay) and the proposed shift to a 50/50 split on who pays were equally arbitrary. Nevertheless, the Commission was of the view that a 50/50 split at least had some equity appeal and was probably closer to the appropriate balance on who pays than the requirement where retailers paid 100 percent.

Sensitive loads

The Commission was satisfied that this proposed amendment addressed the concerns pertaining to management of liability under existing contractual arrangements by restoring to the jurisdictional coordinator the authority to determine those loads to which supply cannot be interrupted or reconnected without prior consent.

The Commission also noted the applicant’s submission outlining the inconsistency between clause 4.3.2 and 4.8.9(c), and imposed a condition to correct this.

Typographical errors

There were a number of typographical errors concerning reviewable decisions and other matters, which the Commission corrected through imposing conditions.

10.4.2 Changes to the NEM Access Code


The Commission concluded that these amendments which allowed the development of ring-fencing guidelines, clarified arrangements for embedded generators, and facilitated improved information flows in the performance of both the Commission’s and jurisdictional regulators functions delivered significant public benefits and as a result authorised the amendments.

10.4.3 Transitional derogations


Queensland spot price determination (rate of change constraints and settlement) derogation

The Commission considered that the size and duration of price spikes would influence investment decisions regarding high cost (flexible) generation opportunities. In general, it is expected that there would be more investment in high cost plant where there are more (and

22 Ibid, pp 29-34. 23 Ibid, pp 40-76.


higher) price spikes than otherwise. Therefore to the extent that the derogation muted these price signals it could result in less investment in higher cost generation than otherwise.

Moreover, to the extent that the derogation discouraged investment in new peaking plant, it violated one of the fundamental premises underlying the NEM – that investment in generation is not distorted by restrictions that favour one generator over another.

The Commission also had concerns about the NEM operating under different pricing and dispatch rules in different regions. Such arrangements would greatly add to the complexity of the NEM.

The Commission also believed that there were doubts as to whether the derogation efficiently addressed any market power concerns that may be present. Indeed, the Commission believed that, by discouraging new investment in peaking plant and potentially leading to an inefficient use of any interconnectors, the derogation could entrench any market power problem that did exist.

The Commission was not convinced that the arrangements produced the benefits claimed, or addressed the concerns raised by the applicants, and as a result inserted a condition which required that these provisions be deleted.

10.4.4 South Australian derogations

Transmission and Distribution Loss Factors

The Commission acknowledged that while state based determination of loss factors may impact on the overall public benefit through locational price distortions as well as price distortions between final consumers, it considered that such arrangements in South Australia were not inappropriate for a transition period.

Power System Security Support

The Commission considered that the operation of the NEM could be jeopardised if power system security support standards were not met by all jurisdictions and imposed a condition to delete the relevant clause.

Nomenclature Standards

The Commission considered that the derogation allowed for a reasonable transition period in which current nomenclature standards could apply, before moving to the NEMMCO determined standards. Further, the Commission noted that similar derogations for Victoria and Queensland had been authorised earlier.

Distribution of the Settlement Surplus

The Commission considered that this derogation was a transitional measure which did not impact upon the NEMMCO settlements residue auction process, as the South Australian government was prohibited from conducting its own auction process once the NEMMCO auction process commenced.


Regulation of transmission network service pricing

Consistent with its assessment of the NEM transmission pricing regime, the Commission accepted that pricing approaches may need to balance competing efficiency and equity objectives, in particular in the context of avoiding a price shock to certain customers and thereby allowing a broad range of customers to share in the benefits of reform.

To this extent the Commission accepted that the South Australian derogation attempted to balance the interest of users and the wider public over the transitional period ending 31 December 2002.

South Australia as one region

The Commission shared the concerns about possible distortions caused by the existence of only one region in South Australia. Therefore, the Commission considered that as this derogation applied only for a limited time, the impact on overall public benefits was also limited, and it provided a suitable transition for the South Australian government to develop alternatives to achieve its policy objectives.

Registration as a Generator – Osborne Cogeneration

The derogation allowed for the Osborne output to be placed under the control of another generator. However, the Commission therefore considered that, given the market structure in South Australia, Osborne’s base load capacity would have the same impact on prices, wherever the Osborne contracts were located. Therefore, the Commission considered that the proposed derogation would give rise to sufficient benefits to the public from improved competition in the South Australian retail market to outweigh the anti-competitive detriment that could arise.

System Planning

The Commission observed that conflict of interest problems could well arise if the network planning function was retained within the NSP. The Commission was prepared to accept the derogation provided that it could be satisfied that the oversight regime imposed on the Planning Council was appropriate and enforceable. However, in order to mitigate any concerns of possible bias, the Commission recommended that the derogation be amended to provide that one of the appointments should be made by a relevant industry body and another appointment made by a relevant user group, which it considered provided appropriate safeguards against possible bias.

Network Pricing in South Australia

The Commission accepted that there was a need for transition from past State-based regimes to the national framework. However the Commission considered it essential that any such arrangements were in place no longer than was necessary and were transparent, in order to minimise the regulatory risk involved once the transitional arrangements ceased.

There were also aspects of the arrangements which were not consistent with the Code and thus the way in which the TNSP would be regulated by the Commission in future regulatory periods. However, the Commission was satisfied that, subject to the following, to the extent that the arrangements are inconsistent with the Code obligations beyond that time, the Code obligations will prevail. However, there were minor inconsistencies which were clarified by the Commission. For example, the Commission imposed a condition deleting the


requirement that a TNSP must not, without the ESCOSA’s approval, discontinue or cease to operate, maintain or service network assets

The Commission also had concerns with elements of the proposed distribution arrangements. For example, the Commission imposed a condition that required any reduction in network charges for non-contestable tariffs be passed through to those customers in the form of lower maximum retail prices. Further, the Commission imposed a condition to ensure that reductions caused by regulatory reviews to transmission charges were passed onto contestable customers.

New South Wales settlement surplus derogation

The Commission did not consider that the amendments to the NSW derogations raised any issues of substance, and the Commission granted authorisation to these amendment.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 22 December 1999 is relevant to this assessment. The Commission considers that NECA’s Access Code application acts to refine the Code in order to increase the efficiency of the NEM and is therefore in the public interest. The Commission proposes to consent to NECA’s Access Code application to vary the NEM Access Code by incorporating the Mark III changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


11. Introduction of the Goods and Services Tax

11.1 Introduction

On 15 June 2000, the Commission received applications for authorisation (Nos A90735, A90736 and A90737) of amendments to the Code. The proposed amendments sought to amend the Code in order to accommodate the introduction of the Goods and Services Tax (GST).

The Commission granted interim authorisation to these amendments on 21 June 2000.

The Commission granted authorisation to the GST changes to the Code on 6 December 2000. The Code changes were gazetted by NECA on 21 December 2000.

On 10 May 2002, NECA submitted the GST changes to the Code to the Commission to incorporate as part of the Access Code.


A description of the application is outlined on page 1 of the Commission’s authorisation determination24. Briefly, the introduction of the GST changes to the Code sought to introduce a clause into the Code which enabled taxable supplies under the Code to be priced to exclude GST. It also required Code participants and NECA to include the amount for GST in any payments made to another Code participant for a taxable supply and required NEMMCO to include the amounts for GST in settlements statements.


The Commission did not receive any submissions on the Access Code Application in relation to the GST changes nor did it receive any submissions in the response to the authorisation application.


The Commission’s considerations of the issues are outlined in pages 4 to 7 of its authorisation determination.25 While, in general, the Commission, in line with its role under Part VB of the TPA, required prices to be GST inclusive when displayed to end customers, the Commission accepted the arguments by NEMMCO and market participants that GST inclusive pricing would have added complexity to the NEM’s operations. The Commission also took into consideration the treatment of other commodity and auction markets and overseas practice in electricity markets.

24 ACCC, Amendments to the National Electricity Code: Introduction of the Goods and Services Tax, 6

December 2000, p 1. 25 Ibid., pp 4-7.


The Commission indicated to NEMMCO that it expected NEMMCO to make it clear to market participants and other interested parties that prices were quoted on a GST exclusive basis. The Commission therefore considered that the introduction of the proposed GST amendments to the Code would result in a benefit to the public in that the changes would facilitate compliance with the new tax system, and support the ongoing orderly conduct of the NEM.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 6 December 2000 is relevant to this assessment. The Commission considers that NECA’s Access Code application will facilitate compliance with the new tax system and support the ongoing orderly conduct of the NEM, and is therefore in the public interest. The Commission proposes to consent to NECA’s Access Code application to vary the NEM Access Code by incorporating the GST changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


12. Amendments to the NSW Derogations

12.1 Introduction

On 29 April 1999, the Commission received applications for authorisation (Nos A90684, A90685, A90686) of amendments to the Code. The applications were submitted by NECA on behalf of NSW Treasury. The proposed amendments related to the extension to the NSW Chapter 9 derogations for intra-regional loss factors.

NECA lodged additional amendments on 24 June 1999 to confirm that the Commission would be the transmission regulator in NSW from 1 July 1999.

The Commission granted interim authorisation to those derogations on 30 June 1999.

On 7 December 1999, NECA lodged further amendments to the derogation application, which stipulated that the Commission will set the opening asset value for all transmission system assets in NSW as well as to delay the introduction in NSW of Parts C and E of Chapter 6 of the Code.

The Commission provided interim authorisation to the first and third elements of these amended derogations on 15 December 1999 and to the remaining elements of the amendments on 25 January 2000.

On 21 June 2000, the Commission authorised the amendments to the Code. The Code changes were gazetted by NECA on 13 October 2000.

On 10 May 2002, NECA submitted the NSW Derogations changes to the Code to the Commission to be incorporated as part of the NEM Access Code.

12.2 The Access Code application

A description of the application is outlined on pages 4 to 7 of the Commission’s authorisation determination.26 However, in brief, the main changes to the Code are outlined below.

NSW Intra-regional loss factors

The NSW derogation provided that a government body as appointed by the Minister would determine intra-regional loss factors, which, at the time was the Independent Pricing and Regulatory Tribunal (IPART). NSW proposed extending its derogation by one year, to enable IPART to determine the loss factors that would apply in the year to 30 June 2000.

NSW transmission regulation

The NSW Government sought to amend its derogations to maintain the regulatory commencement date for the NSW transmission network of 1 July 1999. However, during the period 1 July 1999 until 31 January 2000, the Commission would administer the existing

26 ACCC, Amendments to the National Electricity Code: Amendments to NSW Derogations, 21 June 2000,

pp. 4-7.


t Commission to set an initial revenue cap for the period 1 February 2000 to

30 June 2004.

, orks,

n charges on behalf of other NSW transmission networks, for example EnergyAustralia.

e

) d according to their relative share of peak and shoulder energy supplied to that

network.

June

rding to IPART’s previous methodology or according to an alternate IPART methodology.


n relation

listed on page 24 (Appendix A) of the Commission’s uthorisation determination.

(rolled-over) IPART revenue (and pricing) determination and from 1 February 2000 onwards, the Commission’s transmission decision, pursuant to the Code would apply. The amendmenalso allowed the

NSW network pricing arrangements

The derogations stipulated that, until 30 June 2002, NSW specific transition arrangements would replace the Code arrangements relating to the allocation of transmission network coststhe calculation of transmission network prices, settlements and transfers between netwnetwork pricing software and pricing data. It also contained the methodology for the allocation of network prices for connection points. The arrangements also allowed for TransGrid to recover transmissio

Over or under recovery of revenue

The arrangements allowed for TransGrid to adjust its charges if in any year it recovered mor(less) revenue under the proposed pricing arrangements than allowed for in its revenue cap, in the following year the interconnected networks would receive a rebate (pay a surchargedetermine

Distribution network prices

The derogations stipulated that rather than reverting to the Code arrangements after 301999, NSW distribution prices were to be set on the basis of IPART’s earlier pricing determinations for the period between 1 July 1999 and 31 January 2000. In the subsequent period, from 1 February 2000 to 30 June 2002, IPART would have the discretion to decide whether NSW distribution prices are to be set according to the Code, acco

The Commission did not receive any submissions on the Access Code Application ito the NSW derogations. The parties who provided submissions in response to the authorisation applications area




NSW Intra-regional loss factors

While the Commission raised concerns about the possible precedent effect of extending the derogations, and its effects on achieving uniformity in the NEM, it noted NSW is in a unique position as its derogation was due to end some 18 months earlier than those of the other jurisdictions. Hence, other jurisdictions will have the opportunity to ‘smooth’ the transition to NEMMCO determined loss factors without extending their derogations, an opportunity that NSW has not had.

Considering the short term nature of the arrangement, the Commission concluded the public benefit arising from greater market stability was sufficient to outweigh any anti-competitive detriment.

NSW transmission regulation

As with the loss factor derogation, the Commission noted that NSW was in a unique position as its commencement date for national regulation of its transmission revenues comes into effect earlier than those of the other jurisdictions. Moreover, the extended date of 1 February 2000 is well within the period of 31 December 2002 which the Commission has used as a benchmark for the end of the transition path for each of the other jurisdictions.

NSW network pricing arrangements

NSW’s proposed amendments to the transmission pricing arrangements ended on 30 June 2002 and they were within the 31 December 2002 end dates in Victoria and South Australia and only six months after Queensland was due to implement the national arrangements on 1 January 2002. Consequently, consistent with the Commission’s views on the other amendments to NSW’s derogations, the network pricing derogations were considered unlikely, in themselves, to delay the introduction of a uniform approach to transmission pricing on 1 January 2003.

