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Capacity Trading Reform Package (Standardisation, capacity trading platform and reporting framework for secondary trades)

Final Recommendations

November 2017

ContentsAbbreviations

1. Introduction and Summary

1.1 Progression of the capacity trading reform package

1.2 Consultation on the capacity trading reform package

1.3 Final recommendations

1.4 How the capacity trading reform package will operate

1.5 Next steps

1.6 Structure of report

2. Overview of the Capacity Trading Reform Package

2.1 Key elements of the reform package

2.2 How secondary capacity can be procured under the new framework

3. Assessment Framework

Part A: Standardisation Reforms

4. Standardisation of Contracts

4.1 AEMC recommendations

4.2 Contracts to be standardised

4.3 Standardisation of the operational GTA

4.4 Application of the standardised operational GTA

4.5 Cost recovery for provision of operational transfer services

4.6 Governance arrangements for the operational GTA

5. Other Measures to Reduce Barriers to Trade

5.1 Allocation agreements and access to receipt/delivery points

5.2 Contractual limitations on capacity trading in primary GTAs

5.3 Gas day start times and nomination cut-off times

Part B: Capacity Trading Platform

6. Initial Set of Capacity Products

6.1 Initial set of products to be sold on the exchange

6.2 Maximising the pool of prospective buyers and sellers

6.3 Standardised products to be sold on the exchange

6.4 Charging parameters for capacity products

7. Delivery Process for Exchange Traded Products

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7.1 Provision of transaction information to service providers

7.2 Transfer of capacity

7.3 Key timings on the capacity trading platform

7.4 Interaction between the delivery process and other markets

8. Settlement and Credit Risk Management

8.1 Centralised settlement system

8.2 Centralised credit risk management

9. Financial and Delivery Default Arrangements

9.1 Seller defaults on its GTA with the service provider

9.2 Seller short-sells capacity

9.3 Seller defaults on financial obligations in the GSH

10. Capacity Listing Service and Bilateral Trading

11. Governance Arrangements for the Capacity Trading Platform

Part C: Reporting Framework for Secondary Trades

12. Reporting Requirements for Secondary Trades

12.1 Types of trades to be reported

12.2 Information to be reported

12.3 Reporting obligations

12.4 Where the information should be published

12.5 Advertising trades in advance

13. Governance Arrangements for the Reporting Framework for Secondary Trades

The views and opinions expressed in this publication are those of the GMRG.

While reasonable efforts have been made to ensure that the contents of this publication are factually correct, the GMRG and its advisor, Johnson Winter & Slattery, do not accept responsibility for the accuracy or completeness of the contents, and shall not be liable for any loss or damage that may be occasioned directly or indirectly through the use of, or reliance on, the contents of this publication.

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AbbreviationsTerm Definition

AA Access Arrangement

ACCC Australian Competition and Consumer Commission

ADP Amadeus to Darwin Pipeline

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

AEST Australian Eastern Standard Time

BB Natural Gas Services Bulletin Board

CGP Carpentaria Gas Pipeline

COAG Council of Australian Governments

CTA Capacity Trading Agreement (for shipper to shipper sales of capacity)

DTS Declared Transmission System

DWGM Declared Wholesale Gas Market

East Coast Review AEMC’s Eastern Australian Wholesale Gas Market and Pipelines Framework Review (May 2016)

EGP Eastern Gas Pipeline

Energy Council COAG Energy Council

ERA Economic Regulation Authority (WA)

ETS Trayport Exchange Trading System

FTP File Transfer Protocol

GMRG Gas Market Reform Group

GSH Gas Supply Hub

GTA Gas Transportation Agreement

HPTP High Pressure Trade Point)

JWS Johnson, Winter & Slattery

LPTP Low Pressure Trade Point)

MAPS Moomba to Adelaide Pipeline System

MCF Moomba Compression Facility

MDQ Maximum Daily Quantity

MHQ Maximum Hourly Quantity

MOS Market Operator Service

MSP Moomba to Sydney Pipeline

MSV Market Schedule Variation

NEM National Energy Market

NER National Electricity Rules

NGL National Gas Law

NGO National Gas Objective

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Term Definition

NGP Northern Gas Pipeline

NGR National Gas Rules

RBP Roma to Brisbane Pipeline

SCO Senior Committee of Officials

SIP STTM Interface Protocol

SRA Settlement Residue Auction

STTM Short Term Trading Market

SWQP South West Queensland Pipeline

TGP Tasmanian Gas Pipeline

Transportation services This term is used to jointly refer to pipeline and compression services

Vision COAG Energy Council’s Australian Gas Market Vision (December 2014)

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1. Introduction and SummaryThe Gas Market Reform Group (GMRG) was established by the COAG Energy Council (Energy Council) in the latter half of 2016 to lead the design, development and implementation of a range of reforms set out in the Gas Market Reform Package, including a package of capacity trading reforms.1

The capacity trading reform package was recommended by the Australian Energy Market Commission (AEMC) as part of its Eastern Australian Wholesale Gas Market and Pipelines Framework Review (East Coast Review) (see Appendix A for further detail) and endorsed by the Energy Council at its August 2016 meeting. The reforms, which relate to transmission pipeline and compression services (jointly referred to as ‘transportation services’), include the development of:§ a capacity trading platform(s) that shippers can use to trade secondary capacity ahead

of the nomination cut-off time and provides for exchange-based trading of commonly traded products and a listing service for other more bespoke products;

§ a day-ahead auction of contracted but un-nominated capacity, which would be conducted shortly after nomination cut-off and subject to a reserve price of zero (with compressor fuel provided in-kind by shippers);

§ standards for key contract terms in primary, secondary and operational transportation agreements to make capacity products more fungible and, in so doing, facilitate a greater level of secondary capacity trading; and

§ a reporting framework for secondary capacity trades that provides for the publication of the price and other related information on secondary trades.

Together these reforms are expected to foster the development of a more liquid secondary capacity market and, in so doing, improve the efficiency with which capacity is allocated and used on transportation assets operating under the contract carriage model (i.e. outside the Declared Transmission System (DTS) in Victoria),2 by:3

§ using market based processes to allocate capacity on a non-discriminatory basis to those that value it most;

§ improving the incentive shippers have to trade capacity and posing a constraint on the ability of pipeline operators to sell secondary capacity at prices in excess of what would be expected in a workably competitive market;

§ reducing search and transaction costs; and

§ reducing information asymmetries and aiding the price discovery process.

Greater liquidity in this market is expected to facilitate increased trade in gas and support the development of a more robust reference price for gas. This, in turn, is expected to enable market participants to make more informed decisions about their use of gas and

1 COAG Energy Council, Bulletin Two: Gas Market Reform Package, August 2016.2 There are currently two different models used to allocate and manage pipeline capacity in Australia:

§ the market carriage model, which provides open access to the Victorian Declared Transmission System and uses outcomes from the operation of the Declared Wholesale Gas Market (DWGM) to allocate pipeline capacity; and

§ the contract carriage model, which is in use on all other pipelines and relies on bilateral contracts between the pipeline operator and shippers to allocate pipeline capacity.

3 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 69 and 73.

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investments in exploration, production, pipelines and storage facilities.4 The package of reforms is therefore expected to promote the National Gas Objective (NGO) and the Energy Council’s Vision for the Australian Gas Market (Vision) (see Box 1.1).

Further detail on the reform package can be found in Chapter 2.

4 ibid, p. viii.

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Box 1.1: National Gas Objective and Vision for the Australian Gas Market

National Gas ObjectiveThe NGO is set out in section 23 of the NGL and states the following:

The objective of this law is to promote efficient investment in, and efficient operation and use of, natural gas services for the long term interests of consumers of natural gas with respect to price, quality, safety, reliability and security of supply of natural gas.

Energy Council’s Vision for the Australian Gas Market5

The Energy Council’s Vision is for:..the establishment of a liquid wholesale gas market that provides market signals for investment and supply, where responses to those signals are facilitated by a supportive investment and regulatory environment, where trade is focused at a point that best serves the needs of participants, where an efficient reference price is established, and producers, consumers and trading markets are connected to infrastructure that enables participants the opportunity to readily trade between locations and arbitrage trading opportunities.

At the time it released the Vision, the Council also noted that it would pursue the following outcomes in the next phase of gas market reform and development:Stream 1: Encouraging competitive gas supply:

(a) Improvements to the regulatory and investment environment so that gas supply is able to respond flexibly to changes in market conditions.

(b) A "social licence" for onshore natural gas development achieved through inclusion, consultation, improving the availability and accessibility of factual information to resources projects, and rigorous science to ensure communities concerns are addressed.

Stream 2: Enhancing transparency and price discovery:(a) Provision of accurate and transparent market making information on pipeline and large

storage facilities operations and capacity, upstream resources, and the actions of producers, export facilities, large consumers and traders.

(b) Increased flexibility and opportunity for trade in pipeline capacity. (c) A competitive retail market that will provide customers with greater choice and large users

with enhanced options for self-supply and shipment. Stream 3: Improving risk management:

(a) Liquid and competitive wholesale spot and forward markets for gas that provide tools for participants to price and hedge risk.

(b) Access to regional demand markets through more harmonised pipeline capacity contracting arrangements which are flexible, comparable, transparent on price, and non-discriminatory in terms of shippers’ rights, to accommodate evolving market structures.

(c) Harmonised market interfaces that enable participants to readily trade between locations and find opportunities for arbitrage and trade.

(d) Identified development pathways to improve interconnectivity between supply and demand centres, and existing facilitated gas markets, which enable the enhanced trading of gas.

Stream 4: Removing unnecessary regulatory barriers:(a) Regulation of gas supply and infrastructure is appropriate and enables participants to

pursue investment opportunities, in response to market signals, in an efficient and timely manner.

The outcomes that are most relevant to the capacity trading related reforms are Streams 2(a), 2(b), 3(b), 3(c) and 3(d).

5 COAG Energy Council, Australian Gas Market Vision, December 2014.

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1.1 Progression of the capacity trading reform package To progress the capacity trading reforms outlined above, the GMRG established:

§ a number of project teams to carry out the detailed design and development work, which consisted of a mix of members drawn from industry, consumer groups, market bodies and other industries (see Appendix C for a list of members); and

§ an Advisory Panel to provide strategic perspective and advice to the GMRG on key issues, which comprises senior representatives from all segments of the gas supply chain as well as Energy Consumers Australia (see Appendix C for a list of members).

Importantly, neither the project teams nor the Advisory Panel had any decision-making power. Their role was to inform the GMRG’s consideration of the design options, which were then consulted upon with other stakeholders. The GMRG has nevertheless benefited from, and greatly appreciates, the effort and resources that project team members and the Advisory Panel put into providing their advice to the GMRG. The GMRG also greatly appreciates the support provided by the Australian Energy Market Operator (AEMO), the AEMC, the Australian Energy Regulator (AER) and the Australian Competition and Consumer Commission (ACCC).

Work on the design of the capacity trading reforms was initially expected to be completed during 2018, allowing the recommendations to be considered by the Energy Council at the end of 2018 so the reforms could be implemented by 2021. However, in response to a request from the Hon. Josh Frydenberg MP, Minister for the Environment and Energy, the GMRG examined opportunities to accelerate this work and committed to providing its final recommendations on the capacity trading reforms by the end of 2017. Specifically, the GMRG agreed to provide its final recommendations to the Energy Council on:

(1) Who should operate and administer the capacity trading platform and the day-ahead auction in July 2017.

(2) The following elements of the reform package at the 24 November 2017 meeting:(a) the standardisation related reforms;

(b) the capacity trading platform; and(c) the reporting framework for secondary capacity trades.