Over or under recovery of revenue

The NSW Government argued that the transfer from the existing transmission network pricing principles to the Code based pricing principles would result in a price shock to NSW electricity consumers. To address these concerns, the NSW Government proposed to allow TransGrid to use the existing (IPART determined) pricing methodology but within a revenue cap set by the Commission.

TransGrid confirmed that the derogations would allow it to systematically over recover its revenue cap. Under the derogations, this over recovery would be smoothed in the following year through rebates to the distribution networks. The Commission believed that the use of

27 Ibid. pp 14-21.


the WACC provided for symmetric treatment of under and over recovery of revenues as opposed to the bond rate, which is only applicable for funds invested. The Commission was also of the opinion that the WACC rate better reflected the opportunity cost borne by consumers arising from the over recovery of revenues, and therefore imposed the condition.

Regarding TransGrid’s recovery of revenue on behalf of EnergyAustralia, the Commission believed there was uncertainty about whether this extended to other TNSPs in NSW. It therefore imposed a condition clarifying that the pricing arrangements only referred to EnergyAustralia’s transmission network.

Commission approval for setting prices during the transition period

The proposed derogations stipulated that transmission networks must seek the Commission’s approval for setting prices that sought to implement the transition path and which departed from the above principles. While the proposed amendments placed an onus on the Commission to approve price deviations according to a defined set of principles, there was not an equivalent obligation on the transmission networks to justify their proposed prices. Consequently, the Commission believed that the derogations should be amended to provide the Commission with sufficient time and information to assess the proposed transition path proposed by the transmission networks, and it imposed conditions to this effect.

Distribution network prices

The amended derogations would have also allowed distribution network prices to be determined in accordance with either the Code, IPART’s previous methodology or according to an alternate IPART methodology. Again, these arrangements were within the end dates of the other jurisdictions moving to the Code’s distribution network pricing arrangements. Given the price shock and implementation concerns regarding a move across to the Code’s distribution network pricing principles and the short term nature of the derogations, the Commission believed that on balance they were likely to provide a public benefit that was sufficient to outweigh any anti-competitive detriment.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 21 June 2000 is relevant to this assessment. The Commission considers that NECA’s Access Code application satisfies s 44ZZAA(3) of the TPA in that the variations to the Access Code facilitate the efficient allocation of resources through improved price signalling in NSW and are therefore in the public interest. The Commission proposes to accept NECA’s Access Code application to vary the NEM Access Code by incorporating the NSW derogations that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


13. IRPC Consideration of Basslink Technical Issues

13.1 Introduction

On 13 September 2000, the Commission received applications for authorisation (Nos A90747, A90748 and A90749) of amendments to the Code. The proposed amendments facilitate consideration by the Inter-Regional Planning Committee (IRPC) of the technical network issues associated with Basslink and empower NEMMCO to impose any necessary technical requirements on its connection to the mainland grid.

The Commission authorised the IRPC consideration of Basslink technical issues changes to the Code on 24 January 2001. The Code changes were gazetted by NECA on 1 February 2001.

On 10 May 2002, NECA submitted the IRPC consideration of Basslink technical issues changes to the Code to the Commission to be incorporated as part of the Access Code.


A description of the application is outlined on pages 2 and 3 of the Commission’s authorisation determination28. As Tasmania is not currently a participating jurisdiction in the NEM, the Code does not provide for an assessment of the technical impact of Basslink on the NEM power system. However, in brief the IRPC consideration of Basslink technical changes to the Code related to putting Basslink in the same substantive position as if Tasmania was a participating jurisdiction in the NEM. The Code changes would facilitate the timely consideration by the IRPC of the technical network issues associated with Basslink on the wider national transmission network and empower NEMMCO to impose any necessary technical requirements on its connection to the mainland grid.


The Commission did not receive any submissions on the Access Code Application in relation to the IRPC consideration of Basslink technical issues. The parties who provided submissions in response to the authorisation application were the Office of the Tasmanian Electricity Regulator, the Victorian Energy Network Corporation (VENCorp) and TransGrid.


The Commission’s consideration of the issues is outlined in pages 4 and 5 of its authorisation determination. Generally, the Commission considered that there were only minor competition issues resulting from the proposed amendments to the Code.

The Commission concurred that there were public benefits in allowing the technical issues associated with Basslink to be considered before Tasmanian participants join the NEM. It

28 ACCC, Amendments to the National Electricity Code: IRPC Consideration of Basslink Technical Issues, 24

January 2001, p 2 and 3.


noted that the IRPC consideration of the technical network issues associated with Basslink was a potential barrier to Tasmania joining the NEM. However, the Code changes allowed this potential barrier to Tasmania’s NEM entry to be handled in a timely manner.

The Commission did not believe that any significant anti-competitive detriments were raised by the applications. The amendments enable Code processes to be followed for the consideration of the technical issues associated with Basslink before Tasmania joined the NEM. Therefore, the proposed Code changes merely put Basslink in the same substantive position as if Tasmania was a participating jurisdiction in the NEM.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 24 January 2001 is relevant to this assessment. The Commission considers that NECA’s applications facilitate consideration of technical issues associated with Basslink before Tasmanian participants join the NEM and the Code changes allow this potential barrier to Tasmania’s NEM entry to be handled in a timely manner and are therefore in the public interest. The Commission proposes to accept NECA’s Access Code application to vary the NEM Access Code by incorporating the IRPC consideration of Basslink technical issues changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


14. Rebidding, VoLL scaling and settlements statements

14.1 Introduction

On 15 March 2000, the Commission received applications for authorisation (Nos A90730, A90731 and A90732) of amendments to the Code. The proposed amendments related to rebidding practices.

NECA lodged additional amendments to the Code on 27 March 2000 relating to VoLL scaling and the revision of settlements statements.

The Commission authorised the rebidding, settlements statements and VoLL scaling amendments to the Code on 6 December 2000. The rebidding and settlements statements Code changes were gazetted by NECA on 21 December 2000; while the VoLL scaling Code changes were gazetted by NECA on 25 January 2001.

On 10 May 2002, NECA submitted the rebidding, settlements statements and VoLL scaling amendments to the Code to the Commission to be incorporated as part of the Access Code.


14.2.1 Rebidding

A description of the application is outlined on page 5 of the Commission’s authorisation determination29. However, in brief the proposed Code changes required participants submitting rebids to NEMMCO or notifying them of a dispatch inflexibility, to provide a ‘brief, verifiable and specific’ reason at the same time. In the case of rebids, NEMMCO would be required to publish the time of, and reason for, the rebid. In both cases, NECA could – in accordance with the guidelines to be developed – request information from the market participant to substantiate their reason. Other market participants would no longer be able to request this information from NECA.

14.2.2 VoLL scaling

A description of the application is outlined on page 11 of the Commission’s authorisation determination30. However, in brief the Code allows for inter-regional scaling of both the VoLL price cap and the price caps that apply during administered price periods. At the time, price scaling provisions within the Code allowed compensation to be paid for the impact of inter-regional settlements due to the application of price caps in the electricity market. However, the application of a price cap tends to remove inter-regional price differences and can have the effect of causing inter-regional settlements residues to become negative. Scaling was introduced to compensate for this impact as well as reduce the price paid to

29 ACCC, Amendments to the National Electricity Code: Rebidding, VoLL scaling and settlements statements,

6 December 2000, pp 5,11 and 15. 30 ACCC, Amendments to the National Electricity Code: Rebidding, VoLL scaling and settlements statements,

6 December 2000, pp 5,11 and 15.


r o the

ons under parallel provisions to those that already existed for administered prices.

14.2.3 Revision of settlements statements

utine

charges where a settlements statement revision affected the total settlements residue.


lication are listed at page 20 (Appendix A) of the Commission’s authorisation determination.


14.4.1 Rebidding

nt ing

the

hat these requirements would also impose a degree of discipline on market participants.

and

upstream generators to a value less than the price cap. The proposed Code changes providedfor scaling based on capping to scaled prices in all circumstances when the VoLL price cap applies in one or more regions. It also based scaled prices on the average loss equations foregulated interconnectors (rather than marginal losses) and allowed MNSPs access tcompensation provisi

A description of the application is outlined on page 15 of the Commission’s authorisation determination31. However, in brief the proposed changes to the Code imposed additional functions and requirements on NEMMCO. Some of those included requirements for rorevised settlements and allowed a correction to the settlements residues applied to the reduction of network

The Commission did not receive any on the Access Code Application in relation to the Rebidding, VoLL scaling and settlements statements changes. The parties who provided submissions in response to the authorisation app

The Commission’s consideration of the rebidding issues is outlined on pages 7-10 of its authorisation determination32. In general, despite concerns of generators exercising market power, the Commission was of the view that restrictions on rebidding may impose significacosts on the NEM and supported NECA’s proposal not to introduce any further rebiddrestrictions at the time. Further, the Commission was broadly supportive of NECA’s proposed revised rebidding information requirements. Information regarding the underlying reasons for rebidding may be a valuable tool in the market analysis of bidding behaviour, and may have also informed market development into the future. The Commission noted thatproposed informational requirements imposed an additional cost on market participants, however it believed t

The Commission noted that NECA was required under clause 3.8.22(c)(3) to develop guidelines regarding information that may be required to substantiate and verify the reasons for rebids. The Commission considered that these guidelines could usefully be extended to address some of the concerns raised by market participants regarding the extent, timing

31 ACCC, Amendments to the National Electricity Code: Rebidding, VoLL scaling and settlements statements,

6 December 2000, pp 5,11 and 15. 32 Ibid., pp 7-10, 13-4 and 16-7.


ed NECA to finalise the guidelines within three months of the Code changes being gazetted.

14.4.2 VoLL scaling

4 price

tion ling amendments

provided a practical solution to pricing during times of system stress.

would exist, again by facilitating a continuation of inter-regional trade during VoLL events.

ap

tion arrangements. The Commission imposed a condition of authorisation to ensure this.

14.4.3 Revision of settlements statements

6

alculations, NEMMCO must be able to recalculate settlements and issue a revised statement.

propriate to extend the coverage

was appropriate for

of

commercial sensitivity of information in respect of rebids. The Commission therefore imposed a condition that requir

The Commission’s consideration of the VoLL scaling issues is outlined on pages 13 and 1of its authorisation determination. In general, the Commission recognised that anyscaling, including VoLL scaling, would distort spot market signals. However, the Commission accepted NECA’s argument that conflicting market priorities would lead to market distortions during VoLL events, which may have triggered demands for compensaby market participants. The Commission recognised that the VoLL sca

The Commission noted that without VoLL scaling provisions VoLL events would usually lead to the removal of inter-regional price differences, and hence act to restrict inter-regional trade. Hence the Commission considered the proposed VoLL scaling arrangements effective in the prevention of barriers to inter-regional trade. The Commission also considered that theapplication of the VoLL scaling provisions would ensure some level of settlements residues

The Commission supported NEMMCO’s claims for equivalent treatment of the price c(either when the price was reduced to VoLL or was set at VoLL), the price floor, and administered prices, in respect of the scaling provisions and compensa

The Commission’s consideration of the settlement statements issues is outlined on pages 1and 17 of its authorisation determination. The Commission considered that accurate andprompt settlements statements would greatly contribute to the effective operation of the NEM, and enhance confidence in the spot market trading arrangements. The Commissionalso accepted that some revision of settlements statements would be required as new data became available and errors were corrected. Therefore, if a dispute was raised which was likely to alter end c

Further, the Commission agreed that where settlements statement revisions impacted upon the settlements residues accruing between regions, it was apof the settlements provisions to network service providers.

The Commission also considered it appropriate for affected parties to be able to join a dispute, and put forward their views prior to a dispute being resolved, as this may have reduced the likelihood of disputes cascading. Further, the Commission considered that inorder to ensure the greatest degree of accuracy in final settlements itNEMMCO to both be able to join a dispute, and to raise a dispute.

The Commission considered that it would be beneficial for the market to have two rounds routine revised statements, at 20 weeks and 30 weeks. It considered this to be in the best interests of all market participants as it allowed for the capture of any inaccuracies due to


limitation

ion

required NEMMCO to routinely recalculate settlements at periods of both 20 and 30 weeks.


d

nt

to the Code

cess d (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this

effect).

data or processing errors, and for the adjustment of settlements before the 6 monthon raising disputes. The Commission considered that this would be useful in the implementation of full retail contestability in which interval meters without communicatfacilities would be read quarterly. The Commission therefore imposed a condition that

The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of accessseekers. The Commission believes that, in relation to this chapter, the analysis it conductein its determination of 6 December 2000 is relevant to this assessment. The Commission considers that NECA’s Access Code application satisfies section 44ZZAA(3) of the TPA inthat the variations to the Access Code will assist the NEM to operate more efficiently and transparently, and are therefore in the public interest. The Commission proposes to conseto NECA’s Access Code application to vary the NEM Access Code by incorporating the rebidding, VoLL scaling and settlements statements changes that have been made to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM AcCode; an


On 10 May 2002, NECA submitted the VoLL, capacity mechanism and price floor changes


15.2.1 VoLL

A description of the application is outlined on page 5 of the Commission’s authorisation LL

one

50/MWh

15.2.2 Capacity Mechanisms

A description of the application is outlined on pages 53 and 54 of the Commission’s to the

r

15. VoLL, Capacity Mechanisms and Price Floor

15.1 Introduction

On 29 September 1999, the Commission received applications for authorisation (Nos A90711, A90712 and A90713) of amendments to the Code. The amendments relate to VoLL, capacity mechanisms, and the introduction of negative spot prices.