(3) The day-ahead auction of contracted but un-nominated capacity in December 2017 for an out-of-session decision. Due to the complexity and wide-ranging stakeholder views associated with the day-ahead auction, it has been necessary to split this recommendation from those listed in (2) to allow for adequate consultation and consideration of the design of the auction.

The GMRG’s recommendations on item (1) was provided to the Energy Council on 14 July 2017. In short, the GMRG recommended that AEMO operate both the capacity trading platform and day-ahead auction and that the capacity trading platform form part of the Gas Supply Hub (GSH) trading exchange.6 This recommendation was endorsed by the Energy Council7 and the work subsequently carried out on the design of the capacity trading platform and auction has proceeded on this basis.

6 The GMRG’s final recommendations can be found here: http://gmrg.coagenergycouncil.gov.au/publications/gmrg-recommendation-on-who-should-operate-capacity-trading-platform-auction

7 COAG Energy Council, 12th Energy Council Meeting Communique, 14 July 2017.

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In keeping with the timetable set out above, the remainder of this paper focuses on the matters set out in item (2). A separate paper will be provided to the Energy Council in December that deals with the matters set out in item (3).

It is worth noting in this context that while it has been necessary to split the recommendations on the design of the standardisation reforms, the capacity trading platform and reporting framework from the recommendations on the design of the day-ahead auction, these reforms are inextricably linked. The day-ahead auction, for example, will provide firm capacity holders with a greater incentive to sell any spare capacity they may have prior to the auction, while the capacity trading platform and the standardisation reforms will provide shippers with the means by which any spare capacity can be readily traded before it would otherwise be released in the auction. So while the GMRG is seeking agreement to the matters listed in (2) now and will be doing the same for the matters listed in (3) in December, the approval of the design of the capacity trading platform, the standardisation reforms and reporting framework pre-supposes approval of the proposed design of the day-ahead auction in December. The only substantive issue that therefore needs to be considered in December is the detailed design of the auction.

1.2 Consultation on the capacity trading reform packageWork on the capacity trading reform package commenced in February 2017 and over the last nine months the GMRG has conducted 35 project team meetings, four Advisory Panel meetings, two public forums and a large number of bilateral meetings with industry participants, consumer groups and market bodies. In May 2017, the GMRG also published a consultation paper that sought feedback from stakeholders on who should operate and administer the capacity trading platform and day-ahead auction. More recently, the GMRG has published consultation papers on:

§ the design of the standardisation reforms and capacity trading platform – consultation on these two elements of the reform package ended on 4 October 2017; and

§ the design of the day-ahead auction and reporting framework – consultation on these two elements of the reform package ended on 6 November 2017.

These consultation papers identified a number of design options for the various reforms and provided an indication of the GMRG’s preliminary view on each of the options.

Stakeholders were given four weeks to provide written feedback on the options presented in these two consultation papers and were also invited to attend two public forums on these topics. The stakeholders that participated in these two consultation processes included the ACCC, AEMO, the AEMC, the AER and a number of organisations with interests across the gas supply chain, including, amongst others:

§ gas producers, such as APLNG, Esso, Shell, Santos, Central Petroleum and Senex, and the Australian Petroleum Production and Exploration Association (APPEA);

§ gas retailers and gas fired generators, such as AGL, Alinta, EnergyAustralia, Engie, ERM Power, Hydro Tasmania, Aurora Energy, Origin, Power and Water Corp, and the Australian Energy Council (AEC);

§ other gas users, such as Ridley Corporation and the Major Energy Users (MEU); § gas pipeline operators, such as APA, Epic, Jemena, SEAGas and Tasmanian Gas

Pipeline (TGP) Pty Ltd, and the Australian Pipeline and Gas Association (APGA); and§ other market participants, including CQ Partners and the Macquarie Group.

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Feedback on the design of the capacity trading reform package was also provided by the GMRG’s Advisory Panel and through extensive bilateral discussions with stakeholders, including some consumer groups.

While stakeholders were generally supportive of the reform package and agreed with most of the GMRG’s preliminary views on the standardisation reforms, the capacity trading platform and reporting framework, a small number of issues were raised about the design of these reforms. The GMRG has therefore given further thought to these issues when developing the final recommendations set out in this report, a summary of which can be found in the following section.

In contrast to these three elements of the reform package, the design of the day-ahead auction has been more controversial. The GMRG is currently working through the feedback provided on the day-ahead auction and, as noted above, will provide its final recommendations on this element of the reform package in December.

Further detail on the feedback provided by stakeholders can be found in Parts A-C of this report. Public written submissions received in response to the two consultation papers can be accessed on the GMRG website.8

1.3 Final recommendations

Having regard to the feedback provided by stakeholders and the advice provided by the GMRG’s legal advisor, Johnson Winter & Slattery (JWS), the GMRG has developed its final recommendations on the design of:

(a) the standardisation related reforms; (b) the capacity trading platform; and(c) the reporting framework for secondary capacity trades.

In developing these recommendations, the GMRG has applied the rule making test that the AEMC is required to consider when exercising its rule making functions, which requires consideration to be given to whether the change will or is likely to contribute to the achievement of the NGO (see Box 1.1). The GMRG’s assessment of whether the proposed design of the reforms will, or is likely to, contribute to the NGO, has been carried out qualitatively having regard to whether the reforms are consistent with:

§ the AEMC’s required, preferred and suggested outcomes for the capacity trading reforms (see Appendix A);

§ the broader objectives of the capacity trading reform package, which were described by the AEMC as being to improve the efficiency with which transportation capacity is allocated and utilised and foster the development of a more liquid market for secondary capacity;9 and

§ the Energy Council’s Vision of the direction gas market development should take to meet the NGO and the outcomes the Energy Council agreed to pursue in the next phase of gas market reform (see ).10

The remainder of this section provides a summary of the GMRG’s final recommendations on these three elements of the reform package. Further detail on these recommendations

8 See http://gmrg.coagenergycouncil.gov.au/publications9 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 67-69.10 COAG Energy Council, Australian Gas Market Vision, December 2014.

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can be found in Parts A-C of this report, while Appendix B compares the GMRG’s final recommendations with the AEMC’s required, preferred and suggested outcomes.

It is important to note that the introduction of the capacity trading reform package will impose new obligations on service providers (i.e. pipeline operators and the operators of compressors) as well as primary and secondary shippers. To give effect to these new obligations and the reform package more generally, amendments will need to be made to the National Gas Law (NGL), the National Gas Rules (NGR), Regulations made under the NGL and procedures. A number of new subordinate instruments will also need to be developed and the functions and powers of AEMO, the AER and the AEMC will need to be expanded. The GMRG has therefore considered the governance arrangements that will be required to give effect to the reform package when developing its final recommendations.

1.3.1 Standardisation reforms

To facilitate a greater level of trade in secondary capacity, the AEMC recommended that:

§ all trades carried out through the exchange component of capacity trading platform and the day-ahead auction be given effect through an operational transfer; and

§ off-market bilateral trades be given effect through either an operational transfer or bare transfer, however, the seller must offer the buyer the option of an operational transfer.

The AEMC also recommended that key terms and conditions in primary, secondary and operational transportation agreements be standardised and that shippers be provided greater flexibility to change receipt and delivery points.

The GMRG has worked with stakeholders and its legal advisor, JWS, on these recommendations. In doing so, the GMRG has considered: § the capacity transfer mechanism to be used to give effect to capacity trades;§ the types of contracts that need to be standardised to facilitate capacity trading;§ the level of contract standardisation that can be achieved and the form the

standardised provisions should take;§ the governance arrangements that could apply to the standardised contracts; and

§ how service providers will recover the costs associated with these reforms.

The GMRG has also considered whether other measures are required to reduce the barriers to capacity trading posed by allocation arrangements, provisions in primary GTAs and the lack of harmonisation of gas day start times and nomination cut-off times.

Table 1.1 provides a high-level summary of the GMRG’s final recommendations on each of these issues. Further detail on these recommendations can be found in Part A.

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Table 1.1: Summary of the GMRG’s final recommendations on the standardisation related reformsDesign Element RecommendationCapacity transfer mechanisms to be used for secondary trading

Consistent with the AEMC’s recommendations, the GMRG recommends that:§ Operational transfers be used to give effect to capacity purchased through the capacity trading platform, the day-ahead auction and bilateral trades where

the buyer elects to use an operational transfer. § Bare transfers be allowed in cases where capacity is purchased through bilateral trades, subject to the caveat that the sellers of secondary capacity offers

the buyer the option of using an operational transfer. Under both types of transfers, the primary shipper’s capacity rights (or part thereof) are temporarily transferred to the secondary shipper and the obligation to pay the service provider remains with the primary shipper. The main difference between the two mechanisms is that under an operational transfer, the secondary shipper is responsible for making nominations directly to the service provider (rather than via the primary capacity holder) and complying with the terms and conditions of access set out in the operational GTA it enters into with the service provider.

Contract standardisation

Standardisation of operational GTAsThe GMRG recommends that priority be given to standardising operational GTAs, given these contracts will be used to give effect to trades conducted through the capacity trading platform and the day-ahead auction, and will also have to be offered under bilateral trades. The standardised operational GTA will operate like a master agreement between the service provider and secondary shipper, and set out the terms and conditions on which the secondary shipper can utilise the service provider’s services if it procures secondary capacity via an operational transfer.It will be mandatory for service providers that provide third party access to publish a standard form operational GTA on their website and to offer to enter into this agreement with secondary shippers (subject to some limited qualifications and exemptions). The NGL and NGR will not, however, prohibit service providers and shippers agreeing to vary the terms, include other services in the agreement, or include the transfer mechanism in a primary GTA.The terms on which capacity is sold through the capacity trading exchange or day-ahead auction will be set out in the Exchange Agreement and the Auction Agreement. For bilateral trades, the shippers buying and selling capacity will agree terms between themselves in Capacity Trading Agreements (CTAs).

Content of the standardised Operational GTA and level of standardisationThe standardised operational GTA will consist of a set of: § standard operational, prudential and other legal terms governing the relationship between the secondary shipper and the service provider that will apply to

all facilities; and§ facility specific terms, which may differ across facilities due to differences in operational or contractual arrangements. While service providers will have some discretion in relation to the facility specific terms, these terms will need to comply with a number of principles that will be set out in the NGR, the requirements set out in the Operational GTA Code (a new regulatory instrument that will set out the standard terms to be adopted by all service providers and the requirements for facility specific terms) and will also be subject to oversight by the AER.The GMRG has developed an initial draft of the Operational GTA Code, which stakeholders have provided some feedback on. The initial draft did not, however, make provision for the day-ahead auction product because the design of the auction had not been settled. The GMRG intends therefore to release another draft of the Operational GTA Code for consultation in early 2018.

Service provider costs The capacity trading reform package will impose a number of incremental establishment and capacity trading costs on service providers. The GMRG recommends that service providers have an opportunity to recover these costs, subject to the caveat that the charges are cost reflective and, so far as practical, reflect the outcomes of a workably competitive market. To impose some constraint on the charges levied by service providers, the GMRG also recommends that the AER be given the power to: § conduct a review of a service provider’s charges if it has concerns about their level (or if concerns are raised by an interested party); and § require amendments to the charges if it finds that they do not comply with the pricing principle outlined above.

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Design Element RecommendationGovernance arrangementsThe standard terms and requirements for the facility specific terms will be set out in an Operational GTA Code, which will be a new regulatory instrument developed under the NGL/NGR. Once the initial Code is made it will be subject to a hybrid governance model, which will involve the following:§ AEMO will be responsible for establishing an Industry Panel to consider changes to the Operational GTA Code and provide secretariat services to the

panel. AEMO will also be responsible for carrying out consultation on behalf of the Industry Panel and requesting input from the AEMC, where required. § Changes recommended by the Industry Panel will only take effect if approved by the AER. In deciding whether to approve the changes, the AER will be

required to take into account the panel’s recommendation (but will not be bound by it), the NGO and principles in the NGR. The AER is considered the most appropriate body to take on this role, because it is consistent with its current role in relation to approving the terms and conditions of access to covered pipelines and is not subject to the same types of conflicts that AEMO or the AEMC would be subject to. Under the proposed governance framework, the AER will also: § be responsible for monitoring service providers’ compliance with the obligation to publish the standard operational GTA and that the facility specific terms

and charges levied by service providers for entering into these arrangements, are consistent with the Operational GTA Code and NGR principles; § have the power to exempt a facility from the requirement to publish a standardised operational GTA (e.g. if it is not providing third party access).