On 2 December 1999, the Commission granted interim authorisation to the Price Floor changes to the Code. NECA lodged typographical amendments to the applications on 26 April 2000.

Following a request from NECA, the Commission revoked the price floor interim authorisation on 21 June 2000 and granted a new interim authorisation covering the capacity mechanisms changes to the Code in addition to the price floor provisions contained in the original interim authorisation.

The Commission authorised the VoLL, capacity mechanism and price floor changes to the Code on 20 December 2000. The Code changes were gazetted by NECA on 25 January 2001.

to the Code to the Commission to be incorporated as part of the Access Code.

determination.33 In brief, the proposed VoLL changes to the Code involved increasing Voin two stages to $20,000/MWh and introducing a rolling three-year schedule of VoLL extended by one year in each annual review. Additionally, the application proposed theimposition of a cap on the market price if the cumulative effect of high spot prices over aweek period exceeds a threshold level of $300,000. In circumstances where this cumulative price threshold (CPT) is exceeded, the market price cap would be reduced to the Administered Price Cap (APC) of $300/MWh during peak times of the day and $during off-peak times.34

authorisation determination.35 Generally, the proposed capacity mechanisms changesCode involved replacing the eserve trader provisions of the Code with a reliability safety net

33 ACCC, Amendments to the National Electricity Code: VoLL, Capacity Mechanisms and Price Floor, 20

December 2000, p 5. 34 Peak time runs from 7am to 10pm. 35 ACCC, op.cit., pp 53-54.


which proposed to extend the timeframe for its operation from a six-month to a rolling 3-year period. The changes also proposed to maintain the Reliability Panel’s role in setting the reliability standard (expressed as a maximum level of unserved energy); while NEMMCO would remain responsible for calculating the appropriate level of capacity required in each region to meet that standard.

15.2.3 Price Floor

A description of the application in regards to the price floor is outlined on page 58 of the Commission’s authorisation determination.36 The application proposed removing the zero price floor and accompanying excess generation provisions and replacing it with a new floor of -$1000/MWh. The application also included a provision that would enable the Reliability Panel to review the market price floor at its next review of VoLL. The proposal also provided for negative administered prices, based on arrangements mirroring those of the administered price cap ceiling.


The Commission did not receive any submissions on the Access Code Application in relation to the VoLL, capacity mechanisms and price floor changes. The parties who provided submissions in response to the authorisation application are listed at pages 62-64 (Appendices A and B) of the Commission’s authorisation determination.


15.4.1 VoLL

The Commission’s considerations on the authorisation application with regard to VoLL, and issues raised in response to the application, are contained in pages 39 to 52 of its authorisation determination37. A summary of the main issues and the Commission’s considerations is outlined below.

Supply side incentives

In its 10 December 1997 determination, the Commission noted that if VoLL is set too low it may result in insufficient generation capacity being available in periods of excess demand, resulting in involuntary load shedding and serious disruption to the community. This view was reflected by some interested parties (predominantly generators) that investment in peak generation is driven by the revenue that can be achieved in the few hours a year when demand peaks occur, and the VoLL ($5,000/MWh) is too low to encourage this investment.

The Commission believed that a rise in the VoLL was necessary to encourage investment in those regions with a ‘peaky’ demand, although it was doubtful that a VoLL of $20,000/MWh was justified. According to the Commission’s consultants, Intelligent Energy Systems (IES), a peaking plant would derive revenue not only in periods of generation scarcity but also in

36 Ibid., p 58. 37 Ibid., pp 39-52.


other periods of higher spot prices. The Commission therefore considered that a VoLL lower than $20,000 would be sufficient to ensure investment in peaking generation.

A more detailed description of the Commission’s consideration is contained in pages 39 to 41 of its authorisation determination.

Demand side incentives

The Commission believed that there were significant impediments to effective demand side responses in the NEM, and under such circumstances, an increase in the level of VoLL would have a less significant impact in reducing demand.

Risk management

The Reliability Panel argued that VoLL acts as a cap on market price and therefore, at least in part, on risk. However, the Commission considered that an increase in the level of VoLL could impose substantial additional costs on end users. The Commission noted that, even for short periods of time, wholesale prices of $20,000/MWh can have a significant effect on average pool prices over a whole year.

Cumulative price threshold

The Commission noted NECA’s arguments that the CPT provisions were intended to replace VoLL as the primary mechanism for controlling risk in the NEM. The Commission considered that reducing the CPT would alleviate some of the concerns as to risk associated with sustained moderate increases in prices increasing average pool prices. However it still believed that VoLL would serve as the defacto price cap in instances of short periods of extreme prices.

Timing

The Commission concurred with the Reliability Panel’s recommendation that sufficient time should be given before the increase in VoLL is implemented to allow adequate notice to market participants, and to allow for further development of risk instruments to manage inter and intra-regional network related risk to accommodate the increase in risk associated with an increase in VoLL.

Market Power

At that time of its 10 December 1997 determination, analysis of the structure of the NEM by the Commission’s consultants, the Australian Bureau of Agricultural and Resource Economics (ABARE), indicated that the NEM was characterised by a significant degree of market concentration, particularly in South Australia and New South Wales. The Commission remained concerned that the detrimental impact on consumers of any exercise of market power would be magnified with an increased VoLL as proposed, and that the higher the level of VoLL was, the greater the impact on consumers. Therefore, any increase in VoLL needed to be coupled with enhanced market monitoring measures.

Therefore, given the Commission’s concerns about the above matters it imposed a condition that restricted the increase in VoLL to $10,000/MWh rather than $20,000/MWh.


Overseas Evidence

As part of the Commission’s examination of the proposed Code changes, the Commission also examined the level of price caps and market power mitigation measures in international electricity markets. The Commission noted that in contrast to these overseas markets, the NEM has less stringent market monitoring mechanisms. The Commission considered that differences in both the market design and market rules between the NEM and most overseas markets mean that the level of VoLL is more problematic in the NEM than would be the case in many overseas markets where other constraints on bidding behaviour serve to mitigate the potential to game the market. Therefore the Commission imposed conditions that required NECA to report on market behaviour in situations where the spot price exceeds $5,000/MWh, as well as a report by no later than 1 April 2003 on adequacy of current monitoring provisions in the NEM and future monitoring options.

15.4.2 Capacity mechanisms

The Commission’s considerations on the authorisation application with regards to capacity mechanisms and issues raised in response to the application are contained in pages 56 to 57 of its authorisation determination38. A summary of the main issues and the Commission’s considerations are outlined below.

The Commission considered that many of the concerns raised at market commencement as to the immaturity of the market remained valid. It appeared that the ability of the market based signals to deliver adequate system reserves and reduce the risk of involuntary load shedding was still limited. Consequently, the Commission considered that some sort of reliability safety net was necessary to accommodate the market, at least in the short term where a lack of market maturity may have resulted in unnecessary breaches of the minimum reliability margin, which could have led to involuntary load shedding.

The Commission remained concerned about potential supply side market power in the NEM generally, and noted that such market power problems could potentially raise the cost of contracting for reliability. The Commission did not consider that the proposed arrangements would necessarily raise such costs. The proposed Code changes provided for an annual review of the necessity of the reliability safety net by the Reliability Panel. The Commission noted that should it become apparent that market power problems were serving to raise the cost of contracting for reserves, then the reserve trader provisions should be revisited as part of the Reliability Panel’s review.

38 Ibid., pp 56-57.


e price floor and issues raised in response to the application are contained on page 59 of its

n t

ricing distorts price signals by not allowing the market to function unimpeded and formulate an appropriate response.

In order to address these concerns, the Commission’s 10 December 1997 determination

ss d

n

ce the operation of the NEM through improvements in price signals and capacity mechanisms, and are therefore in the public interest. The Commission proposes to consent to NECA’s Access Code Application to vary the NEM Access Code by incorporating the VoLL, capacity mechanisms and price floor changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).

15.4.3 Price floor

The Commission’s considerations on the authorisation application with regards to th

authorisation determination39. A summary of the main issues and the Commission’s considerations is outlined below.

In its 10 December 1997 determination, the Commission allowed a zero spot floor price as ainterim measure to address concerns regarding the maturity of demand side response at thatime. The Commission argued that customers are denied the market benefits of negative prices at times of very low demand and that non-negative p

required that the Code be amended to remove the zero spot price floor within one year of market commencement. The Commission accepted NECA’s argument that some floor level is essential to set the bounds of the dispatch algorithm. The Commission considered that a floor price of -$1,000/MWh will provide customers with the benefits of negative prices at times of very low demand and would allow the appropriate market signals to be sent therebyremoving a possible source of distorted market behaviour.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of acceseekers. The Commission believes that, in relation to this chapter, the analysis it conductein its determination of 20 December 2000 is relevant to this assessment. The Commissioconsiders that NECA’s Access Code Application satisfies s 44ZZAA(3) of the TPA in thatthe variations to the Access Code will enhan

39 Ibid., p 59.


16. Ancillary Service Amendments

16.1 Introduction

On 23 August 2000, the Commission received applications for authorisation (Nos A90742, A90743 and A90744) of amendments to the Code. The proposed amendments facilitate the introduction of a market based system for the procurement of ancillary services.

At the time of the initial application, NECA also requested interim authorisation for an interim frequency control ancillary service (FCAS) market, and other provisions to enable the new arrangements to be implemented prior to 31 December 2000. However, on 2 November 2000, NECA withdrew its interim authorisation request and the amendments to the Code required solely for the implementation of the interim FCAS market were being withdrawn from the application.

The Commission authorised the ancillary services amendments to the Code on 11 July 2001. The Code changes were gazetted by NECA on 9 August 2001.

On 10 May 2002, NECA submitted the ancillary services amendments to the Code to the Commission to be incorporated as part of the Access Code.


A description of the application is outlined on pages 8-9, 41-2 and 46 of the Commission’s determination40. A brief description of each of the changes to the Code relating to ancillary services is explained below.

16.2.1 Frequency control ancillary services

The proposed changes to the Code sought to introduce 8 spot markets for different components of FCAS:

Contingency services (large deviation FCAS):

second raise/lower

60 second raise/lower

minute raise/lower

Regulation services (small deviation FCAS):

raise/lower

In each market, clearing prices would be set for each dispatch interval (5 minutes), to apply to all providers within a region. Payments to service providers would be based on

40 ACCC, Amendments to the National Electricity Code: Ancillary Services Amendments, 11 July 2001, pp 8-

9, 41-2 & 46.


enablement of FCAS rather than actual use. The dispatch arrangements would allow for bidding and rebidding in the FCAS market to be undertaken on a similar basis to the energy market. NEMMCO would be the sole purchaser of FCAS on behalf of market participants, and the costs allocated to market participants on a causer pays basis, where causers can be measured.

NEMMCO would use supervisory control and data acquisition (SCADA) data to assist in allocating costs for regulation FCAS, with the costs of contingency FCAS being apportioned 100% to customers for lower services, and 100% to generators for raise services.

The changes to the Code set out a requirement for testing the proposed market environment prior to its introduction, as well as the extension of the Chapter 9 ancillary service arrangements allowing for the continuation of contract based procurement of FCAS until the introduction of the new market based arrangements.

16.2.2 Network control ancillary services

The proposed arrangements classified Network Control Ancillary Services as a non-market ancillary service and set out a continuation of the existing arrangements whereby NCAS were supplied through three mechanisms:

• mandatory supply of reactive power by generators – specified in connection agreements;

• TNSP provision of NCAS; and

• additional NCAS procured by NEMMCO through ancillary service contracts.

The Code changes proposed that NEMMCO would procure additional NCAS through an invitation to tender (ITT) process allowing NEMMCO to specify the required service quantities and technical criteria, in accordance with the standards specified by the Reliability Panel. Costs of NCAS procured by NEMMCO through the ITT process would be recovered wholly from market customers.

Where the ITT process was deemed to be non-competitive, negotiation could take place between NEMMCO and each potential supplier of NCAS, with scope for independent arbitration to be used to finalise contract details.

No changes were proposed in respect of the mandatory supply of reactive power or the provision of NCAS by TNSPs. The Code changes also provided for a review of ancillary service arrangements, including the potential for developing NCAS markets. The review was to be undertaken by NEMMCO before 30 November 2001. The Code changes allowed for contracts entered into under the provisions of the Chapter 9 ancillary services derogations to continue after the commencement of the new ancillary ervices arrangements. s


16.2.3 System restart ancillary services

The Code changes proposed that System Restart Ancillary Services would be centrally procured by NEMMCO, through an ITT process. Where the ITT process is deemed to be non-competitive, negotiation may take place between NEMMCO and the potential suppliers of SRAS, with scope for independent arbitration to be used to finalise contract details.

The changes provided for half the costs of SRAS to be recovered from generators and half the costs to be recovered from market customers, in proportion to their energy trading.

The changes also allowed for contracts entered into under the provisions of Schedule 9G to continue after the commencement of the new ancillary services arrangements.


The Commission did not receive any submissions on the Access Code application in relation to the ancillary services changes. The parties who provided submissions in response to the authorisation applications are listed on page 58 (Appendix A) of the Commission’s authorisation determination.


16.4.1 Frequency control ancillary services

The Commission’s consideration of the issues are outlined in pages 19-40 of its authorisation determination.41

Generally, the proposed arrangements for FCAS would introduce 8 spot markets, operating under similar conditions to that of the energy spot market. The original arrangements provided for potential suppliers of ancillary services to tender for contracts with the market operator NEMMCO. Participation in the FCAS spot markets will be open to all NEM participants that can meet the required technical criteria.

The Commission considered that as the proposed arrangements did not rely on long term contracts, it would be possible for NEM participants to more easily enter the FCAS markets than under the present contract arrangements, which effectively prevent new competitors participating for the life of the contracts. As such, the Commission did not consider that the proposed arrangements represented a lessening of competition in the FCAS markets, in comparison to the existing arrangements.

The Commission also noted that while many submissions disputed the likely level of benefits that may arise from the FCAS spot markets, interested parties did not claim that there would be any lessening of competition in the FCAS markets. However, the Commission believed that generators could alter their behaviour as a result of the interactions between the energy and FCAS markets, although the Commission believed the significance of any such change in behaviour to be minor.

41 Ibid., pp. 19-40.


The Commission noted that the relative sizes of the energy and FCAS markets suggests there will only be a marginal change in generator behaviour and hence considers the lessening of competition in the energy market to be insignificant.

Overall, the Commission believed that the expected benefit to the public arising from greater efficiencies in the investment, production and use of FCAS would outweigh the public detriment arising from the possibility of a lessening of competition in the related energy market, and as such authorisation should be granted.

The Commission, however, imposed conditions relating to the review and reporting requirements placed upon NEMMCO, requiring NEMMCO to provide all market participants with forward estimates, changes in requirements and other information relating to FCAS. NECA was also required to monitor and review the performance of the FCAS markets. Furthermore, a condition of authorisation was made to allow the annual fixed fee to be set at zero where a market customer registers with NEMMCO solely for the purpose of participating in the FCAS market and does not operate in the energy markets.

16.4.2 Network control ancillary services

The Commission’s consideration of the issues is outlined in pages 43-5 of its authorisation determination.42 Generally, the Code changes did not represent any major change to the current system of procurement of NCAS that existed at the time. Further, the Commission noted that a number of reviews could impact upon the future provision of NCAS.

The Commission argued that market development work in ancillary services needs to be coordinated with all market development work undertaken. An assessment of the potential impact of the various reviews upon each other needed to be made explicit, including proposed changes and likely timing of reports and implementation of outcomes. As such, the Commission recognized that it may be necessary to accommodate the outcomes of other reviews in the planning and implementation processes of the ongoing ancillary services review.

The Commission fully supported the proposal to introduce a causer pays arrangement for ancillary services. The Commission believed that such an arrangement would lead to increased market efficiency by attributing costs to the parties that can best act to minimise the costs, and in doing so, minimise the overall need for ancillary services in the NEM.

The Commission noted arguments that the proposed arrangements were less than ideal, and required significant work to be undertaken. However, the Commission considered that it was appropriate to await the outcome of the relevant reviews and allow for the development of a better cost allocation methodology once the regulatory and commercial frameworks were settled.

The Commission noted concerns regarding the cost minimisation incentive on NEMMCO but considered the provisions of clause 3.11.5(d1)(1) clearly impose a cost minimisation requirement upon NEMMCO.

42 Ibid., pp. 43-5.


16.4.3 System restart ancillary services

The Commission’s consideration of the issues is outlined in pages 48-50 of its authorisation determination.43

The Commission noted the widespread support for the continuation of the centralised procurement of SRAS through a contract market. It also considered that the requirements for providers of SRAS to meet technical standards as specified by NEMMCO would have little impact on the effective level of competition in the SRAS market. However, the Commission noted that confidence in NEMMCO’s ability to restore the power system is a major benefit of SRAS. Hence, in order to increase that confidence the Commission considers that NEMMCO’s plans and procedures for system restart should be open to public scrutiny.

The Commission considered that market confidence could be enhanced by the availability of system restart plans and strongly recommended that NEMMCO and all market participants consider the need for more transparent procedures regarding system restart.

The Commission did not support the calls for revising the cost allocation on regional grounds, partly due to the increased level of complexity that such a process could introduce, which may not be warranted given the relative size of SRAS costs. Further, given the lack of public information about plans for restarting different regions and the whole of the NEM, it would have been difficult to determine which SRAS costs should be billed to which NEM participants, especially if inter-regional flows were to be used to restore the system.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 11 July 2001 is relevant to this assessment. The Commission considers that NECA’s Access Code Applications satisfies s44ZZAA(3) of the TPA in that the variations to the Access Code enable a more efficient provision of ancillary services, and are therefore in the public interest. The Commission proposes to consent to NECA’s Access Code Application to vary the NEM Access Code by incorporating the ancillary services changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).

43 Ibid., pp. 48-50.


17. Full Retail Competition and Registration of National Electricity Code Participants

17.1 Introduction

On 11 August 2000, the Commission received applications for authorisation (Nos A90739, A90740 and A90741) of amendments to the Code. The proposed amendments facilitate the introduction of full retail competition (FRC) and amend the procedures for the registration of code participants. NECA lodged a typographical amendment to the FRC changes to the Code on 17 August 2000.

The Commission authorised the FRC and registration of code participants changes to the Code on 1 August 2001. The Code changes were gazetted by NECA on 16 August 2001.

On 10 May 2002, NECA submitted the FRC and registration of code participant changes to the Code to the Commission to be incorporated as part of the Access Code.


17.2.1 Full Retail Competition

A description of the FRC changes is outlined on pages 5 and 6 of the Commission’s authorisation determination44. In brief, the FRC changes to the Code introduced lower cost alternatives (including profiling) to remotely read interval metering, which are designed to enable all customers to change their electricity retailer. Under the previous Code arrangements a customer switching retailers was required to install a manually read interval meter. The Code changes also introduced a metrology coordinator into the Code who is responsible for designing and approving the metrology procedures required for the installation of the lower cost metering alternatives.

17.2.2 Registration of Code participants

A description of the registration of code participants changes is outlined on page 26 of the Commission’s authorisation determination45. Generally, to register as a code participant, NEMMCO must be reasonably satisfied that the person meets the specified eligibility requirements in the Code. However, with the introduction of FRC, new retailers entering the market may not be in a position to supply customers, and therefore would be ineligible to register as a code participant. This would also affect the registration of distribution businesses who have statutory obligations to act as a retailer of last resort. The Code changes enabled a new retailer or a retailer of last resort to register as a market customer without

44 ACCC, Amendments to the National Electricity Code: Full Retail Competition and Registration of Code

Participants, 1 August 2001, pp 5 and 6. 45 ACCC, Amendments to the National Electricity Code: Full Retail Competition and Registration of Code

Participants, 1 August 2001, p 26.


requiring it to identify a connection point immediately (provided it can do so to NEMMCO’s satisfaction).


The Commission did not receive any submissions on the Access Code Application in relation to the FRC or registration of code participant changes. The parties who provided submissions in response to the authorisation applications are listed at page 35 (Appendix A) of the Commission’s authorisation determination.


17.4.1 Full Retail Competition


Role of the metrology coordinator and metrology procedures

There were a number of issues raised by interested parties regarding the role of the metrology coordinator and, in particular the design and approval process for the metrology procedures.

The Commission considered that initially there are public benefits arising from the metrology coordinator design and approving the metrology procedures while requiring the jurisdictional regulator to undertake the role of metrology coordinator in the longer term. It, therefore, imposed a condition to that effect. It also imposed a condition that the jurisdictional regulator would be required to complete a review of the metrology procedures within 6 months of commencing its role as metrology coordinator.

In the longer term, the Commission argued that the benefits of FRC would only be facilitated by a single metrology procedure. It, therefore, imposed a condition that the jurisdictional regulators consider the costs and benefits of a single nationally consistent approach in a joint review which must be completed by 31 December 2003.

Metering installations type 5 and 6

Opinion was divided on whether the Commission should impose a condition that mandated a fully interval metered solution. The Commission considered that there would be short term benefits arising from enabling a low cost alternative to facilitate customer choice without mandating a roll out of interval meters. However, in the longer term the Commission argued the benefits of FRC would not be delivered unless there is a move towards interval metering. The Commission, therefore, imposed a condition that required the jurisdictional regulators to

46 ACCC, Amendments to the National Electricity Code: Full Retail Competition and Registration of Code

Participants, 1 August 2001, pp 12 to 25.


lations types 5 and 6, in addition to developing a single national metrology procedure by 31 December 2003.

e Commission considered these Code changes would ailers to enter the market and thereby increase the

potential for greater price and non-price competition to be delivered to customers.

s

ion at

e,

this Code are not included in the

NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).

jointly conduct a review of metering instal

17.4.2 Registration of code participants

There were no issues raised by interested parties.

In its authorisation determination, thprovide greater opportunities for ret


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of accesseekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 20 December 2000 is relevant to this assessment. The Commissconsiders that NECA’s Access Code Application satisfies s 44ZZAA(3) of the TPA in ththe variations to the Access Code facilitate competition in the retail market and are, thereforin the public interest. The Commission proposes to consent to NECA’s Access Code Application to vary the Access Code by incorporating the FRC and registration of code participants changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections ofauthorisation incorporating amendments to Chapter 3 of the


18. Inter-regional transfer of TUoS, treatment of losses, improvements to PASA, pricing under extreme conditions, demand side participation and end-user advocacy

18.1 Introduction

On 8 December 2000, the Commission received applications for authorisation (Nos A90766, A90767 and A90768) of amendments to the Code. The proposed amendments relate to:

inter-regional transfer of transmission use of system (TUoS) charges; and treatment of losses (interim issues).

On 18 December 2000, NECA lodged additional Code amendments relating to:

improvements to the projected assessment of system adequacy (PASA); pricing under extreme conditions; demand side participation; and end-user advocacy.

On 12 December 2000 the Commission granted interim authorisation to the inter-regional transfers of TUoS and treatment of losses code changes. On 14 February 2001, the Commission granted interim authorisation to the pricing under extreme conditions code changes. The Commission authorised the inter-regional transfer of TUoS, treatment of losses, improvements to PASA, pricing under extreme conditions, demand side participation and end-user advocacy amendments to the Code on 19 September 2001. The Code changes were gazetted by NECA on 11 October 2001.

On 10 May 2002, NECA submitted the inter-regional transfer of TUoS, treatment of losses, improvements to PASA, pricing under extreme conditions, demand side participation and end-user advocacy changes to the Code to the Commission to be incorporated as part of the Access Code.


18.2.1 Inter-regional transfer of TUoS

A description of the inter-regional transfer of TUoS changes is outlined on page 4 of the Commission’s determination47. In brief, the inter-regional transfer of TUoS changes to the

47 ACCC, Amendments to the National Electricity Code: Inter-regional transfer of TUoS, treatment of losses,

improvements to PASA, pricing under extreme conditions, demand side participation and end-user advocacy, 19 September 2001, p 4.


Code related to extending the moratorium on the transfer of inter-regional TUoS from the existing 1 January 2001 to 1 July 2002.

18.2.2 Treatment of losses (interim issues)

A description of the treatment of losses (interim issues) changes is outlined on page 5 of the Commission’s determination48. In brief, NECA is reviewing the scope for integrating the energy market and network services (RIEMNS) which includes proposals on the treatment of losses. To allow time for the recommendations to be properly considered and to implement the outcomes of the review, NECA proposed interim changes to:

extend the operation of schedule 3.2, on the calculation of loss factors in its existing form, and specifically to extend the sunset clause on the fast track change to accommodate the calculations of loss factors for new entrants to the market from 31 December 2000 to 30 June 2002; and

renew the chapter 8 derogation to make it clear that NEMMCO should not currently be

required to calculate time varying loss factors until 30 June 2002 whilst NEMMCO develops the proposed new methodology.

18.2.3 PASA

A description of improvements to PASA changes is outlined on pages 8 and 9 of the Commission’s determination49. While it was thought that the PASA arrangements in existence at the time worked well, it was acknowledged that there was scope to improve the overall operation of PASA. To remove the ambiguity surrounding the definition of expected availability and acknowledge the crucial role of timing in relation to commitment decisions, NECA’s changes included:

clarifying and enhancing the information generators provide to NEMMCO by removing the ambiguity regarding expected availability and drawing a distinction between the capacity they intend to make available and the capacity they could make available in extreme conditions; and

ensuring that network information is provided in accordance with the timetable specified

in the Code.

18.2.4 Pricing under extreme conditions

A description of the pricing under extreme condition changes is outlined on page 12 of the Commission’s authorisation determination50. Generally, restrictions on the use of electricity may be imposed by a jurisdiction as a means of controlling demand and averting a situation where there is insufficient generation capacity to meet demand. The market does not

48 ACCC, Amendments to the National Electricity Code: Inter-regional transfer of TUoS, treatment of losses,

improvements to PASA, pricing under extreme conditions, demand side participation and end-user advocacy, 19 September 2001, p 5.