Other measures to reduce barriers to secondary trading and participation in the auction

Allocation arrangements To reduce the opaqueness currently surrounding allocation agreements, information on the allocation agents a secondary shipper would need to contact to become a party to an allocation agreement at all the relevant points should be published on the Natural Gas Services Bulletin Board (BB).The GMRG also recommends that further work be carried out by the GMRG, in consultation with AEMO and industry, in early 2018 to address the allocation issues at Moomba and determine whether additional reforms are required to reduce the other barriers to trade posed by allocation arrangements. The GMRG will also work with the ACCC to determine whether any additional transparency measures are required in relation to allocation agreements.

Contractual limitations on capacity trading in primary GTAs There are a number of provisions in primary GTAs that may prevent or impede secondary trading. To ensure these do not act as a barrier to secondary capacity trading, the GMRG recommends that:§ Provisions that prohibit primary shippers from trading capacity, or require primary shippers to obtain a service provider’s consent before they can trade

capacity, be addressed through provisions that will require service providers to allow users to transfer contracted capacity to another party, without the service provider’s consent, if the user remains liable for capacity payments and the transferee has an operational GTA.

§ Provisions that prohibit primary shippers from requesting changes to receipt and delivery points, or limit the number of changes that can be requested, be addressed through provisions detailing the rights shippers have to seek changes to receipt or delivery points; the timeframes within which service providers must respond; and the pricing principle to apply to charges levied by the service provider for these changes (i.e. charges should be cost reflective and reflect the outcomes of a workably competitive market).

The provisions are expected to draw on the approach in rules 105(2) and 106(1) of the NGR, which apply in relation to scheme pipelines.

Harmonisation of gas day start times and nomination cut-off times To remove the barriers to trade posed by differences in gas day start times and nomination cut-off times, the GMRG recommends that changes be made to the NGL/NGR to require the adoption of: § a common gas day start time of 6 am (AEST) across the east coast (and the Northern Territory once it becomes connected) and apply to the operators of

all production, pipeline, compressor and storage facilities; and§ a common nomination cut-off time of 3 pm (AEST) for pipelines and other facilities that will be subject to the capacity trading reforms.The GMRG recommends these changes take effect by 1 October 2019.

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1.3.2 Capacity trading platform

To overcome some of the other impediments to secondary capacity trading, the AEMC recommended the development of a capacity trading platform(s) that would provide for both an anonymous exchange mechanism that shippers can use to trade commonly sought products and a listing service for bespoke products. The AEMC also recommended that:

§ steps be taken to optimise the pool of prospective buyers and sellers of capacity; and

§ the exchange provide for as many standardised services to be traded as possible.

In developing the design of the capacity trading platform, the GMRG has worked with stakeholders, AEMO and JWS to determine:

§ how the capacity trading platform will operate and interact with the GSH;

§ the initial list of products to be made available on the exchange;

§ how the pool of prospective buyers and sellers on the exchange will be maximised;

§ the arrangements that will need to be put in place to manage and allocate financial and default risks; and

§ the governance arrangements required to underpin the capacity trading platform.

Table 1.2 provides a high-level summary of the GMRG’s final recommendations on each of these issues. Further detail on these recommendations can be found in Part B.

1.3.3 Reporting framework for secondary capacity tradesTo increase the transparency surrounding secondary capacity trades and the market’s confidence in the secondary market, the AEMC recommended that information on the prices and other key terms struck in all secondary trades of pipeline and compression capacity be published at the time the trade is entered into, or shortly thereafter.

As with the other elements of the reform package, the GMRG has worked with market participants and its legal advisor, JWS, on these recommendations. In doing so, the GMRG has considered:

§ the types of trades to be reported and the information to be reported;

§ who should have the obligation to report trades and when they should be reported;

§ where the information should be published;

§ whether bilateral trades should be advertised before they are entered into; and

§ the governance arrangements to apply to the reporting framework.

Table 1.3 provides a summary of the GMRG’s final recommendations on these key elements of the reporting framework. Consistent with the AEMC’s recommendations, the reporting framework will capture trades that involve the direct transfer of capacity rights between shippers. It will not, however, capture transactions that can be used as an alternative to trading capacity, such as locational swaps or delivered gas supply agreements, because, as highlighted by stakeholders, this would go beyond the scope of the AEMC’s recommendations. The GMRG intends, however, to work with the ACCC in early 2018 to consider whether there is value in publishing this type of information and other information to reduce the opaqueness in the gas market.

Further detail on the GMRG’s final recommendations is provided in Part C.

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Table 1.2: Summary of the GMRG’s final recommendations on the capacity trading platformDesign Element RecommendationOperation of the capacity trading platform

The GMRG recommends that the capacity trading platform, which will be operated by AEMO and form part of the GSH trading exchange, provide for both:§ Exchange-based trading of commonly traded transportation (pipeline and compression) products, which can be conducted through either:

– the screen trade service, which allows participants to place anonymous bids or offers for standardised products that are automatically matched; or – the pre-matched trade service, which allows participants to bring a bilateral trade in one of the GSH products to the exchange for settlement.The screen trade service will operate on a fully anonymous basis (i.e. the names of counterparties will not be revealed pre-or post-transaction), with AEMO informing the relevant service provider of the trade once it has been executed. The service provider will then confirm the trade with each counterparty separately, maintaining the anonymity of the trading parties through this process.

§ A listing service that shippers can use to list more bespoke transportation products and imbalance trades.Trades conducted through the exchange will utilise the existing GSH settlement, prudential and reporting frameworks, which means participants will receive one settlement statement for all traded products and be able to aggregate prudential requirements across gas and secondary capacity products.

Initial set of services to be listed on the exchange

The GMRG recommends that the initial set of standardised products to be sold on the exchange include: § firm forward haul services on all major transmission pipelines (if the pipeline is bi-directional, services will be available in both directions);§ firm compression services at Moomba and Wallumbilla; and § firm park (storage) services on all the major transmission pipelines.These products will be available as day-ahead, daily (available on a 6-day rolling basis), weekly (available on a 4 week rolling basis) and monthly (available on a 3 month rolling basis) products and will have a minimum contract size of 500 GJ/day. The terms and conditions on which the buyer can use these products will be set out in the Operational GTA, which, amongst other things, will specify the maximum hourly flexibility the buyer will have and provide the buyer with a reasonable endeavours renomination right.

Zonal model The GMRG recommends that a zonal model with secondary firm rights at receipt and delivery points be used to maximise the pool of prospective buyers and sellers of firm forward haul services through the capacity trading platform. To implement this model, receipt and delivery point zones will need to be established on each pipeline that will be listed on the exchange and will need to reflect the technical pipeline requirements and market requirements.

Management of financial and delivery default risks

There are two key risks that buyers will be exposed to under the proposed design of the capacity trading platform:§ The seller’s primary GTA is terminated by the service provider: In this case, the GMRG recommends that the service provider be obliged to honour the

transaction for up to two weeks after the primary GTA is terminated and receive the price established through the exchange in return for doing so. The GMRG believes this approach is necessary because the buyer will not know the seller’s identity so will be unable to carry out its own assessment of the financial viability of its counterparty prior to entering into the trade. By keeping the trade on foot for two weeks, buyers will have time to find alternative arrangements, which will promote an orderly transition and minimise the impact of default on the gas market.

§ The seller short-sells capacity: In this case, the GMRG recommends that service providers give the seller an hour to rectify the short position and if it can’t be rectified, the trade be cancelled and the buyer(s) compensated. Because individual counterparties will not be known, if a trade is cancelled all secondary shippers’ capacity would be pro-rated down.

Governance arrangements

The GMRG recommends that the governance framework that currently applies to the GSH be maintained, but the necessary changes be made to the NGR, the Exchange Agreement and procedures to accommodate capacity trading and the recommendations set out above. In relation to the zonal model, the GMRG recommends that any proposal to change the zones be submitted to the Industry Panel for consideration and approved by the AER. Principles will be included in the NGR to guide this process and enable any person to make a request to change the zone.

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Table 1.3: Summary of the GMRG’s final recommendations on the reporting framework for secondary capacity tradesDesign Element RecommendationTrades subject to reporting

The GMRG recommends that the reporting framework apply to: § all screen and pre-matched trades carried out through the capacity trading platform; and § bilateral trades of capacity involving forward haul, backhaul, park, park and loan and/or compression services.Capacity purchased through the auction will also need to be reported but the reporting framework will be slightly different. The GMRG’s recommendations on the day-ahead auction reporting framework will be made to the Energy Council in December.

Information to be reported

The GMRG recommends that the reporting framework require the following information to be reported:§ the date of the trade and the start and end dates for the trade;§ the type of trade (e.g. exchange traded or bilateral) and how it is given effect (e.g. operational GTA, primary GTA or bare transfer);§ the type of service procured (i.e. forward haul, backhaul, park, park and loan, compression), the firmness of the service and service priority; § the pipeline or compression facility the trade relates to and, in the case of pipeline services, the direction of the service and zones between which gas is

transported (zones will be used to, the extent practicable, protect the anonymity of counterparties);§ the amount of capacity procured (expressed on a maximum daily quantity (MDQ) and maximum hourly quantity (MHQ) basis); and§ the price paid for the capacity (including, where relevant, details of the price structure and price escalation mechanism for bilateral trades).

Responsibility for reporting

The GMRG recommends that: § AEMO be accorded responsibility for reporting trades carried out through the capacity trading platform; and § sellers be accorded responsibility for reporting bilateral trades.

Where and when information is to be reported and published

The GMRG recommends that trades carried out: § through the capacity trading platform be reported on the GSH by AEMO as soon as practicable after the trade occurs (consistent with what currently

applies for commodity) and published on the BB website by the end of the gas day; and§ bilaterally be reported to AEMO by the earlier of one day after the trade is executed, and the day prior to the trade commencing (D-1) and published on

the BB website by AEMO by the end of the gas day.

Requirement to advertise bilateral trades

The GMRG has some concerns about the workability of the proposal to require bilateral trades be advertised on the listing service ahead of time. As an alternative, the GMRG is recommending that these trades be subject to the reporting framework, with the prices and other key terms struck in these trades published on an ex post basis. The publication of this information is intended to discourage parties from engaging in any form of discriminatory behaviour, but if the reported information reveals this type of behaviour is occurring, the AEMC could recommend further changes as part of its biennial review of liquidity in the wholesale gas and pipeline capacity trading markets.


A number of changes will need to be made to the NGL and NGR to give effect to this reporting framework.Changes to the NGL will be required to impose an obligation on sellers to provide AEMO with information about bilateral trades and permit AEMO to publish information on these trades and trades carried out through the capacity trading platform, in accordance with the NGR and applicable procedures. Changes will also need to be made to the NGR to set out the specific obligations that: § sellers have to report information to AEMO, including the types of trades to be reported, the information that must be reported and the timing for

reporting; and§ AEMO has to report the trade information on the GSH and BB website. Secondary trading reporting procedures will also need to be developed by AEMO.The AER will be responsible for monitoring and enforcing compliance with these obligations using its existing powers in the NGL.