49 ibid p 8. 50 ibid p 12.


recognise such restrictions as load shedding and as a result, the spot market price may fall in step with the reduction in demand due to restrictions. The resulting depressed price signal contrasts to the high (or VoLL) price signal market participants would have otherwise seen had restrictions not being imposed. The pricing under extreme condition changes to the Code integrated restrictions into the market through a combination of capacity contracting and a refinement to the ‘what-if’ pricing arrangements that NEMMCO currently uses if it intervenes in the market. The pricing provisions in the Code were also amended to ensure that the price is set at VoLL whenever, but only when, there is an imbalance of supply and demand in the energy market.

18.2.5 Demand side participation

A description of the demand side participation changes is outlined on page 27 of the Commission’s authorisation determination51. In brief, the demand side participation changes provided an improved framework for demand side bidding. Under the previous Code arrangements, direct demand side bidding was rarely used. A key disincentive to the use of direct demand-side bidding, as perceived by end-use customers, was the requirement for absolute symmetry between the rules governing the supply and demand sides of the market. The Code changes made the framework for demand side bidding more attractive to end-use customers through addressing the perceived barriers to demand side biding by restructuring and simplifying the arrangements.

18.2.6 End-user advocacy

A description of the end-user advocacy changes is outlined on pages 31 and 32 of the Commission’s authorisation determination52. In its 22 December 1999 determination, the Commission required NECA to explore ways to improve the ability for end-use customers to participate in the development of the NEM and in the Code change process. At that time, NECA was only obliged to consult with market participants (for example, generators, networks and retailers) on proposed Code changes. Subsequently, NECA undertook a review and proposed a number of Code changes to:

give end-users the same rights as market participants in the Code change making processes;

require NECA and NEMMCO to improve their practices and procedures for dealing with end-users; and

establish the Advocacy Panel. NECA’s review acknowledged that small and medium end-users generally do not have access to sufficient human and financial resources to ensure adequate representation. The Code changes amended clause 2.11 so that market based funding for end-user advocacy is provided through the imposition of a levy upon generators and retailers. The role of the

51 Ibid p 27. 52 Ibid pp 31 and 32.


Advocacy Panel is to administer end-user advocacy functions and allocate market funding to specific projects for end-users. 18.3 Submissions from interested parties

The Commission did not receive any submissions on the Access Code application in relation to the inter-regional transfer of TUoS, treatment of losses, improvements to PASA, pricing under extreme conditions, demand side participation and end-user advocacy changes. The parties who provided submissions in response to the authorisation applications are listed at page 50 (Appendix A) of the Commission’s authorisation determination.


18.4.1 Inter-regional transfer of TUoS

There were no issues raised by interested parties.

In its authorisation determination, the Commission considered these Code changes would enable sufficient lead-time to facilitate the smooth transition of those arrangements under consideration to be implemented and, as such, improve the overall efficiency of the NEM.

18.4.2 Treatment of losses (interim issues)

The Commission’s consideration of these issues is outlined in pages 6 and 7 of its authorisation determination.

During the authorisation process for the Code changes, the Commission received two submissions expressing concerns about ambiguities currently in the Code. The Commission noted the concerns but considered that it would be inappropriate to implement additional changes in advance of the extensive consultation with participants and others, in accordance with Code consultation procedures, on the development of more detailed methodology for the calculation of loss factors based on the draft report of RIEMNS. The Commission also considered that extending the operation of schedule 3.2 to the Code would allow sufficient time for those recommendations on the treatment of losses to be properly considered and the necessary Code changes to implement the outcomes of the review to be made.

18.4.3 Projected assessment of system adequacy

The Commission’s consideration of PASA issues is outlined in pages 10 and 11 of its authorisation determination.

The Commission considered that the Code changes would improve the overall operation of the existing PASA arrangements. However, the Commission noted NEMMCO’s concern with the transition to the new provisions. The Commission acknowledged that the benefits of the proposed changes might be reduced by any uncertainties surrounding the transition period. Therefore, the Commission considered that in order to facilitate a smooth transition, NEMMCO should be allowed until 31 December 2001 to implement the changes to PASA in the short-term normal market conditions.


18.4.4 Pricing under extreme conditions

The Commission’s consideration of the issues is outlined in pages 18 to 26 of its authorisation determination.

The Commission considered that preserving price signals in restriction periods creates public benefits by encouraging investment in peak generation and demand-side management. The Commission, however, acknowledged that the practical implementation of the provisions might result in adverse impacts on market participants. Based on these concerns it was appropriate to impose a condition of authorisation requiring NECA to undertake a review of the arrangements after a significant mandatory restriction event.

The Commission was also concerned that generators may receive windfall gains in circumstances where the restriction capacity contract market is uncompetitive. Therefore a cap was placed on the amount generators can receive from restriction capacity contracts made with NEMMCO.

Overall, the Commission considered the Code changes in relation to pricing under extreme conditions provide significant public benefits.

18.4.5 Demand side participation

The Commission’s consideration of the issues is outlined in pages 29 and 30 of its authorisation determination.

The Commission recognised that the proposed demand-side bidding framework removes some of the barriers to participation in the market and therefore may foster greater participation. The Commission considered that the removal of barriers to participate in the market would provide end-use customers with a choice and enhance overall public benefits. Nevertheless, it accepts that a change in the degree of demand-side participation is ultimately up to customers. Consequently, although the proposed Code changes may reduce the barriers to demand-side bidding, it was noted that it is unclear whether they will be sufficient to actually result in any additional demand-side participation.

18.4.6 End-user advocacy

The Commission’s consideration of the issues is outlined in pages 40 to 46 of its authorisation determination.

All interested parties supported the general thrust of the Code changes although they did take issue with particular features of the proposed arrangements. In particular, interested parties expressed concerns about the appointment, composition and accountability of the proposed Advocacy Panel. The Commission addressed some of these issues by seeking clarification from the applicant and suggested some amendments which related to:

NECA consulting with ‘representatives of end-users and industry sectors’ in appointing the chair;

the chairperson be given full voting rights;


the requirement for a co-payment be treated flexibly by the Advocacy Panel, that applicants can seek to waive this requirement and that non-financial contributions be considered; and

in developing guidelines for the appointment of representatives to the Panel, the chairperson have regard to benchmarks developed by the Department of Industry, Science and Resources in relation to dispute resolution panels.

The Commission considered that the Code changes met the objectives established by the Commission in its December 1999 determination and authorised the changes subject to conditions.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 19 September 2001 is relevant to this assessment. The Commission considers that NECA’s Access Code Applications satisfies s 44ZZAA(3) of the TPA in that the variations act to improve the operation of the Code and help facilitate informed decision making processes in the NEM. The Commission proposes to consent to NECA’s Access Code Application to vary the NEM Access Code by incorporating the inter-regional transfer of TUoS, treatment of losses, improvements to PASA, pricing under extreme conditions, demand side participation and end-user advocacy changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


19. Network Pricing and Market Network Service Providers

19.1 Introduction

On 26 July 1999, the Commission received applications for authorisation (Nos A90704, A90705, and A90706) of amendments to the Code. The proposed amendments related to the introduction MNSPs in the NEM.

The authorisation applications were amended on 18 August 1999, at which time NECA also sought authorisation of the network pricing code changes in accordance with its final report from its transmission and distribution pricing review.

The Commission granted interim authorisation to the MNSP provisions in chapters 2,3,4 and 7 of the Code on 6 October 1999 and to the MNSP provisions in chapters 5 and 6 of the Code on 25 January 2000. In response to concerns about the interpretation of conditions of authorisation contained in the 25 January 2000 interim authorisation the Commission revoked and regranted the interim authorisation on 23 February 2000.

The Commission authorised the Network Pricing and MNSP Code changes to the Code on 21 September 2001. The Code changes were gazetted by NECA on 6 December 2001.

On 10 May 2002, NECA submitted the Network Pricing and MNSP changes to the Code to the Commission to be incorporated as part of the Access Code.


19.2.1 Usage charges

A description of the application is outlined on page 6 of the Commission’s authorisation determination53. In general, the code provisions required TNSPs to calculate transmission charges using a combination of cost reflective network pricing (CRNP) and average pricing (postage stamping). NECA concluded that there are deficiencies in this approach and that it should be replaced with provisions that allow TNSPs to select a transmission use of system (TUOS) usage charge from a range of prices calculated using CRNP, utilisation adjusted CRNP and long run marginal cost (LRMC). NECA proposed that TUOS usage charges should only be levied on transmission customers. NECA also proposed that the residual costs should be recovered from a TUOS general charge, allocated to customers to minimise distortions.

19.2.2 General charge

A description of the application is outlined on page 35 of the Commission’s authorisation determination. In general, NECA’s code changes would result in the balance of regulated

53 ACCC, Amendments to the National Electricity Code: Network Pricing and Market Network Service

Providers, 21 September 2001.


TNSPs’ agreed revenue being recovered through TUOS general charges. General charges would be levied only on transmission customers and would be assessed on the basis of a uniform price applied to energy consumed during the year.

19.2.3 Common service charge

A description of the application is outlined on page 46 of the Commission’s authorisation determination. In general, a common service is one that cannot reasonably be allocated to network users on a locational basis. Under the existing arrangements, common service costs are recovered through an energy-based charge based on a rate that varies at each connection point according to the assessed utilisation of different networks. The proposed changes required the rate to be uniform for all connection points in a particular network.

19.2.4 Negotiation of price discounts

A description of the application is outlined on page 46 of the Commission’s authorisation determination. In brief, the code currently allows TNSPs to negotiate a discount to customers who would otherwise bypass the transmission network. NECA has proposed changes to these arrangements that allow TNSPs to recover the cost of discounted TUOS general charges from remaining transmission customers.

19.2.5 Financial transfers

A description of the application is outlined on page 58 of the Commission’s authorisation determination. In general, the code changes would extend the scope of financial transfers between TNSPs.

19.2.6 Distribution pricing

A description of the application is outlined on page 62 of the Commission’s authorisation determination. In general, NECA recommended that a nationally consistent approach to distribution pricing be implemented.

19.2.7 New investments – beneficiaries pay

A description of the application is outlined on page 67 of the Commission’s authorisation determination. In general, NECA’s review concluded that there is a mismatch between those who benefit from new investments and those who pay for those investments. NECA proposed code changes that required the beneficiaries of new investments to pay for those investments according to the proportion of benefits that they receive.

19.2.8 Service standards

A description of the application is outlined on page 87 of the Commission’s authorisation determination. In general, NECA’s code changes included provisions requiring NSPs to publish service standards. Appropriate service standards can provide a sound basis for ensuring that NSPs deliver cost-effective levels of service and do not abuse the market power arising from their monopoly position.


19.2.9 Negotiating framework

A description of the application is outlined on page 93 of the Commission’s authorisation determination. In general, NECA’s code changes required each NSP to establish a negotiating framework to apply to the agreement of levels of network services.

19.2.10 Information disclosure

A description of the application is outlined on page 108 of the Commission’s authorisation determination. In general, in order to improve information about the composition and structure of network charges, NECA proposed code changes that allow large customers to request unbundled transmission and distribution charges and for smaller end users to be able to access unbundled information on a customer class basis.

19.2.11 Embedded generation

A description of the application is outlined on page 112 of the Commission’s authorisation determination. In general, to provide locational signals to embedded generators, the proposed code changes required Distribution Network Service Providers (DNSPs) to pass through to embedded generators the full reduction in TUOS usage charges that arises from the generator being located within the distribution network.

19.2.12 Market network service providers

A description of the application is outlined on page 126 of the Commission’s authorisation determination. In general, NECA’s review developed a framework for the participation of MNSPs which earn their revenue from participating in the wholesale spot market rather than levying network charges. The code changes set out safe harbour provisions that allow a market network service to be automatically approved if it meets these criteria.


The Commission did not receive any submissions on the Access Code Application in relation to the Network Pricing and MNSP changes. The parties who provided submissions in response to the authorisation application are listed on pages 164 and 165 (Appendix A) of the Commissions authorisation determination.


19.4.1 Usage charges

A summary of the Commission’s consideration of the code changes is outlined in pages 24 to 35 of its authorisation determination.

By and large, the Commission considered the proposal to employ three alternative cost allocation methodologies for TUOS usage charges invited pricing inconsistencies and encouraged perceptions that TNSPs may apply their pricing discretion in a discriminatory


manner. The Commission therefore required the proposal for a discretionary price range to be deleted.

The Commission also required that standard CRNP be retained for the time being as the default technique, but that the utilisation-adjusted technique would be permitted where a benefit to the market can be demonstrated.

The Commission restored the option that allowed the price calculation to be applied over multiple regions.

The Commission also noted that it is important that usage prices take into account signals present elsewhere in the market so as to avoid duplication and that the existing arrangements provide for inter-regional residues to be deducted for the purposes of calculating usage prices. NECA’s changed arrangements removed that provision, increasing the risk of duplication of signals. The Commission recommended that the amendment be deleted.

The Commission noted that there is scope for improvement of the network pricing arrangements, and required NECA to further review the TUOS usage pricing regime. The Commission also noted that the need for economic signals to be provided through transmission usage charges would be diminished if energy market signals were not improved. It added that such improvements may include the introduction of more regions or full nodal pricing in the spot market and firmer and more extensive network-related rights in the forward markets. The Commission therefore required NECA to consider these possibilities in conjunction with its review of TUOS usage pricing.

19.4.2 General charge

A summary of the Commission’s consideration of the code changes is outlined in pages 40 to 46 of the determination.

The Commission raised concerns that customers’ behaviour may be influenced if the general charge is based on current energy consumption and has therefore made it a condition of authorisation that the TUOS general charges be levied according to customers’ energy consumption in the previous year rather than the current year. The Commission also recognised that an energy-based charge can be distortionary for customers with high load factors and therefore required that an alternative capacity-related charge be applied in those instances.

The Commission also considered that there is no benefit, and indeed may be significant detriment, for example to the structure of generation, the energy and ancillary markets, from applying the general charge to generators and MNSPs in addition to customers. The Commission therefore accepted NECA’s proposal that TUOS general charges continue to be levied on customers only.

19.4.3 Common service charge

A summary of the Commission’s consideration of the code changes is outlined in pages 46 of the determination.


The Commission considered it is appropriate for the common service charge to be structured similarly to the general charge. In both cases the primary aim should be to recover the required revenue with minimal distortion. The Commission endorsed NECA’s proposal to move to a uniform rate, but believes the distortionary impact is reduced if the rate is applied to historical energy consumption rather than present consumption, and if high load factor customers have access to an alternative capacity based charge. It therefore imposed a condition that required a method for the calculation of common service prices and charges that are required for TUOS general charges.

19.4.4 Negotiation of price discounts


The Commission considered that there are benefits in this approach as it can help minimise the distortionary impact of the general charges. On the other hand there is some risk of negative impacts for the customers who are required to absorb the cost of the discounts. The Commission required that discounts will have to be negotiated in accordance with an even-handed framework and meet guidelines promulgated by the Commission in order to be eligible for the costs to be recovered from other customers.

Further, the Commission believed that similar arrangements should apply to the recovery of common service charge discounts. The Commission also required the disclosure of information about discounts offered, so that the remaining customers can assess the impact of the TNSP policies.

19.4.5 Financial transfers


The Commission was not satisfied of the merit of NECA’s proposals, and argued that they may result in distortionary price steps at region boundaries. The Commission imposed a requirement on NECA to review the prospects for financial transfer arrangements that would support a market-wide user pays approach to the existing network and/or support uniform general charges across the market.

19.4.6 Distribution pricing


The Commission was concerned that a consistent approach to distribution pricing has yet to emerge. While the Commission acknowledged the work being undertaken by some of the jurisdictional regulators, it considers that there would be public benefits from a consistent approach to distribution pricing and for these arrangements to be within the code.


n of authorisation that the code be amended to require DNSPs, where metering installations allow this, to allocate TUOS charges to

to

The Commission accepted that NECA’s proposals had merit in principle but is concerned that their implementation is known. The Commission, while

endorsing the beneficiaries pay framework, imposed a condition delaying its introduction

, given the absence of adequate property rights and compensation arrangements in the code, it would be necessary to impose financial incentives

Commission’s consideration of the code changes is outlined in pages 97 to 102 of the determination.

ission required the negotiating framework to be extended to other situations in which matters have to be negotiated between network users and

The Commission therefore imposed a number of conditions that build on the concept of arges network charges. The Commission required that both

The Commission therefore imposed a conditio

distribution users in a way that preserves the economic signalling of the TUOS prices.

19.4.7 New investments – beneficiaries pay

A summary of the Commission’s consideration of the code changes is outlined in pages 7986 of the determination.

insufficient detail regarding

until further review by NECA.

19.4.8 Service standards


The Commission considered that

on TNSPs to ensure that they provide the required level of service.

19.4.9 Negotiating framework

A summary of the

Conditions imposed by the Comm

regulated NSPs.

19.4.10 Information disclosure

A summary of the Commission’s consideration of the code changes is outlined in pages 109to 116 of the determination.

The Commission considered that efficient network pricing arrangements require an effective information disclosure regime so that customers can assess the impact of their network use on their charges and make informed decisions about location and alternatives to network use.

unbundling TUOS and DUOS chTNSPs and DNSPs must, upon request, provide customers with information about the methodused to calculate network charges and to separately identify the components of the charges.

19.4.11 Embedded generation



compensating embedded generators for the benefits that they deliver to the network, in terms of avoided augmentation. The Commission

w

articipants. The Commission also supported ed interconnectors from converting to a market network regulated TNSPs may be able to leverage off their

existing transmission network to make windfall gains, at the expense of their transmission n

ss ted

de to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).

The Commission supported the principle of

therefore imposed conditions to ensure the provisions take into account the new arrangementsfor allocating network augmentation costs to beneficiaries.

19.4.12 Market network service providers

A summary of the Commission’s consideration of the code changes is outlined in pages 131-133, 136-140, 143-145 and 147-149 of the determination.

The Commission considered that there are public benefits from NECA’s proposal to alloMNSPs to operate in the NEM. It argued that MNSPs will provide a source of competitionfor generators in an importing region and facilitate inter-regional trading where the owner of the MNSP sells financial hedges to market pNECA’s proposal to restrict regulatservice. This is due to concerns that

connected customers. However, it accepted that there may be circumstances under which aMNSP can convert to a prescribed service.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of acceseekers. The Commission believes that, in relation to this chapter, the analysis it conducin its authorisation determination of 21 December 2002 is relevant to this assessment, in particular the public interest criterion. The Commission considers that NECA’s Access Codeapplications satisfies s 44ZZAA(3) of the TPA in that the variations to the Access Code facilitate the introduction of MNSPs and improve the network pricing arrangements in the NEM and are therefore in the public interest. The Commission proposes to consent to NECA’s Access Code Application to vary the NEM Access Code by incorporating the network pricing and MNSP changes that have been made to the Co


20. Queensland Technical Derogations

20.1 Introduction

On 24 October 2000, the Commission received applications for authorisation (Nos A90751, A90752 and A90753) of amendments to the Code. The proposed amendments were designed to facilitate the early commissioning of the Queensland-New South Wales Interconnector (QNI).

The Commission granted a conditional interim authorisation to amend the code on 6 December 2000.

The Commission authorised the Queensland technical derogation changes to the Code on 3 October 2001. The Code changes were gazetted by NECA on 25 October 2001.

On 10 May 2002, NECA submitted the Queensland technical derogation changes to the Code to the Commission to be incorporated as part of the Access Code.


A description of the application is outlined on page 4 of the Commission’s authorisation determination54. The changes to the Code clarified and made minor amendments to the Queensland derogations, which were granted authorisation on 19 October 1998, by clarifying the terminology contained in the derogations. Additional amendments extended the end dates of eight technical derogations, to 31 December 2002. These technical derogations were initially planned to cease at the earlier of interconnection of QNI or 31 December 2002. The derogation extensions were proposed to give those code participants affected by the earlier commissioning of the QNI time to complete the appropriate derogation processes to ensure compliance with the Code’s technical requirements.


The Commission did not receive any submissions on the Access Code Application in relation to the Queensland technical derogations. One party, Powerlink Queensland, provided a submission in response to the authorisation applications.


The Commission’s consideration of the issues is outlined in pages 7-8 of its authorisation determination.55 Generally, while the Commission accepted the applicant’s arguments that there would be public benefits from the early commissioning of QNI, it was concerned about the anti-competitive detriment of extending the duration of these derogations beyond the date of interconnection.

54 ACCC, Amendments to the National Electricity Code: Queensland Technical Derogations, 3 October 2001, p

4. 55 Ibid., pp 7-8.


The Commission was particularly concerned that extending Queensland’s stability requirements derogation beyond the interconnection date may have increased the potential for a stability event in Queensland to have an adverse impact on the other interconnected NEM regions. However, the Commission was satisfied that the extent of any anti-competitive detriment would be limited if the derogation was amended by assigning NEMMCO the role of independent adjudicator on these matters and the Commission imposed a condition to this effect.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conducted in its determination of 3 October 2001 is relevant to this assessment. The Commission considers that NECA’s Access Code Application satisfies s 44ZZAA(3) of the TPA in that the variations act to smooth the entry of Queensland into the NEM and assists the early commissioning of the QNI and are therefore in the public interest. The Commission proposes to consent to NECA’s Access Code Application to vary the NEM Access Code by incorporating the Queensland Technical Derogation changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sections of this authorisation incorporating amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


21. Averaging loss factors in distribution networks

21.1 Introduction

On 20 March 2001, the Commission received applications for authorisation (Nos A90783, A90784 and A90785) of amendments to the Code. The proposed amendments allow the averaging of loss factors in distribution networks.

The Commission authorised the averaging loss factors for distribution networks changes to the Code on 3 October 2001. The Code changes were gazetted by NECA on 1 November 2001.

On 10 May 2002, NECA submitted the above changes to the Code to the Commission to be incorporated as part of the Access Code.


A description of the application is outlined on pages 4 and 5 of the Commission’s determination56. The changes are briefly described below.

There are generally open points in the distribution networks that define areas supplied by each Transmission Connection Point (TCP). These open points generally are automatically or remotely controlled and thus readily altered. A change in any open point can result in a significant change in the area supplied by a TCP. The open points frequently change for operational purposes, during system maintenance and development, and on a seasonal basis to improve the utilisation of the network.

To ensure that price signals are passed through to distribution connection points (DCPs), and to allow local retailers’ wholesale market purchases to be settled on the basis of metering at TCPs, each DCP is required to be assigned to a TCP.

The amendments allow DNSPs to assign smaller contestable customers to non-physical TCPs using an averaged transmission loss factor (TLF). This replaced the existing obligation on DNSPs to assign all such customers to physical connection points. The code changes permitted the creation of a non-physical TCP or virtual transmission node (VTN) with an averaged TLF and DNSPs would be allowed to assign smaller contestable customers to these VTNs. These connection points would be used for market settlements and have a TLF equal to a volume weighted average of the TLFs at adjacent TCP locations.


The Commission did not receive any submissions on the Access Code Application in relation to the averaging loss factors Code changes. The parties who provided submissions in

56 ACCC, Amendments to the National Electricity Code: Averaging loss factors in distribution networks, 3

October 2001, pp 4-5.


re the Energy Markets Reform Institute and EnergyAustralia.

n rations of the spot market, or distort economic signals to any greater degree than the

system that was in place. Furthermore, the Commission understood that the proposal was a

The Commission considered that the level of complexity involved in the Code changes was

The Commission believed that there is a public benefit in reduced administration costs and

The Commission noted concerns regarding public scrutiny of the VTN calculation process s

flowing to these DCPs to be accounted for in market settlements. e aggregate adjusted gross energy for DCPs assigned to calculating adjusted gross energy for TCPs, and imposed

conditions to this effect.

e

d

e

ons of the Code are not included in

the NEM Access Code (unless (a) such sections were necessary or incidental to the operation

response to the authorisation application we


The Commission’s consideration of the issues is outlined in pages 8 and 9 of its authorisationdetermination.57 Generally, the Commission considered that the averaging of TLFs in distribution networks for smaller urban customers was unlikely to have a material impact othe ope

pragmatic approach to the problems identified, and would not generally be used in remote areas.

not significantly greater than the current system and would not increase potential barriers toentry for new participants or barriers to direct trading for end use customers.

certainty in the arrangements for averaging losses between TCPs while the alternative of assigning every DCP and a TCP is complex and does not increase the benefit to end-users.

and therefore imposed a condition that required NEMMCO to calculate and publish the TLFand methodology that applies to VTNs.

While the Code change proposal did not require DCPs to be assigned to specific TCPs, the Code required the energyThe Commission considered that thVTNs must be accounted for when


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, thlegitimate business interests of service providers, the public interest and the interest of access seekers. The Commission believes that, in relation to this chapter, the analysis it conductein its determination of 3 October 2001 is relevant to this assessment. The Commission considers that NECA’s Access Code Application satisfies s44ZZAA(3) of the TPA in that thchanges facilitate compliance by DNSPs (especially as contestability progresses) and are therefore in the public interest. The Commission proposes to consent to NECA’s Access Code Application to vary the NEM Access code to incorporate the averaging loss factors in distribution networks changes that have been made to the Code to the extent that they have not been amended by subsequent authorisations. The Commission notes that those sectiof this authorisation incorporating amendments to Chapter 3

57 Ibid., pp 8-9.


ECA applies under s of the other Chapters that form the NEM Access Code; and (b) N44ZZAA(6) to vary the NEM Access Code to this effect).


ork augmentations.

resources changes to the Code on 13 February 2002. The Code changes were gazetted by NECA on 8 March 2002.

to the

22.2.1 Institutional roles and procedures

The network and distributed resources changes are outlined on pages 4 and 5 of the Commission’s authorisation determination58.

The am espective roles and responsibilities of NSPs, the IRPC, NEMMCO and the Commission in relation to the planning and approval of new transmission

NEMMCO and transferred to TNSPs;

ade

augmentations, replacing the inter-regional and intra-regional distinction with a distinction between small network assets

y of information to market participants on emerging network constraints and planned new network investments by requiring TNSPs to publish an Annual Planning Report, identifying emerging network constraints and breaches

22. Network and distributed resources

22.1 Introduction

On 21 December 2000, the Commission received applications for authorisation (Nos 90773, A90774 and A90775) of amendments to the Code. The proposed amendments relate to planning and approval provisions for new transmission netw

The Commission authorised the network and distributed

On 10 May 2002, NECA submitted the Network and Distributed Resources changesCode to the Commission to be incorporated as part of the Access Code.