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1.3.4 Consistency of the final recommendations with the NGO In the GMRG’s view, the recommendations set out in Tables 1.1-1.3, are fit for purpose, targeted and proportionate to the issues they are intended to address and will achieve the stated objective of facilitating more trade in secondary capacity by:

§ making capacity products more fungible and providing secondary shippers with access to secondary capacity on reasonable terms, by developing standardised products for the capacity trading platform and requiring service providers to offer to enter into standardised operational GTAs with secondary shippers;

§ removing other impediments to trade, including restraints on secondary capacity trading, restrictions on receipt and delivery point flexibility and differences in gas day start times and nomination cut-off times;

§ maximising the pool of prospective buyers and sellers of secondary capacity and facilitating a greater level of competition between shippers for the provision of secondary capacity, by implementing a zonal receipt and delivery point model with secondary firm rights at individual receipt and delivery points;

§ aiding the price discovery process and reducing the search and transaction costs that market participants currently face through:

o the establishment of a single capacity trading platform;

o the development of standardised products and the standardised operational GTA;

o the publication of information on allocation arrangements; and

o the publication of information on the prices and other key terms struck in secondary capacity trades shortly after they are entered into;

§ instilling a greater level of confidence in the secondary capacity market through the implementation of robust governance arrangements for the standardisation reforms, the capacity trading platform and the reporting framework; and

§ allowing shippers to readily co-ordinate trades across pipelines (regardless of location and ownership) and to procure gas and other gas services through one platform.

The GMRG is also satisfied that the reforms:

§ appropriately reflect the legitimate business interests of service providers and other parties that have rights to use the transportation services, including primary and secondary capacity holders;

§ are operationally feasible and recognise the operational and technical requirements necessary for the safe and reliable operation of the assets used in the provision of transportation services; and

§ facilitate the efficient operation and use of the capacity trading platform and day-ahead auction.

The recommendations can therefore be expected to improve the efficiency with which transportation capacity is allocated and used under the contract carriage model, which will, in turn, foster the development of a liquid secondary capacity market and promote efficient investment in, and the efficient operation and use of, natural gas services. This is consistent with the overarching objective of the capacity trading reform package and is also consistent with the Energy Council’s Vision of the direction gas market development should take (in particular, outcomes 2(a), 2(b), 3(b), 3(c) and 3(d) see ). The ultimate

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beneficiaries of these improvements will be consumers of natural gas. The adoption of these recommendations can therefore be expected to promote the NGO.

Finally, it is worth noting that the implementation of these reforms will inevitably give rise to some costs. While the benefits of the reforms are expected to outweigh the costs, the GMRG has, where possible, sought to minimise the costs associated with the reforms by leveraging existing systems, processes and governance frameworks.

1.4 How the capacity trading reform package will operate

The way in which the final design of the capacity trading reform package is intended to operate is depicted in Figure 1.1. As this figure highlights, shippers that want to buy or sell secondary capacity will be able to do so prior to nomination cut-off time by using either:

§ the capacity trading platform, which will consist of both:

o an exchange service, which will facilitate the trade of standardised transportation products (e.g. day-ahead, daily, weekly and monthly firm forward haul, compression and park products) through either screen trading or the pre-matched trade service; 11 and

o a listing service, which will facilitate the trade of more bespoke transportation products through bilateral trades; or

§ other means to identify potential counterparties and enter into bilateral trades.

After nomination cut-off time, if there is any spare contracted but un-nominated capacity and the pipeline or compressor is subject to the auction, then it will be released in the day-ahead auction. While the auction will provide a credible alternative source of capacity for shippers, the auction product will be a lower quality product than the firm capacity sold on the capacity trading platform, because, in keeping with the AEMC’s recommendations, it will need to accommodate nominations and renominations by firm capacity holders that occur after the auction is conducted. The auction product will also only be available on a day-ahead basis and will be subject to a greater level of volume and price risk (i.e. if demand for capacity is high, the auction would clear at a high price and there is also a risk no capacity would be available in the auction).

To participate in the capacity trading platform and/or the day-ahead auction, shippers will need to enter into a number of contractual arrangements. For example, shippers that want to use the capacity trading platform will need to enter into the Exchange Agreement with AEMO, while shippers that want to use the day-ahead auction will need to enter into tan Auction Agreement with AEMO. To utilise the capacity procured through the capacity trading platform or the auction, secondary shippers will also need to enter into an operational GTA12 with the relevant service provider(s) and, where relevant, become a party to the allocation agreements at the receipt and delivery points they intend to use. Further detail on the contractual arrangements that shippers will need to enter into can be found in Chapter 2.

11 The pre-matched service allows participants to register off-market trades in listed products to the exchange for settlement.

12 The service provider can also offer an operational GTA-style service under a primary GTA, allowing a primary shipper to roll capacity bought in the secondary market into the primary GTA.

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Figure 1.1: How the capacity trading reform package will operate

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1.5 Next steps

The GMRG intends to provide the Energy Council with its final recommendations on the design of the day-ahead auction in December for an out-of-session decision. If the Energy Council endorses the recommendations made at this time, then the GMRG and AEMO will commence work on implementing the reform package.

Before implementation can occur, a number of changes will need to be made to the NGL, the NGR, the Regulations and a range of other subordinate instruments. AEMO will also need to design, develop and test the new systems for the capacity trading platform and the day-ahead auction, carry out training and conduct an industry trial of the capacity trading platform and the day-ahead auction. Service providers will similarly need to design, build and test their own systems for the capacity trading platform and auction and develop standardised contracts to give effect to secondary capacity trades and auction purchases.

At this stage it is expected that the GMRG will take the lead on developing the legal architecture required to give effect to the design of the reform package approved by the Energy Council and be responsible for:

§ preparing the drafting instructions for the proposed changes to the NGL; and

§ developing the changes that will be required to the NGR, the Regulations and other subordinate instruments to be made by the South Australian Minister to give effect to the package of reforms.

Once the proposed changes to the NGL, NGR and other subordinate instruments have been drafted, they will be submitted to SCO for review. If SCO agrees, then the draft instruments will be released for public consultation and stakeholders will be provided six weeks to provide their feedback. At this stage, the stakeholder consultation period is expected to commence in March and be completed by mid-April 2018.

Following the incorporation of stakeholder feedback, the final set of proposed changes to the NGL, NGR and other subordinate instruments will be provided to SCO and the Energy Council for their consideration and approval. This consideration is expected to take place in mid-2018. Further detail on the proposed timing for the development of the legal architecture is provided in Table 1.4.

The other point to note from this table is that a separate review will be carried out in early 2018 to determine whether the capacity trading reform package should extend to the Northern Territory. This review will be carried out by the AEMC, in conjunction with the GMRG and the Northern Territory Government, and the final recommendations will be made to the Energy Council at its April 2018 meeting. If a decision is made to extend the application of the reforms to the Northern Territory, then they will commence operation at the same time as the east coast (i.e. 1 March 2019).

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Table 1.4: Next stepsDate ProcessDecember 2017 Provision of recommendations on auction design and the application of reforms

outside the east coast to Energy Council for out-of-session decisionDecember 2017 – February 2018

Development of drafting instructions for the NGL and amendments to the NGR and other subordinate instruments

Late February 2018 SCO review and approval of draft instruments to reflect the agreed designJanuary – March 2018 AEMC review of the application of the capacity trading reform package in the

Northern TerritoryMarch – mid-April 2018 Stakeholder consultation on the draft instruments (6 weeks)April 2018 Final recommendation to the Energy Council on the application of the capacity

trading reform package in the Northern TerritoryMay 2018 SCO consideration of final instrumentsMay – June 2018 Final instruments presented to Energy Council for approvalJun – Aug 2018 Amendments to the NGL progressed through SA Parliament

Once the NGL changes have been proclaimed, the SA Minister can make the initial set of rules and any other subordinate instrument required to give effect to the reforms

1.6 Structure of reportFurther detail on the GMRG’s final recommendations can be found in the remainder of this report, which is structured as follows:

§ Chapter 2 provides an overview of the capacity trading reform package;

§ Chapter 3 outlines the assessment framework the GMRG has used when developing its final recommendations;

§ Part A focuses on the standardisation related reforms, which are discussed in detail in:

o Chapter 4, which focuses on the contract standardisation reforms; and

o Chapter 5, which outlines other measures that could be implemented to reduce the barriers to secondary capacity trading and participation in the day-ahead auction;

§ Part B focuses on the capacity trading platform, which is discussed in detail in:

o Chapter 6-9, which focuses on key elements of the exchange component of the capacity trading platform, including the initial set of products to be sold, delivery, settlement and credit risk processes and other measures to manage delivery risk;

o Chapter 10, which focuses on the key elements of the listing service; and

o Chapter 11, which outlines the changes to the governance arrangements that are likely to be required to implement the capacity trading platform;

§ Part C focuses on the reporting framework for secondary capacity trades, which is discussed in detail in:

o Chapter 12, which focuses on the reporting requirements and timeframes; and

o Chapter 13, which focuses on the governance arrangements required to underpin the reporting framework.

§ Appendix A provides a summary of the AEMC’s recommendations, which were classified as required, preferred and suggested outcomes;

§ Appendix B compares the GMRG’s final recommendations with the AEMC’s required, preferred and suggested outcomes;

§ Appendix C sets out the members of the project teams and Advisory Panel;

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§ Appendix D provides an overview of the services offered by pipelines; and

§ Appendix E provides an overview of the GSH.§

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2. Overview of the Capacity Trading Reform PackageThe capacity trading reform package was recommended by the AEMC in the East Coast Review and endorsed by the Energy Council at its 14 August 2016 meeting. The objective of this reform package is, as noted in Chapter 1, to improve the efficiency with which transportation capacity is allocated and utilised under the contract carriage model and to foster the development of a more liquid market for secondary capacity.13 The remainder of this chapter provides further detail on:

§ the key elements of the capacity trading reform package; and

§ how capacity can be procured under the new capacity trading framework.

2.1 Key elements of the reform package

The capacity trading reform package (see Figure 2.2) provides for the introduction of:

§ A capacity trading platform that shippers can use to trade secondary transportation capacity prior to the nomination cut-off time on gas day D-1 (i.e. the day before the gas is due to be transported), which will consist of both: o an anonymous exchange mechanism that shippers can use to buy or sell

commonly traded transportation products, such as firm forward haul services, stand-alone compression services and pipeline storage (park) services; and

o a listing service that shippers can use to buy or sell more bespoke products.

The trading platform, which will be operated and administered by AEMO and form part of the GSH trading exchange, is intended to reduce the search and transaction costs that shippers may otherwise face when trying to trade secondary capacity.

§ A day-ahead auction of contracted but un-nominated transportation capacity that will be conducted on designated pipelines shortly after nomination cut-off on gas day D-1 and subject to a reserve price of zero (with compressor fuel provided in-kind by shippers). The objective of the day-ahead auction is, as the AEMC noted, to:14 o encourage capacity holders to sell any spare capacity they may have on the

trading platform prior to the nomination cut-off time by providing for service providers to retain the auction proceeds; and

o pose a constraint on the ability of service providers to sell day-ahead capacity at prices in excess of what would prevail in a workably competitive market by adopting a zero reserve price and allowing the market to determine the value.

The day-ahead auction will be operated and administered by AEMO.

The reform package also provides for the implementation of:

§ a range of standardisation related reforms, which are intended to facilitate a greater level of secondary capacity trading; and

§ a reporting framework for secondary capacity trades, which is intended to reduce information asymmetries and aid the price discovery process.

13 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 67, 73 and 83.14 ibid, p. 83.

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Figure 2.2: Capacity trading reform package

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2.2 How secondary capacity can be procured under the new framework

Under the capacity trading reform package, shippers that want to buy or sell secondary capacity will be able to have recourse to either:15

§ the exchange component of the GSH – the exchange will be used to facilitate the trade of standardised transportation products (e.g. day-ahead, daily, weekly and monthly firm forward haul, compression and park products) through either screen trading or the pre-matched trade service; 16 or

§ the listing service component of the GSH – the listing service will be used to facilitate the trade of more bespoke transportation products through bilateral (off-market) trades.

Shippers may also be able to procure day-ahead standardised capacity products through the auction on those pipelines and other facilities that will be subject to the auction if there is any contracted but un-nominated capacity available.

The way in which secondary capacity will be released through these mechanisms is depicted in Figure 1.1.

Before utilising the capacity trading platform or the day-ahead auction, shippers will need to enter into the relevant agreements with AEMO. Secondary shippers will also need to enter into a number of other contractual arrangements to utilise the capacity procured through the GSH or the auction. Table 2.5 provides more detail on the arrangements shippers will need to have in place.

Table 2.5: Arrangements shippers will require to access capacity trading measuresParticipation in the day-ahead auction

Membership and contractual obligations

While the participation arrangements for the day-ahead auction have not yet been finalised, they are expected to operate in a similar manner to the GSH (see Chapter 7). Specifically, it is envisaged that shippers that want to purchase capacity through the day-ahead auction will execute an Auction Agreement with AEMO. The Auction Agreement will set out the terms of participation in the auction and the terms governing purchases of capacity through the auction, including the prudential and settlement obligations.

15 Shippers will also be able to have recourse to other means to identify potential counterparties and enter into bilateral trades.

16 The pre-matched service allows participants to register off-market trades in listed products to the exchange for settlement.

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Table 2.5: Arrangements shippers will require to access capacity trading measuresParticipation in the GSH capacity trading platform

Membership and contractual obligations

Primary and secondary shippers that want to use the GSH will need to become members of the GSH and be registered as trading participants.Shippers can become a trading participant by executing a Membership Agreement with AEMO and then registering as a trading participant. Through the Membership Agreement, shippers will become a party to the Exchange Agreement.The Exchange Agreement is a multilateral agreement that sets out the terms of participation in the GSH and the terms governing transactions entered into through the exchange. The body of this agreement contains the trading, delivery, prudential and settlement obligations, while the product specifications are set out in schedules.

Use of secondary capacity procured through the trading platform or auctionOperational transfers17

If a shipper procures capacity through the trading platform or day-ahead auction, the trade will be given physical effect through an operational transfer. Secondary shippers will also have the option to utilise an operational transfer if they enter into a bilateral trade through the listing service or other means. A secondary shipper will therefore need to have entered into an operational Gas Transportation Agreement (operational GTA) with the relevant service provider, or otherwise agreed with the service provider to include an operational transfer mechanism into its primary GTA.

Operational GTAs, which are sometimes referred to as ‘zero MDQ’ contracts, operate like a master agreement between the service provider and secondary shipper, with the operational capacity (measured on a Maximum Daily Quantity (MDQ) basis) set at zero until the shipper purchases capacity. The operational GTA sets out the terms on which the secondary shipper can utilise the service provider’s assets if it procures secondary capacity via an operational transfer, including the operational, prudential and other terms governing the relationship between the service provider and secondary shipper. If capacity is purchased then the MDQ in the shipper’s operational GTA will be increased for the duration of the trade and it will be entitled to make nominations directly to the service provider and liable to pay the service provider for any specified charges (i.e. imbalance or overrun charges) set out in the operational GTA. The primary shipper, on the other hand, will remain liable to pay the service provider for the capacity sold to the secondary shipper.

Allocation agreements

If a secondary shipper procures capacity through the trading platform or day-ahead auction and wants to use a multi-user receipt or delivery point, it will need to become a party to the allocation agreement at that point. This agreement sets out the rules the allocation agent is required to use to allocate gas metered as having been supplied between shippers.

Other services and arrangements

In some cases, a secondary shipper that procures capacity through the trading platform or day-ahead auction may also require: § access to other transportation related services that are not available on the trading

platform or through the auction (for example, in some locations a shipper will require redirection services and compression services) and will need to enter into arrangements with the relevant service provider for the provision of that service; and

§ access to a receipt or delivery point that is controlled by a third party and will need to enter into arrangements with that party to ensure they can utilise those points.

As Table 2.5 highlights, operational transfers (see Box 2.2 for more detail) are expected to play a key role under the reform package and will be given effect through an operational GTA.18 Operational GTAs set out the terms on which the secondary shipper can use the service provider’s assets if it procures secondary capacity under a bilateral agreement with another shipper or through the trading platform or day-ahead auction.

It is worth noting in this context that while the term ‘transfer’ in operational transfer implies that capacity is being transferred from one shipper to another, this will not occur in relation

17 Refer to Box 2.1 for an explanation of this term.18 The service provider can also offer an operational GTA-style service under a primary GTA,

allowing a primary shipper to roll capacity bought in the secondary market into the primary GTA.

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to the day-ahead auction. In the day-ahead auction, any contracted but un-nominated capacity sold through the auction will be allocated to the auction winners, but there will not be a corresponding reduction in the capacity holdings of primary shippers that have contracted but un-nominated capacity.

Box 2.2: Capacity transfer mechanisms

Transfers of capacity can be given effect through either: § an operational transfer - under an operational transfer, the price, prudential and other

legal provisions relating to the sale of capacity are set out in the secondary CTA, Exchange Agreement or Auction Agreement entered into by the shippers, while the operational terms are set out in the operational GTA entered into by the service provider and secondary shipper; or

§ a bare transfer - under a bare transfer all the terms and conditions applying to the trade are set out in the CTA entered into by the primary and secondary shipper.

Under both types of transfers, the primary shipper’s capacity rights (or part thereof) are temporarily transferred to the secondary shipper and the obligation to pay the service provider remains with the primary shipper. The key difference between these two forms of transfer mechanisms is that under the:

§ bare transfer, the primary shipper is responsible for making nominations on behalf of the buyer of the secondary capacity and complying with the operational and legal obligations imposed by the service provider under its primary GTA for the capacity that it has sold; and

§ operational transfer, the secondary shipper is responsible for making nominations directly to the service provider and complying with the operational and legal obligations in the operational GTA it has entered into with the service provider in relation to the capacity that has been purchased.

Operational transfers can therefore result in lower administrative and monitoring costs for the primary shipper and enhance commercial confidentiality for the secondary shipper.

Operational Transfer

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Box 2.2: Capacity transfer mechanisms

Bare Transfer

Source: AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 99-100 and Pipeline Access Discussion Paper, 3 March 2016, pp. 18-19.

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3. Assessment Framework There are a number of different ways in which the capacity trading reforms could be designed and implemented. When assessing these options and developing its final recommendations, the GMRG has had regard to the rule making test that the AEMC is required to consider when exercising its rule making functions.19 This test states that:20

§ the AEMC may only make a rule if it is satisfied it will, or is likely to, contribute to the achievement of the NGO; and

§ the AEMC may give such weight to any aspect of the NGO as it considers appropriate, having regard to any relevant Council statement of policy principles.

In keeping with this test, the GMRG has had regard to the NGO, which as noted in , is to promote efficiency for the long-term interests of natural gas consumers (see Box 3.3 for more detail on economic efficiency).

Box 3.3: Economic efficiency concepts

Economists generally recognise the following types of efficiency:§ Allocative efficiency – This term is used to refer to the situation in which society’s

resources are allocated between end uses in an optimal way to those that value them most. This efficiency concept requires prices that are cost reflective and is consistent with the ‘efficient use of’ element of the NGO.

§ Productive (or technical) efficiency – This term is used to refer to goods and services being produced at the lowest possible cost, using the least-cost combination of inputs. This concept is consistent with the ‘efficient operation of’ element of the NGO.

§ Dynamic efficiency – This term is used to refer to a market outcome in which society’s resources are deployed efficiently between present and future uses, so that the welfare of society is maximised over time (i.e. allocative and productive efficiency are achieved jointly over time). This term is also used to refer to the ability of firms and markets to adapt over time in response to changes in consumer preferences and/or technology by implementing measures that result in a reduction in costs, improvements in product quality and/or the development of new products. This is consistent with the long run ‘efficient investment in’, ‘efficient operation of’ and ‘efficient use of’ elements.

These three dimensions of economic efficiency are illustrated in the following diagram developed by the Productivity Commission.

Source: Productivity Commission, Staff Research Note On Efficiency and Effectiveness: some definitions, May 2013.

19 Section 291 of the NGL.20 See section 291 of the NGL.

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As the AEMC has previously observed, quantifying the costs, benefits and efficiency improvements associated with these types of reforms can be difficult.21 The GMRG’s assessment of whether the proposed design of the reforms will, or is likely to, contribute to the NGO, has therefore been carried out qualitatively having regard to whether the reforms are consistent with:

§ the AEMC’s required, preferred and suggested outcomes for the capacity trading reforms (see Appendix A);

§ the broader objectives of the capacity trading reform package, which were described by the AEMC as being to improve the efficiency with which transportation capacity is allocated and utilised and foster the development of a more liquid market for secondary capacity;22 and

§ the Energy Council’s Vision of the direction gas market development should take to meet the NGO and the outcomes the Energy Council agreed to pursue in the next phase of gas market reform (see ).23

The GMRG’s assessment has also been guided by the following principles that the AEMC usually employs when applying the NGO:24

§ Competition and market signals will generally lead to better outcomes than centralised planning and regulation, as competing energy businesses have an incentive to meet consumers’ needs efficiently.

§ Where it is required, regulation should be targeted, fit-for-purpose, provide incentives that imitate the outcomes of a workably competitive market, and involve regulatory costs proportionate to the materiality of the issue.

§ Risk allocation and the accountability for investment decisions should rest with those parties best placed to manage them.

§ Market and regulatory frameworks should be flexible and provide firms with a clear and consistent set of rules that allow them to independently develop strategies and adjust to changes in the market. These frameworks should also be resilient to changing supply and demand conditions, and patterns of flow, over the longer term.

Given the nature of the reforms, the GMRG has also considered the extent to which the proposed reforms, where relevant:

§ allow capacity in the short-term to be allocated to those that value it most;

§ provide secondary shippers with access to secondary capacity on reasonable terms (i.e. at prices and on other terms and conditions that, so far as practical, reflect the outcomes of a workably competitive market);

§ appropriately reflect the legitimate business interests of service providers and other parties that have rights to use the transportation services, including primary and secondary capacity holders;

§ are operationally feasible and recognise the operational and technical requirements necessary for the safe and reliable operation of the assets used in the provision of transportation services;

21 AEMC, Stage 2 Final Report: Information Provision, May 2016, p. 4.22 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 67-69.23 COAG Energy Council, Australian Gas Market Vision, December 2014.24 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 128-129.

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§ facilitate the efficient operation and use of the capacity trading platform and day-ahead auction; and

§ provide for the publication of information in a timely and cost-effective manner and in a format that is easy for participants to process and understand, which will aid the price discovery process by reducing information asymmetries.

When evaluating the design of the capacity trading platform, the GMRG has also had regard to the attributes that the Capacity Trading Platform and Day-Ahead Auction project teams thought the capacity trading and auction platforms would need to emulate if they were to become ‘platforms of choice’ for market participants. These attributes are set out the table below.