22.2 The application

endments alter the r

network investments. Among the amendments to the roles of the stated bodies are:

the removal of responsibility for the regulatory test assessment for interconnectors from

restricting the role of the IRPC to matters of technical assessment;

providing the Commission with a role in reviewing the regulatory test assessment mby TNSPs where the regulatory test has been disputed by interested parties.

Further, the Code changes alter the classification of

(a capital cost greater than $1 million but less than $10 million) and large network assets (a capital cost greater than or equal to $10 million, or as otherwise set by the Commission).

22.2.2 Framework for regulated new investments

The changes seek to improve the availabilit

of technical standards, and details of proposed augmentations.

58 ACCC, Amendments to the National Electricity Code: Network and Distributed Resources, 13 February

2002.


rocesses for the consideration of large and small network assets. For a large network asset a TNSP is required to publish an application to

The IRPC is also required to publish an Annual Interconnector Review in the Statement of d

The Code changes seek to ensure adequate consultation and dispute resolution opportunities est

dete rge network assets. The consultation and dispute resolution procedures provide interested parties with the opportunity to dispute the contents, findings or

possible network alternatives considered and their ranking;

twork impact; and

the regulatory test;

t it is

e changes. The parties who provided

submissions in response to the authorisation applications are listed at page 65 (Appendix A)

Further, the requirements set out different p

establish a new large network investment, which must include the assessment of reasonable alternatives and results of the application of the regulatory test.

Opportunities outlining the technical and economic need for inter-regional augmentations anthe impact of augmentations on inter-regional transfer capabilities.

22.2.3 Consultation and dispute resolution processes

are available to interested parties who are dissatisfied with a TNSPs regulatory trmination for proposed new la

recommendations of the final report with respect to:

whether or not the new large network asset will have a material inter-ne

the basis on which the applicant has assessed that a new large network asset satisfiesthe regulatory test.

If a dispute is raised in relation to the final report and is not resolved between the parties then a Dispute Resolution Panel (DRP) is established to determine any factual issue referred to it, but can not determine whether the new large network asset satisfies

Further, if after the TNSP amends the final report to include the findings of the DRP, codeparticipants and interested parties are still dissatisfied, they may dispute the finding in the final report that the new large network asset satisfies the regulatory test, provided thanot a reliability augmentation. Where a dispute is raised the Commission must make a determination as to whether or not the new large network asset satisfies the regulatory test.


The Commission did not receive any submissions on the Access Code application in relationto the network and distributed resources cod

of the Commission’s authorisation determination.


The Commission’s consideration of the issues is outlined in chapters 2, 3 and 4 of the Commission’s authorisation determination.


edures

In general, the Commission considered that the proposed Code changes would lead to public

ments by devolving the regulatory test assessment to TNSPs; and

sufficient checks and balances through consultation and dispute resolution procedures to ensure TNSPs are held accountable for new network investment decisions.

The Commission did not support arguments from Code participants that the review of the TNSPs regulatory test determination by the Commission would add no value and delay the approval process for new network investments. The Commission considered that its proposed role would add value in terms of holding TNSPs accountable for regulatory test determinations. The Commission, however, questioned the benefits of permitting TNSPs to voluntarily apply to the Commission for regulatory test approval. The Commission therefore imposed a condition of authorisation requiring this provision be deleted.

NEMMCO raised concerns regarding deletion of clause 5.6.6(c) that required the IRPC to undertake the regulatory test assessment based on the premise that all transmission systems were to be planned and operated as if they formed a single transmission system. The Commission agreed that under the proposed Code changes TNSPs would not be explicitly required to take a network-wide perspective when considering investment alternatives. The Commission considered that the TNSP could take advantage of this omission by discriminating against projects in other networks when undertaking the regulatory test assessment. The Commission therefore imposed a condition of authorisation to ensure TNSPs consider interconnectors or options involving other transmission and distribution networks when proposing a new large network asset.

22.4.2 Consultation and dispute resolution processes

The Commission considered that the dispute resolution arrangements, greater information disclosure requirements and more explicit consultation procedures for all network augmentations would overcome concerns from market participants that TNSPs may misuse their monopoly position in the planning process to the detriment of other market participants.

The Commission imposed several other conditions of authorisation. The conditions of authorisation are listed in chapter 6 of the determination.

22.4.1 Institutional roles and proc

benefits by improving the network planning and development arrangements in the Code byproviding a clearer and more streamlined framework within which new investment can occur.

The Commission considered that it was appropriate for TNSPs to have more responsibility for planning and augmentation of networks as they are accountable for network performance levels. In particular, the Commission considered that public benefits would arise from:

improved information disclosure regarding emerging network constraints and proposednew network investment;

improved information availability to the market regarding opportunities for interconnector development;

streamlined approval processes for new network invest


nsidered the matters in s44ZZAA(3) of the TPA, in particular, the rests of service providers, the public interest and the interest of access

seekers. The Commission believes that, in relation to this chapter, the analysis it conducted ommission

ry framework for new network investment in the NEM

and is therefore in the public interest. The Commission proposes to consent to NECA’s

s that have been made to the Code to the extent that they have notes that those sections Code are not included in

eration ccess Code; and (b) NECA applies under s

44ZZAA(6) to vary the NEM Access Code to this effect).


The Commission has colegitimate business inte

in its determination of 21 December 2002 is relevant to this assessment. The Cconsiders that NECA’s Access Code application satisfies s 44ZZAA(3) of the TPA in that thevariations act to improve the regulato

Access Code application to vary the NEM Access Code by incorporating the network and distributed resources changenot been amended by subsequent authorisations. The Commissionof this authorisation incorporating amendments to Chapter 3 of thethe NEM Access Code (unless (a) such sections were necessary or incidental to the opof the other Chapters that form the NEM A


te to rangements.

The Code changes were gazetted by NECA on 21 February 2002.

On 10 May 2002, NECA submitted the changes to the Code to the Commission to be

et e

h

ty deposit fund for prudential requirements;

allowing market participants to lodge cash as a security deposit; and

spelling out the rights and obligations of participants and NEMMCO with regard to the new arrangements.


The Commission did not receive any submissions on either the Access Code Application in relation to prudential arrangements changes or the authorisation application.


The Commission’s consideration of the issues is outlined on page 8 of its authorisation determination.60 Generally, in its determination of 10 December 1997, the Commission

23. Prudential Arrangements: Security Deposits

23.1 Introduction

On 22 October 2001, the Commission received applications for authorisation (Nos A90805, A90806 and A90807) of amendments to the Code. The amendments relathe Code’s prudential ar

The Commission authorised the Prudential Arrangements: Security Deposits changes to the Code on 6 February 2002.

incorporated as part of the Access Code.


A description of the application is outlined on pages 5 to 7 of the Commission’s authorisation determination59. Briefly, the code’s prudential requirements are set out in clause 3.3 of the code. Entrants to the NEM are admitted in the category of code participant if NEMMCO is reasonably satisfied that, in applying for registration in one of the categories of markparticipant, an applicant is and will be able to fulfil its financial obligations. NECA’s Codchanges were intended to provide a low-cost alternative to bank guarantees to allow market participants to meet their prudential obligations, especially during short-term periods of higprices, without compromising the objective of full coverage of settlement liabilities. Thiswould be done by:

formalising the existence of a securi

59 ACCC, Amendments to the National Electricity Code: Prudential Arrangements: Security Deposits, pp 5-7. 60 Ibid., p 8.


rticipants. es

obliged to extend their bank guarantees, which could be a costly exercise and therefore be entry to the NEM, especially for small participants. The

Commission considered that providing participants with an alternative to extending their ompetition in the

arket participants, the Code changes provided the benefit of increased certainty regarding rights


of the TPA, in particular, the iders, the public interest and the interest of access relation to this chapter, the analysis it conducted

in its determination of 6 February 2002 is relevant to this assessment. The Commission in that the

in

ts been amended by

subsequent authorisations. The Commission notes that those sections of this authorisation are not included in the NEM Access

Code (unless (a) such sections were necessary or incidental to the operation of the other

noted that the prudential arrangements might represent a barrier to entry to some paUnder the previous Code prudential requirements, market participants were sometim

perceived as a barrier to

bank guarantees, such as lodging cash as a security deposit, might enhance cmarket. Thus, the Commission considered that the proposed changes would reduce the costs of meeting the Code’s prudential requirements, and as such would help encourage new entrants into the NEM.

Further, in formalising a set of arrangements that were already proven acceptable to m

and obligations to all market participants.

The Commission has considered the matters in s44ZZAA(3) legitimate business interests of service provseekers. The Commission believes that, in

considers that NECA’s Access Code application satisfies s 44ZZAA(3) of the TPAvariations to the NEM Access Code will provide a greater degree of certainty for all marketparticipants, as well as reduce potential barriers to entry into the NEM, and are thereforethe public interest. The Commission proposes to consent to NECA’s Access Code Application to vary the NEM Access Code by incorporating the prudential arrangemenchanges that have been made to the Code to the extent that they have not

incorporating amendments to Chapter 3 of the Code

Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


(Nos A90786, A90787 and A90788) of amendments to the derogations contained in chapter 9 y

t. The

e

erogations to the Code to the Commission to be incorporated as part of the Access Code.


isation applications are listed at page 14 (Appendix A) of the Commission’s authorisation determination.


The Commission’s considerations of the issues are outlined in pages 10-12 of its authorisation determination.62 Generally, the Commission considered that it was important to establish an operating environment that is conducive to customer churn, in order for the full benefits of FRC to be realised in Victoria. The Commission agreed with the EPD’s view that allowing LNSPs to have temporary exclusivity in meter provision would simplify the process for customers who choose to switch electricity retailers, and would minimise disruption to the metering data systems.

24. Victorian Full Retail Competition Derogations

24.1 Introduction

On 19 March 2001, the Commission received applications for authorisation

of the Code. The applications were submitted by NECA on behalf of the Energy PolicDivision (EPD) of the Victorian Department of Natural Resources and Environmenamendments related to the metering arrangements of chapter 7 of the code, in conjunction with the introduction of FRC in Victoria.

The Commission authorised the Victorian FRC derogations on 8 August 2001. The Codchanges were gazetted by NECA on 6 September 2001.

On 10 May 2002, NECA submitted the Victorian FRC d

A description of the application is outlined on pages 5 and 6 of the Commission’s determination.61 However, in brief, the Victorian FRC derogations to the Code introduced transitional arrangements for metering services in the wholesale electricity market; andprovided the Local Network Service Providers (LNSPs) with a monopoly for the provision of metering services for a period of three years from the commencement of the Victorian metrology procedures for type 6 metering installations (profile meters).


The Commission did not receive any submissions in response to the Access Code application in relation to the Victorian FRC Code changes. The parties who provided submissions in response to the author

61 ACCC, Amendments to the National Electricity Code: Victorian Full Retail Competition Derogations, 8

August 2001, pp. 7-8. 62 Ibid, p. 10-12.


t hip of meters d that the cost

savi er electricity prices, through more accurate metering, might be outweighed by the cost of installing a new meter. Therefore, the Commission determined

s to retain exclusive ownership of meters, the derogations would efit by facilitating a smooth transition to FRC in Victoria.

, that includes consideration of whether meter ownership acts as a barrier to customer switching. Therefore, the Commission

ject to the condition that clause re

cess ed

onsent to NECA’s Access Code application to vary n FRC derogation changes that have ot been amended by subsequent

authorisations. The Commission notes that those sections of this authorisation incorporating

hapters that form the under s 44ZZAA(6) to vary the NEM Access

Interes ed parties argued that allowing the LNSP to retain exclusive ownerswould be a barrier to competition. However, the Commission was concerne

ngs derived from low

that by allowing LNSPdeliver a net public ben

The Commission also considered that it was inappropriate for it to determine whether metering contestability was required at that stage. The Commission noted that its determination on the FRC code changes imposed a condition that requires the jurisdictional regulators to conduct a review, by 31 December 2003

considered that it was appropriate to grant authorisation to the derogations pending the outcome of that review. The derogation was authorised sub9.9A.2(e) of the derogation must end on 1 July 2004 to allow the jurisdictions time to prepafor any changes arising from the jurisdictional review.


The Commission has considered the matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of acseekers. The Commission believes that, in relation to this chapter, the analysis it conductin its determination of 8 August 2001 is relevant to this assessment. The Commission considers that NECA’s Access Code application satisfies s 44ZZAA(3) of the TPA in that the application will facilitate the transition to FRC in Victoria, and is therefore in the public interest. The Commission proposes to cthe NEM Access Code by incorporating the Victoriabeen made to the Code to the extent that they have n

amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other CNEM Access Code; and (b) NECA appliesCode to this effect).


ion ever, in brief, the New South Wales FRC derogations to the Code

troduced transitional arrangements for metering services in the wholesale electricity market; and provided the LNSPs with a monopoly for the provision of metering services for a period of three years from the commencement of the NSW metrology procedures for type 6 metering installations (profile meters).


The Commission did not receive any submissions on either the Access Code Application in relation to the NSW FRC derogations or the authorisation application.