Table 3.6: ‘Platform of Choice’ evaluation criteriaEvaluation criteria

Operation of the platform:

Operated by an independent (i.e. a party that has no commercial interests in the outcome of the trades) and experienced operator Operated in a predictable and reliable mannerOperation of platform underpinned by a robust governance frameworkTransparency in costs and operation of platform

Trading Platform features:

Provides for low transaction costs and quick and effective execution of trades

Readily integrated with service providers’ nomination and scheduling processes

Co-ordination benefits:

Shippers can readily co-ordinate trades across pipelinesShippers can readily co-ordinate trades through the capacity trading platform and the day-ahead auction

Shippers can readily co-ordinate trades with other gas services on the GSH

Scale and scope benefits and adaptability:

Capable of capturing scale and scope benefits

Future proof, scalable and adaptable

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Part A: Standardisation ReformsIn the East Coast Review, the AEMC noted that the contracts underpinning primary and secondary capacity trades on transportation assets operating under the contract carriage model have historically been quite bespoke, with a range of terms and conditions customised to meet the requirements of the contracting parties. While the AEMC recognised there may be value in having customised service provisions, it recommended that the operational, prudential and other provisions governing the relationship between contracting parties and their contractual obligations in primary, secondary and operational transportation agreements be standardised. The AEMC also recommended that all trades conducted through the exchange or auction be given effect through an operational transfer and that shippers be provided with greater flexibility to change their receipt and delivery points. 25

Together, the AEMC expected these reforms to facilitate a greater level of secondary capacity trading by:26

§ making capacity products more fungible;

§ reducing search and transaction costs (i.e. by making it easier for shippers to value and compare offers and reducing the number of provisions to be negotiated); and

§ removing any unnecessary impediments to trade across pipelines.

Table A.1 provides further detail on the scope of the standardisation related reforms, which were categorised by the AEMC as either:

§ required outcomes – these recommendations were described by the AEMC as outcomes that must be progressed by the GMRG and are necessary to the implementation of the reforms; or

§ preferred outcomes – these recommendations were described by the AEMC as outcomes that should be pursued by the GMRG unless it is clear there are greater benefits in alternative approaches.

Table A.1: AEMC’s Recommendations: Standardisation related reformsRequired Outcomes

§ Trades carried out through the capacity trading platform to be given effect through an operational transfer. Bare transfers will be allowed but the seller will be required to offer the buyer the option to use an operational transfer.

§ Standardisation of key primary and secondary capacity contractual terms for pipeline and hub (compression) services. Where possible and appropriate the standards should apply across the eastern Australian gas market.

§ Standards to be developed are for key operational, prudential and other contractual provisions in primary GTAs, secondary CTAs and operational GTAs, and provisions in contracts used for exchange-based trading on the capacity trading platform.

§ Counterparties to existing contracts should not be materially disadvantaged through the standardisation process.

Preferred outcomes§ Shippers provided greater flexibility to change their receipt and delivery points.

Source: AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, p. 17.

25 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 87-92.26 ibid, p. 87.

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The GMRG commenced work on this element of the reform package in February 2017 and over the last nine months has worked closely with the Standardisation project team and its legal advisor, JWS, on the design of the standardisation related reforms.

To facilitate consultation with other stakeholders, the GMRG published a consultation paper on the standardisation reforms on 7 September 2017. This consultation paper identified a number of design options for the standardisation reforms and provided an indication of the GMRG’s preliminary view on each option. Stakeholders were given four weeks to provide written feedback on the options presented in this consultation paper and were also invited to attend a public forum in Sydney on 14 September 2017. The consultation period for this paper ended on 4 October 2017.

The stakeholders that provided written submissions on this consultation paper included AGL, Origin, EnergyAustralia, Alinta, Stanwell, APLNG, Senex, Shell, the MEU, APGA, APA, Jemena, Epic and TGP Pty Ltd. These submissions can be accessed on the GMRG website.27 Feedback on the standardisation related reforms was also provided through extensive bilateral discussions with stakeholders (including a number of consumer groups) and by the GMRG’s Advisory Panel.

In general, stakeholders were broadly supportive of this element of the capacity trading reform package and agreed with the majority of the preliminary views set out in the consultation paper. A number of specific issues were, however, raised about:

§ the way in which risk and liability will be allocated between secondary shippers and service providers under the standardised operational GTA and the governance arrangements that will apply to the Operational GTA Code; and

§ the proposed measures to reduce other barriers to secondary capacity trading, including those posed by allocation arrangements, provisions in primary GTAs and the lack of harmonisation of gas day start times and nomination cut-off times.

These issues have been considered by the GMRG in developing its final recommendations.

Table A.2 provides a high-level summary of the GMRG’s final recommendations on this element of the reform package, which have been developed having regard to the assessment framework set out in Chapter 3.

27 http://gmrg.coagenergycouncil.gov.au/publications/standardisation-related-reforms-and-capacity-trading-platform-consultation-paper

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Table A.2: Summary of the GMRG’s final recommendations on the standardisation reformsDesign Element RecommendationCapacity transfer mechanisms to be used for secondary trading

Consistent with the AEMC’s recommendations, the GMRG recommends that:§ Operational transfers be used to give effect to capacity purchases through the capacity trading platform, the day-ahead auction and bilateral trades where

the buyer elects to use an operational transfer. § Bare transfers be allowed in cases where capacity is purchased through bilateral trades, subject to the caveat that the sellers of secondary capacity offers

the buyer the option of using an operational transfer. Under both types of transfers, the primary shipper’s capacity rights (or part thereof) are temporarily transferred to the secondary shipper and the obligation to pay the service provider remains with the primary shipper. The main difference between the two mechanisms is that under an operational transfer, the secondary shipper is responsible for making nominations directly to the service provider (rather than via the primary capacity holder) and complying with the terms and conditions of access set out in the operational GTA it enters into with the service provider.

Contract standardisation

Standardisation of operational GTAsThe GMRG recommends that priority be given to standardising operational GTAs, given these contracts will be used to give effect to trades conducted through the capacity trading platform and the day-ahead auction, and will also have to be offered under bilateral trades. The standardised operational GTA will operate like a master agreement between the service provider and secondary shipper, and set out the terms and conditions on which the secondary shipper can utilise the service provider’s services if it procures secondary capacity via an operational transfer.It will be mandatory for service providers that provide third party access to publish a standard form operational GTA on their website and to offer to enter into this agreement with secondary shippers (subject to some limited qualifications and exemptions). The NGL and NGR will not, however, prohibit service providers and shippers agreeing to vary the terms, include other services in the agreement, or include the transfer mechanism in a primary GTA.The terms on which capacity is sold through the capacity trading exchange or day-ahead auction will be set out in the Exchange Agreement and the Auction Agreement. For bilateral trades, the shippers buying and selling capacity will agree terms between themselves in CTAs.

Content of the standardised operational GTA and level of standardisationThe standardised operational GTA will consist of a set of: § standard operational, prudential and other legal terms governing the relationship between the secondary shipper and the service provider that will apply to

all facilities; and§ facility specific terms, which may differ across facilities due to differences in operational or contractual arrangements. While service providers will have some discretion in relation to the facility specific terms, these terms will need to comply with a number of principles that will be set out in the NGR, the requirements set out in the Operational GTA Code (a new regulatory instrument that will set out the standard terms to be adopted by all service providers and the requirements for facility specific terms) and will also be subject to oversight by the AER.The GMRG has developed an initial draft of the Operational GTA Code, which stakeholders have provided some feedback on. The initial draft did not, however, make provision for the day-ahead auction product because the design of the auction had not been settled. The GMRG intends therefore to release another draft of the Operational GTA Code for consultation in early 2018.

Service provider costs The capacity trading reform package will impose a number of incremental establishment and capacity trading costs on service providers. The GMRG recommends that service providers have an opportunity to recover these costs, subject to the caveat that the charges are cost reflective and, so far as practical, reflect the outcomes of a workably competitive market. To impose some constraint on the charges levied by service providers, the GMRG also recommends that the AER be given the power to: § conduct a review of a service provider’s charges if it has concerns about their level (or if concerns are raised by an interested party); and § require amendments to the charges if it finds that they do not comply with the pricing principle outlined above.

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Design Element RecommendationGovernance arrangementsThe standard terms and requirements for the facility specific terms will be set out in an Operational GTA Code, which will be a new regulatory instrument developed under the NGL/NGR. Once the initial Code is made it will be subject to a hybrid governance model, which will involve the following:§ AEMO will be responsible for establishing an Industry Panel to consider changes to the Operational GTA Code and provide secretariat services to the

panel. AEMO will also be responsible for carrying out consultation on behalf of the Industry Panel and requesting input from the AEMC, where required. § Changes recommended by the Industry Panel will only take effect if approved by the AER. In deciding whether to approve the changes, the AER will be

required to take into account the panel’s recommendation (but will not be bound by it), the NGO and principles in the NGR. The AER is considered the most appropriate body to take on this role, because it is consistent with its current role in relation to approving the terms and conditions of access to covered pipelines and is not subject to the same types of conflicts that AEMO or the AEMC would be subject to. Under the proposed governance framework, the AER will also: § be responsible for monitoring service providers’ compliance with the obligation to publish the standard operational GTA and that the facility specific terms

and charges levied by service providers for entering into these arrangements, are consistent with the Operational GTA Code and NGR principles; and§ have the power to exempt a facility from the requirement to publish a standardised operational GTA (e.g. if it is not providing third party access).

Other measures to reduce barriers to secondary trading and participation in the auction

Allocation arrangements To reduce the opaqueness currently surrounding allocation agreements, information on the allocation agents a secondary shipper would need to contact to become a party to an allocation agreement at all the relevant points should be published on the BB. The GMRG also recommends that further work be carried out by the GMRG, in consultation with AEMO and industry, in early 2018 to address the allocation issues at Moomba and determine whether additional reforms are required to reduce the other barriers to trade posed by allocation arrangements. The GMRG will also work with the ACCC to determine whether any additional transparency measures are required in relation to allocation agreements.

Contractual limitations on capacity trading in primary GTAs There are a number of provisions in primary GTAs that may prevent or impede secondary trading. To ensure these do not act as a barrier to secondary capacity trading, the GMRG recommends that:§ Provisions that prohibit primary shippers from trading capacity, or require primary shippers to obtain a service provider’s consent before they can trade

capacity, be addressed through provisions that will require service providers to allow users to transfer contracted capacity to another party, without the service provider’s consent, if the user remains liable for capacity payments and the transferee has an operational GTA.

§ Provisions that prohibit primary shippers from requesting changes to receipt and delivery points, or limit the number of changes that can be requested, be addressed through provisions detailing the rights shippers have to seek changes to receipt or delivery points; the timeframes within which service providers must respond; and the pricing principle to apply to charges levied by the service provider for these changes (i.e. charges should be cost reflective and reflect the outcomes of a workably competitive market).

The provisions are expected to draw on the approach in rules 105(2) and 106(1) of the NGR, which apply in relation to scheme pipelines.

Harmonisation of gas day start times and nomination cut-off times To remove the barriers to trade posed by differences in gas day start times and nomination cut-off times, the GMRG recommends that changes be made to the NGL/NGR to require the adoption of: § a common gas day start time of 6 am (AEST) across the east coast (and the Northern Territory once it becomes connected) that will apply to the operators

of all production, pipeline, compressor and storage facilities; and§ a common nomination cut-off time of 3 pm (AEST) for pipelines and other facilities that will be subject to the capacity trading reforms.The GMRG recommends these changes take effect by 1 October 2019.

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In the GMRG’s view, the recommendations set out in Table A.2 will facilitate a greater level of secondary capacity trading by:

§ making capacity products more fungible and providing secondary shippers with access to secondary capacity on reasonable terms;

§ removing other impediments to trade, including restraints on secondary capacity trading, restrictions on receipt and delivery point flexibility and differences in gas day start times and nomination cut-off times;

§ reducing search and transaction costs through the development of the standardised operational GTA; and

§ instilling a greater level of confidence in the secondary capacity market through the implementation of robust governance arrangements for the standardisation reforms.

The GMRG is also satisfied that the recommendations in this table:

§ appropriately reflect the legitimate business interests of service providers and other parties that have rights to use the transportation services;

§ are operationally feasible and recognise the operational and technical requirements necessary for the safe and reliable operation of the transportation assets; and

§ will facilitate the efficient operation and use of the capacity trading platform and day-ahead auction.

The recommendations can therefore be expected to contribute to the broader objective of the capacity trading reforms, which is to improve the efficiency with which transportation capacity is allocated and utilised and foster the development of a more liquid market for secondary capacity. They will also contribute to the Energy Council’s Vision of the direction gas market development should take and a number of the outcomes set out in (i.e. 2(b) and 3(b)). The GMRG is therefore satisfied that the recommendations will contribute to the achievement of the NGO.

The remainder of this part of the report provides further detail on the GMRG’s final recommendations on the standardisation related reforms and the feedback stakeholders provided in response to the consultation paper.

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4. Standardisation of ContractsTo facilitate a greater level of trade in secondary capacity, the AEMC recommended that capacity trades conducted through the exchange and auction be given effect through an operational transfer and that key terms and conditions in primary, secondary and operational transportation agreements be standardised.28

The GMRG has worked with the Standardisation project team, its legal advisor, JWS, and other stakeholders on these issues when developing its final recommendations. In doing so, the GMRG has considered:

§ the types of contracts that should be standardised;

§ the level of standardisation that can be achieved and the form of standardised provisions;

§ whether the standardised terms should be voluntary or mandatory;

§ the governance arrangements that could apply to the standardised contracts; and

§ how service providers will recover the costs associated with these reforms.

These issues are discussed, in turn, in the remainder of this chapter, which commences with an overview of the AEMC’s recommendations.

4.1 AEMC recommendations In the East Coast Review, the AEMC recommended that:

§ operational transfers be used to give effect to capacity purchased through the capacity trading exchange and the day-ahead auction; and

§ bare transfers be allowed in cases where capacity is purchased through bilateral trades, subject to the caveat that the sellers of secondary capacity must offer the buyer the option of using an operational transfer.

In making this recommendation, the AEMC noted that operational transfers will:29

§ provide secondary shippers greater anonymity in terms of nominations and its use of the pipeline, which may encourage more trade; and

§ alleviate primary shippers of the costs that it would otherwise incur in administering the trade and monitoring the secondary shipper’s compliance with various obligations, which should encourage more primary shippers to sell any spare capacity they have.

Further detail on operational and bare transfers can be found in Box 2.2.

The AEMC also recommended that the operational, prudential and other contractual provisions governing the relationship between the contracting parties and their contractual obligations in primary GTAs, operational GTAs and secondary capacity agreements be standardised (see Box 4.4 for more detail on contract terms). However, in response to feedback provided by a number of stakeholders in the East Coast Review, the AEMC

28 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 85-86.29 AEMC, Pipeline Capacity Discussion Paper, 3 March 2016, p.20.

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noted that it may be appropriate to prioritise the standardisation of operational GTAs and secondary capacity agreements (i.e. CTAs, the Exchange Agreement and Auction Agreement).

Elaborating further on this recommendation, the AEMC noted that, with the exception of the exchange-based capacity trading and auction products, it did not expect the service related provisions in transportation contracts to be standardised. It did, however, think there would be value in making capacity more fungible and reducing search and transaction costs by standardising the operational, prudential and other contract provisions.30 At a minimum, the AEMC expected common standards to be developed for the provisions governing the relationships between contracting parties and their contractual obligations, and many of the operational provisions. It did, however, acknowledge that it may be more difficult to develop common standards for more technical provisions, such as imbalance and overrun allowances, because these can depend on the physical characteristics and operating conditions of the pipeline.31

Box 4.4: Contract terms

A capacity holder’s right to access pipeline or compression capacity will usually be defined by reference to the service related elements, which include: § the type of service that the capacity is to be used for (e.g. transportation services (forward

haul, backhaul or bi-directional), stand-alone compression services or storage services); § the firmness of the seller’s obligation to provide the service (e.g. firm, as available or

interruptible) and the priority in scheduling and curtailment; § the receipt and delivery points (or zones) that services are provided between and any

technical restrictions at those points (e.g. operating pressures); and § the maximum capacity the shipper can nominate to be supplied at receipt and delivery

points, which is usually measured on a daily and hourly basis, and renomination rights. The contracts will also contain: § operational terms and conditions, such as:

(a) start of gas day and nomination cut-off times; (b) gas specification, gas quality and metering provisions; (c) service definition and the priority accorded to firm, as available and interruptible

services in the scheduling and curtailment processes; (d) nomination, scheduling, curtailment and allocation procedures; (e) imbalance and overrun tolerance levels and charges; (f) the process for making changes to receipt and delivery points; and (g) provisions relating to transfers, assignments and novations of capacity.

§ prudential requirements; and § other contract provisions governing the relationships and contractual obligations between

parties, such as warranties, representations, possession, responsibility, title, control, liability and indemnities, default, force majeure, confidentiality and dispute resolution.

Source: AEMC, Pipeline Access Discussion Paper, 3 March 2016, p. 12.

Some of the other matters that the AEMC recommended the GMRG consider in this context include whether:32

30 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 85-86. 31 ibid, p. 89.32 ibid, p. 90.

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§ a single standard can be developed for each term and condition, or if a range of standards may be more appropriate in some circumstances;

§ a credit support mechanism should be developed to manage the risk to one counterparty when the other counterparty has low credit worthiness because this would no longer be managed through bespoke prudential requirements;

§ the adoption of the standardised terms should be compulsory, or if shippers and pipelines should be able to negotiate around any provisions; and

§ changes to the functions and powers of the AEMC, AER or AEMO and/or whether changes to the NGL, the NGR or subordinate instruments would be required to give effect to the standardised terms and what, if any, governance arrangements would need to be implemented to enable the standards to be amended over time.

4.2 Contracts to be standardised

BackgroundOne of the first issues the Standardisation project team considered was whether it was necessary to standardise both primary GTAs and operational GTAs to make capacity more fungible and reduce search and transaction costs.

In short, the Standardisation project team was of the view that if operational transfers are to become the primary means by which capacity trades are given effect, then it may be sufficient to standardise operational GTAs because any capacity released by the primary shipper would be subject to the terms in the operational GTA rather than the primary GTA. The project team decided therefore to prioritise the standardisation of the operational GTA and to only consider amending primary GTAs where it was necessary to give effect to operational GTAs or to facilitate secondary trading.

The position the project team reached on this issue is consistent with the feedback that other stakeholders provided during the East Coast Review. It is also consistent with the following observation that the AEMC made in one of its initial discussion papers: 33

“For trades that are given effect through an operational transfer there may be less of a need to align the primary capacity holder’s GTA and the CTA because the Operational GTA will set out the operational and many of the other contractual provisions that apply to the trade ... That is not to say that some degree of standardisation would not be required in the CTAs and Operational GTAs, in order to facilitate a more liquid secondary capacity trading market. It is just that the terms and conditions in the Operational GTA do not necessarily need to align with the primary capacity holder’s GTA.”

The project team also observed that while standardisation of primary GTAs was not required to achieve the AEMC’s objectives, the standards developed for the operational, prudential and other legal provisions in the operational GTA may drive the standardisation of primary GTAs over time.

In relation to CTAs, the project team noted that AEMO has already developed a standardised CTA for bilateral trades that are given effect through a bare transfer34 and that there would be little value in carrying out further work to standardise these types of contracts because:

33 AEMC, Pipeline Capacity Discussion Paper, 3 March 2016, p.20.34 See https://www.aemo.com.au/Gas/Gas-Supply-Hubs/Market-operations

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§ secondary shippers would always have the option to use an operational transfer so any standardised CTA would only need to set out the details of the capacity being sold and the financial terms of the sale between the primary shipper and the secondary shipper, which would be trade specific; and

§ if the secondary shipper decided to proceed with a bare transfer, the terms in the CTA would in most cases need to mirror those in the primary shipper’s GTA to minimise its risk exposure.

GMRG’s preliminary view

In the consultation paper, the GMRG agreed with the project team that priority should be given to developing a standardised operational GTA, given that all trades conducted through the exchange and day-ahead auction would need to be given effect through an operational transfer and secondary shippers must be offered this option in bilateral trades. The GMRG also noted that there was likely to be little value in standardising primary GTAs and CTAs that use a bare transfer mechanism, if operational transfers become the primary means by which trades are conducted. The GMRG did, however, note that some changes to primary GTAs may be necessary to accommodate secondary trading.

Feedback provided through the consultation process

Stakeholders generally supported the GMRG’s preliminary view, with most submissions agreeing that:

§ priority should be given to standardising operational GTAs; and

§ there is likely to be little value in standardising primary GTAs or CTAs that use a bare transfer mechanism to facilitate secondary capacity trading.

Alinta did, however, suggest that there may be value in developing a standardised operational mechanism that can be included in primary GTAs. Senex and APLNG also noted that while standardisation of primary GTAs may not be required to facilitate secondary trade, there may still be value in standardising these contracts in the future. Shell also indicated that there may be value in revisiting this issue following a review of the operation of the reforms. Stanwell, on the other hand, thought that the standards developed for the operational GTA would drive the standardisation of primary GTAs over time. In contrast to these positions, AGL, Origin, Jemena, Epic, TGP Pty Ltd and APA, were of the view that the standardisation of primary GTAs is unnecessary and could result in a loss of flexibility for shippers.

GMRG’s final recommendations The GMRG has considered the feedback provided by stakeholders and remains of the view that:

§ Priority should be given to developing a standardised operational GTA given that all trades conducted through the exchange and day-ahead auction will be given effect through an operational transfer and secondary shippers will need to be offered the option of using an operational transfer.

§ There is little value in standardising primary GTAs if operational transfers become the primary means by which trades are conducted, but some changes to primary GTAs will be necessary to accommodate secondary trading and/or facilitate the operation of the trading platform and/or auction.

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§ There is little value in carrying out further work on developing a standardised CTA that uses a bare transfer mechanism. Standardised terms will, however, be available for trades conducted through the capacity trading platform and the day-ahead auction and for bilateral trades that use the operational transfer mechanism.

The GMRG’s final recommendation is therefore that operational GTAs be standardised and that, to the extent necessary, primary GTAs be amended to accommodate secondary trading and/or facilitate the operation of the trading platform and/or auction.35

While the GMRG does not think the standardisation of primary GTAs is necessary to facilitate secondary trading, there may, as some stakeholders have suggested, be value in considering this in the future if there are concerns about the terms on which access is provided to primary capacity.

4.3 Standardisation of the operational GTA

Background The GMRG has worked with the Standardisation project team and its legal advisor, JWS, to develop the key elements of the standardised operational GTA that will establish the contractual terms between secondary shippers and service providers for capacity procured through the capacity trading platform, day-ahead auction or bilaterally if an operational transfer is used. Through this process it was established that the operational GTA would need to include both:

§ standard terms that will apply to all transportation assets; and

§ facility specific terms that may differ across service providers or facilities (e.g. pipeline or compression assets) as a result of differences in:

o the operational characteristics of the facility (for example, hourly limitations, pressure, temperature and metering requirements); and

o the contractual arrangements of the facility (for example, differences in the prioritisation principles that apply to scheduling and curtailment).36

GMRG’s preliminary viewIn the consultation paper, the GMRG agreed with the project team that the standardised operational GTA would need to include both standard and facility specific terms. The

35 Changes to primary GTAs may, for example, be required to:§ allow the primary shipper’s capacity to be transferred to another shipper via an operational transfer;§ introduce the concepts of contract and operational MDQ and allow the primary shipper’s operational

MDQ to be adjusted when a trade occurs;§ recognise that if capacity is traded through an operational GTA the primary shipper will remain

liable to pay the tariff for the contract MDQ but the liability to pay any imbalance or overrun charges on the transferred capacity and all the other obligations and liabilities set out in the operational GTA will move to the secondary shipper;

§ the harmonisation of gas day start times and nomination cut-off times when it occurs; § the adoption of zones and primary/secondary receipt and delivery point concepts. and§ amend service priorities.