The Commission’s consideration of the issues is outlined in pages 7 and 8 of its authorisation determination. Generally, the Commission considered that it is important to have in place an operating environment that is conducive to customers being able to decide their retailer of choice for the full benefits of FRC to be realised. The Commission agreed with the MEU’s view that allowing LNSPs to have temporary exclusivity in meter provision would simplify the process for customers who choose to switch retailers, and will minimise disruption to the metering data systems. In addition, given the infancy of retail contestability, the Commission considered it inappropriate for it to determine whether metering contestability was required at that stage. In its determination on the FRC code changes, the Commission imposed a condition that

25. New South Wales Full Retail Competition Derogations

25.1 Introduction

On 5 October 2001, the Commission received applications for authorisation (Nos A90801, A90802, A90803) of amendments to the Code. NECA submitted the applications on behalf of the New South Wales Ministry of Energy and Utilities (MEU). The derogations relate to the metering arrangements of chapter 7 of the code.

The Commission authorised the New South Wales FRC derogations on 23 January 2002. The Code changes were gazetted by NECA on 7 March 2002.

On 10 May 2002, NECA submitted the New South Wales FRC derogation amendments to the Code to the Commission to be incorporated as part of the Access Code.


A description of the application is outlined on pages 4 to 6 of the Commission’s authorisatdetermination63. Howin

63 ACCC, Amendments to the National Electricity Code: New South Wales Full Retail Competition

Derogations, 23 January 2002, p5 & 6.


1 December 2003, that includes customer switching. Therefore,

the Commission considered it appropriate to grant authorisation to the derogations pending ew of meter ownership.

A, in particular, the legitimate business interests of service providers, the public interest and the interest of access

ted mission

considers that NECA’s Access Code application satisfies s 44ZZAA(3) of the TPA in that the

ccess Code application to vary NSW FRC derogation changes that have been e not been amended by subsequent

authorisations. The Commission notes that those sections of this authorisation incorporating

he

requires the jurisdictional regulators to conduct a review, by 3consideration of whether meter ownership acts as a barrier to

the outcome of the revi


The Commission has considered the matters in s44ZZAA(3) of the TP

seekers. The Commission believes that, in relation to this chapter, the analysis it conducin its determination of 23 January 2002 is relevant to this assessment. The Com

application will facilitate the transition to FRC in NSW, and is therefore in the public interest. The Commission proposes to consent to NECA’s Athe NEM Access Code by incorporating themade to the Code to the extent that they hav

amendments to Chapter 3 of the Code are not included in the NEM Access Code (unless (a) such sections were necessary or incidental to the operation of the other Chapters that form tNEM Access Code; and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).


eceived applications for authorisation of amendments to chapter 8.2 of the Code. The

amendments include changes to the dispute resolution arrangements.

’s

ng ore in line with common law provisions as well

as changing the Code to deal with the timing and cost of disputes.


The Commission did not receive any submissions on the Access Code Application in relation to the dispute resolution arrangements. The parties who provided submissions in response to the authorisation applications were TransGrid, EnerTrade, NECA, Hazelwood Power and Ergon Energy.


The Commission’s consideration of the issues is outlined in pages 13 to 23 of its authorisation determination. Overall, the Commission considered that public benefits may arise through reduced costs, improved cost allocation and reduced time spent resolving disputes as a result of the proposed dispute resolution arrangements. In particular, it concluded that the clarifications gave participants a better understanding of their roles, rights and requirements within the Code dispute resolution arrangements and may enable participants to resolve disputes in the shortest possible time, without costly interruption to the operation of the participant’s business. Further, it was argued that those arrangements may reduce the need for legal advice and representation in the event of a dispute.

The Commission however considered that a smooth transition from the old Code arrangements to the new Code arrangements was required and imposed conditions that

26. Dispute resolution arrangements

26.1 Introduction

On 26 July 2001, the Commission r(Nos A90792, A90793 & A90794)

The Commission authorised the dispute resolution arrangement changes to the Code on 13 March 2002. The Code changes were gazetted by NECA on 11 April 2002.

On 10 May 2002, NECA submitted the new Code dispute resolution arrangements to the Commission to be incorporated as part of the Access Code.


A description of the authorisation application is outlined on pages 5 to 8 of the Commissionauthorisation determination64. In summary, under the Code NECA was required to reviewthe dispute resolution arrangements. NECA completed its review and proposed amendments to the Code providing the opportunity for parties to come to consensual resolution, amendithe confidentiality provisions to bring them m

64 ACCC, Amendments to the National Electricity Code: Dispute resolution arrangements, 13 March 2002, p5-

8.


mposed another condition to ensure the DRP power to make a determination was not limited.

e matters in s44ZZAA(3) of the TPA, in particular, the legitimate business interests of service providers, the public interest and the interest of access

in its authorisation determination of 13 March 2002 is relevant to this assessment. The

te improved resolution of code disputes and are, therefore, in the public interest. The Commission proposes to consent to NECA’s

he extent that they have not been amended by n notes that those sections of this authorisation he Code are not included in the NEM Access

Code (unless (a) such sections were necessary or incidental to the operation of the other

ensured that disputes that remained unresolved at the time of transition were not disadvantaged by the changes.

The Commission also i


The Commission has considered th

seekers. The Commission believes that, in relation to this chapter, the analysis it conducted

Commission considers that NECA’s access code application satisfies s 44ZZAA(3) of the TPA in that the variations to the access code facilita

access code application to vary the access code by incorporating the dispute resolution changes that have been made to the Code to tsubsequent authorisations. The Commissioincorporating amendments to Chapter 3 of t

Chapters that form the NEM Access Code; and (b) NECA applies under s 44ZZAA(6) tovary the NEM Access Code to this effect).


nts to the Code. The amendments facilitate ciated

The Commission granted interim authorisation to the amendments on 19 December 2001.

O he

recovery of the associated participant fees until 1 July 2003.

In addition, the Code changes relate to the implementation of arrangements governing the covery of fees for future major projects declared by NEMMCO. The amendments also

cover changes relating to the FRC code changes gazetted on 20 August 2001.


The Commission did not receive any submissions on the Access Code Application in relation to the FRC MkII changes. The parties who provided submissions in response to the authorisation applications are listed at page 13 (Appendix A) of the Commission’s authorisation determination.


In its authorisation determination, the Commission concluded that the determination of participant fees and cost recovery for future declared projects would provide benefits to all customers by ensuring that the associated costs of FRC are borne evenly amongst all customers in the NEM. The deferral of the cost recovery period until 1 July 2003, when it is more probable that FRC will have been adopted in Queensland and South Australia, will

27. Full Retail Competition Mk II

27.1 Introduction

On 10 December 2001, the Commission received applications for authorisation (Nos A90813, A90814 and A90815) of amendmethe introduction of FRC by allowing for the delay of the recovery of the assoparticipant fees until 1 July 2003.

The Commission authorised the FRC Mk II changes to the Code on 8 May 2002. The Code changes were gazetted by NECA on 16 May 2002

On 10 May 2002, NECA submitted the FRC Mk II changes to the Code to the Commission to be incorporated as part of the Access Code.


A description of the application is outlined on page 6 of the Commission’s authorisation determination65. However, in brief, the FRC Mk II changes to the Code related to NEMMCO’s participant fee determination to introduce a new element of fees to cover the capital and future operating costs of the new and enhanced systems developed by NEMMCto facilitate the introduction of FRC. The amendments also allow for the delay of t

re

65 ACCC, Amendments to the National Electricity Code: Full Retail Competition Mk II, 8 May 2002 p 5.


i llection of market fees for FRC will result in a more equitable recovery of the associated costs.

Interested parties raised concerns about not being able to review NEMMCO’s participant fee ided


particular, the legitimate business interests of service providers, the public interest and the interest of access

d , in particular the

public interest criterion. The Commission considers that NECA’s access code application

s changes into the Code to

the extent that they have not been amended by subsequent authorisations. The Commission not th the Code are not included in the NEM Access Code (unless (a) such sections were necessary or inciden and (b) NECA applies under s 44ZZAA(6) to vary the NEM Access Code to this effect).

ensure that the costs to consumers coincides with the resultant benefits of FRC. The Comm ssion considered that the deferral of co

determination. The Commission considered that the dispute resolution procedures provparticipants with a number of simple and cost-effective methods of resolving disputes, including participant fee determination disputes.

The Commission’s consideration of the issues is outlined in pages 8 and 9.

The Commission has considered the matters in s44ZZAA(3) of the TPA, in

seekers. The Commission believes that, in relation to this chapter, the analysis it conductein its authorisation determination of 8 May 2002 is relevant in its assessment

satisfies s 44ZZAA(3) of the TPA in that the variations to the access code facilitate the smooth transfer to FRC and ensure equitable recovery of the associated costs and are therefore in the public interest. The Commission, therefore, proposes to accept NECA’application for the purposes of the Access Code incorporating these

es at those sections of this authorisation incorporating amendments to Chapter 3 of

tal to the operation of the other Chapters that form the NEM Access Code;


28

28.1 Summary of Reasoning

On 16 under s 44ZZAA of the TPA, accepted as an industry access code Chapters 1, 2, 4, 5, 6, 7, 8, 9 and 10 of version 2.3 of the Code. On 5 No eapplication, under s 44ZZAA(6) of the TPA, to vary the NEM Access Code. The Comm ry 1999.

Since that time there have been a number of Code changes which have been authorised by the Co the Code which EM Access Code or affect the NEM Access Code.

As e to vary

The Co onsidered the matters in s44ZZAA(3) of the TPA in particular, the legitimate business interests of service providers, the public interest and the interest of access seekers and, in accordance with s44ZZAA(6) of the TPA proposes to consent to these variations of the NEM access code on the basis that the variations:

m security

interconnectors and network augmentation and derogation for deferral of

ability of market participants to manage the risks associated with inter-regional trade as well as facilitate increased competition in the NEM (Settlement

facilitate a fully competitive market in South Australia (South Australian

he more efficient operation of the NEM by lowering potential barriers to entry, improving reliability, and reducing risk and uncertainty (Trading limits;

stimates and intra-regional loss factors)

refine the Code in order to increase the efficiency of the NEM (Third tranche

will facilitate compliance with the new tax system and support the ongoing

facilitate the efficient allocation of resources through improved price signalling in

. Commission’s decision

September 1998, the Commission,

v mber 1998, the National Electricity Code Administrator (NECA) lodged an

ission consented to the application on 20 Janua

mmission under Part VII of the TPA. Those changes also vary components ofcomprise the N

a r sult, on 10 May 2002, the Commission received a further application from NECA the NEM Access Code, which includes Chapter 3 for the first time.

mmission has c

facilitate least cost network expansion, and also ensure that the systecompensation function is operated efficiently (Regulatory test for new

compensation) increase the

residue auctions)

Derogations)

facilitate t

Funding of compensation for system security directions; Settlements by e

amendments)

orderly conduct of the NEM (Introduction of the GST)

NSW (NSW transmission network service pricing derogation)


onsideration of technical issues associated with Basslink before Tasmanian participants join the NEM and the Code changes allow this potential barrier to

sues)

mechanisms and removal of zero price floor)

services (Ancillary services)

facilitate competition in the retail market (FRC and registration of code participants)

improve the operation of the Code and help facilitate informed decision making processes (End-user advocacy; inter-regional transfer of TUoS; treatment of losses; improvements to PASA; pricing under extreme conditions; demand-side participation)

facilitate the introduction of MNSPs and improve the network pricing arrangements in the NEM (Network Pricing and MNSPs)

smooth the entry of Queensland into the NEM and assists the early commissioning of the QNI (Extension of Queensland technical derogations)

facilitate compliance by DNSPs (Averaging of loss factors in distribution networks)

improve the regulatory framework for new network investment in the NEM (Network and Distributed Resources)

provide a greater degree of certainty for all market participants, as well as reduce potential barriers to entry into the NEM (Prudential arrangements: security deposits)

facilitate the transition to FRC in Victoria (Victorian FRC derogations)

facilitate the transition to FRC in NSW (NSW FRC derogations)

facilitate improved resolution of code disputes (Dispute resolution arrangements) and

facilitate the smooth transfer to FRC and ensure equitable recovery of the associated costs (FRC)

The Commission does not, however, consider that the entire Chapter 3 should be included in the NEM Access Code.

facilitate c

Tasmania’s NEM entry to be handled in a timely manner (Basslink technical is

assist the NEM to operate more efficiently and transparently (Rebidding and revision of settlement statements)

enhance the operation of the NEM through improvements in price signals and capacity mechanisms (VoLL scaling; implementation of VoLL, capacity

enable a more efficient provision of ancillary


the TPA, the Commission consents to the application by NECA dated 10 May 2002 to vary the NEM Access Code except to the extent that the

proposes to include Chapter 3 in the NEM Access Code. However, where deemed appropriate, the Commission may consent to an application by NECA to vary the

EM Access Code to include such provisions in Chapter 3 as, from time to time, are necessary or incidental to the operation of the other Chapters that form the NEM Access Code.

This decision takes effect from the date it is made.

28.2 Decision

Pursuant to s 44ZZAA(6) of

application

N


Appendix A Submissions

National Generators Forum

TransGrid

Documents

Variation to the National Electricity Market Access Code · which comprise the NEM Access Code or affect the NEM Access Code. On 5 November 1998, the National Electricity Code Administrator