36 In this case, if the operational GTA had different prioritisation principles to those set out in primary GTAs and if there was a curtailment event the service provider may have inconsistent contractual obligations to primary shippers from those to secondary shippers and be in breach of its contracts.

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GMRG also proposed the development of a new regulatory instrument, the Operational GTA Code, which service providers would have to have regard to when developing their standard form operational GTA and would set out:

§ the standard terms to be adopted by all service providers;

§ the requirements for the facility specific terms; and

§ the form of agreement allowing these two elements of the operational GTA to be incorporated into a binding contract.

The GMRG also set out its preliminary views on the form the standard terms and the facility specific requirements should take, which were reflected in a draft Operational GTA Code that was published with the consultation paper.

While the GMRG recognised the need to include facility specific terms in the standardised operational GTA, it noted the potential for these terms to be used to impede trade because:

§ service providers’ interests in facilitating secondary capacity trades may not be closely aligned with the interests of shippers that want to trade capacity; and

§ service providers will face no competition for the provision of operational transfer services.

The GMRG therefore suggested the following measures be used to limit the discretion service providers have in relation to facility specific terms:

§ service providers should be required to comply with the facility specific requirements in the Operational GTA Code and a number of guiding principles in the NGR when developing these terms; and

§ the AER should be able to monitor the compliance of a service provider’s facility specific terms with the requirements in the Operational GTA Code and the principles in the NGR.

The principles the GMRG suggested could be included in the NGR to guide the development of facility specific terms were as follows:(a) An overriding requirement that the facility specific terms be reasonable, which is to be

assessed having regard to the terms that would be negotiated in a workably competitive market.

(b) A requirement that, where applicable, facility specific terms, must be consistent with the terms of an Access Arrangement (AA) for the pipeline or an AA for another transmission pipeline equivalent in nature to the pipeline and not impose obligations, requirements or other limitations on the secondary shipper’s rights that are more restrictive than those in the AA.

(c) Provision for the reasonableness of a facility specific term to be assessed by reference to the terms on which the services are available to other primary and secondary shippers and industry practice. This would be qualified where pipelines have foundation shipper37 contracts containing provisions that no longer represent current contracting practice on the pipeline.

37 Foundation shippers are those who funded the construction of a pipeline (or part thereof) either by direct contributions or by signing up as the original shippers to the pipeline. In consideration of this contribution and the risk they take, foundation shippers are often granted special rights.

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(d) A requirement that, except where expressly permitted by the standard terms or where required to comply with a law or undertaking given to the Crown or a regulator, facility specific terms may not vary the standard terms.

Feedback provided through the consultation processIn the consultation paper, stakeholders were asked to provide their views on the standard terms and facility specific requirements set out in the draft Operational GTA Code and the governance arrangements to apply to facility specific terms. An overview of the feedback that stakeholders provided on these two matters is set out below.

Draft Operational GTA Code

The majority of stakeholders that provided feedback on the draft Operational GTA Code were supportive of the general approach that had been taken and the delineation between standard terms and facility specific requirements. There were, however, some exceptions to this:

§ Jemena, for example, did not believe that a standard operational GTA was required for the entire east coast and suggested that a better approach would have been to require service providers to offer standard operational GTAs for their respective assets. APA stated that the level of standardisation proposed in the Operational GTA Code went beyond what was required to facilitate more secondary trading. The MEU, on the other hand, thought it was essential for standardisation to occur across the east coast and for facility specific provisions to be minimised to enable shippers to enter into trades across a number of pipelines and compression services (irrespective of ownership) without a loss of continuity.

§ APGA was of the view that the facility specific requirements were too prescriptive and that the Operational GTA Code should just set out a descriptor list for each term to be covered in each facility’s operational GTA. Senex, on the other hand, thought that further standardisation would be desirable and that more detail was required, particularly in relation to facility specific terms. APLNG also indicated that some of the facility specific terms, such as the imbalance arrangements, could be standardised.

In the consultation paper, stakeholders were asked to provide specific feedback on the proposed drafting of the following provisions:

§ the liability provisions relating to off-specification gas;

§ the general liability provisions;

§ the credit support requirements; and

§ the imbalance management provisions.

able 4.7 provides a summary of stakeholder views on these provisions. As this table highlights, stakeholders were divided on a number of these provisions, particularly in relation to the way in which risks and liabilities are assumed to be allocated between service providers and secondary shippers and the credit support requirements.

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Table 4.7: Feedback on specific provisionsLi

abili

ty fo

r off-

spec

ifica

tion

gas

Preliminary view The standard terms in the draft Operational GTA Code provided for:§ Secondary shippers to indemnify the service provider against the losses the service provider suffers due to supply of off-specification gas,

excluding losses the service provider would have avoided had the service provider acted as a reasonable and prudent operator. § Service providers to only be liable for delivering off-specification gas at a delivery point where the service provider agreed to accept off-

specification gas into the pipeline from another shipper, or where the service provider could, as a reasonable and prudent operator, have avoided delivering off-specification gas to the secondary shipper.

Feedback on secondary shipper’s liability for off-specification gas

Shippers and service providers views divided on the liability that secondary shippers should have in relation to off-specification gas with:§ service providers suggesting that there should not be a cap on the secondary shipper’s liability and in some cases that liability should extend to

consequential losses (APGA, Jemena, APA and TGP Pty Ltd stated that liability should extend to consequential losses while Epic was satisfied with the proposed drafting) – the submissions from service providers noted that this reflects current practice and that allocating this risk to service providers would be inappropriate because they do not have a contractual relationship with producers; and

§ shippers suggesting that liability should be capped and/or limited to direct losses (AGL, EnergyAustralia and Shell proposed a cap and limitation of liability to direct loss, APLNG proposed a limitation to direct loss and Senex proposed a standard cap of $20 million covering direct and consequential loss) – the submissions from shippers noted that these limitations were required to ensure that this does not act as a barrier to trade and that limitations were consistent with what applies under some GTAs and gas supply agreements.

Feedback on service provider’s liability for off-specification gas

Mixed views were expressed about the liability service providers should have in relation to off-specification gas, with:§ A number of shippers suggested that service providers should have a reciprocal level of liability for off-specification gas (AGL, Senex, Shell and

APLNG), while EnergyAustralia did not think this was appropriate if it was not the service provider’s fault.§ Service providers agreeing with the approach set out in the draft Operational GTA Code.

Gen

eral

liab

ility

Preliminary View The standard terms in the draft Operational GTA Code provided for the following in relation to general liability:§ Secondary shippers – no proposed limits on liability for secondary shippers with the exception that, other than in the case of the secondary

shipper’s wilful misconduct (and potentially liability for the supply of off-specification gas) the secondary shipper is not liable for the service provider’s loss of profits or revenue; and

§ Service providers – except in the case of wilful misconduct, the service provider’s liability is capped at a monetary amount and the service provider is not liable for the secondary shipper’s consequential losses.

Feedback on service provider’s liability

Most stakeholders agreed that a service provider’s liability should be capped, but differing views were expressed on the level of the cap. For example, AGL thought the cap should be a function of the face value of the transaction; Shell suggested the limits be mutual and set at $5 million per event; Senex proposed a standard cap of $20 million; APA suggested the cap be set at 10% of the charges paid by the user. APLNG, on the other hand, suggested there be no monetary cap, but consequential loss should be excluded.

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Table 4.7: Feedback on specific provisions

Feedback on secondary shipper’s liability

Shippers and service providers views were divided on the general liability that secondary shippers should have with:§ Shippers claiming that uncapped liability will act as a barrier to entry and should therefore be capped. Shippers expressed differing views though

on the level of the cap and whether it should be limited to direct losses. For example: AGL suggested the cap be expressed as a function of the face value of the transaction; EnergyAustralia suggested the cap be based on the percentage of value of the remaining contract; Shell suggested a monetary cap and limitation of liability to direct losses; Senex suggested a standard cap of $20 million; APLNG suggested a monetary cap and proposed a limitation to direct loss; and

§ Service providers generally comfortable with the proposed approach in the draft Operational GTA Code, subject to some caveats. Jemena also stated that it is common in competitive markets for a service provider’s liability to be limited, but not that of the shipper. APA also stated that it was speculative whether these arrangements would act as a barrier to entry.

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uppo

rt

Preliminary View The standard terms in the draft Operational GTA Code provided for:§ secondary shippers to have appropriate third party public and product liability insurance; and§ service providers to require credit support from the secondary shipper if the shipper’s credit rating (either directly or indirectly through a guarantee)

is lower than BBB-, with the amount of credit support to be calculated as 60 days x tradable Maximum Daily Quantity (MDQ) (agreed to by the service provider and secondary shipper) x firm tariff.

Feedback on credit rating

While shippers agreed that a credit rating threshold of BBB- was appropriate, a number of service providers opposed its use. APA, for example, suggested that service providers should be able to determine the credit support requirements in the same way they do with primary shippers and noted that a decline in credit rating may lag a deterioration in the shipper’s position. Jemena noted that BBB- was a minimum acceptable rating and that it would usually look at a broad range of factors when assessing the suitability of a shipper. Epic indicated that the requirement to assess whether a shipper had financial substance equivalent to a BBB- rating was too onerous.

Feedback on level of credit support

Most stakeholders were comfortable with the formulaic approach to calculating the level of credit support but a number of shippers stated that the amount of credit support should not be equal to 100% of the face value of the MDQ and suggested that: § a percentage of 20-40% may be more appropriate (AGL, EnergyAustralia);§ the percentage be based on the proportion of the revenue imbalance and overrun charges typically accounted for (Alinta); or§ the percentage should be based on the proportion of MDQ that is being used (Senex). Other shippers, on the other hand, were comfortable with the formula in the draft Operational GTA Code. A number of shippers also noted that the higher the level of credit support, the more likely it was to act as a barrier to entry. AGL also noted that credit support should be designed to cover charges such as imbalance and overrun charges and not to deal with risks such as off-specification gas.APA and APGA, on the other hand, suggested that the quantum of credit support should be up to the service provider and the standard terms should just require the service provider to act reasonably and consistently with primary shipper practice. Jemena also noted that the proposed levels of credit support did not adequately replace the ability to choose who will have access to the infrastructure.

Imba

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Preliminary view The standard terms in the draft Operational GTA Code provided for imbalances to be managed through an imbalance trade. Stakeholders were, however, asked whether there would be value in allowing service providers the option to offer either imbalance trading or an in-pipe trading, or if in-pipe trading should be the standard position rather than imbalance trades.

Feedback Stakeholders agreed that imbalance trading and in-pipe trades can be used to achieve the same outcome, but expressed a range of views on the mechanism that should be included in the draft Operational GTA Code, with: § AGL, Jemena and APA stating that the mechanism should reflect the standard mechanism available to all shippers using the pipeline; § Senex and Epic stating that service providers should have the option to offer one or the other; and§ APLNG stating that the standard terms should offer the most efficient option.

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In addition to providing feedback on the provisions set out above, a number of stakeholders also provided feedback on a range of other standard terms and facility specific requirements, which the GMRG intends to take into account in developing the next draft of the Operational GTA Code early in 2018.

Governance arrangements applying to the facility specific provisions

Stakeholder feedback provided in relation to the facility specific provisions centred on:

§ the principles to be included in the NGR that service providers would be required to have regard to when developing the facility specific terms; and

§ the role of the AER.

In relation to the principles, the majority of stakeholders supported the inclusion of the overriding principle that facility specific terms be reasonable and the requirement that facility specific terms not vary the standard terms. There was, however, some debate about whether the principles should require:

§ the facility specific terms to be consistent with the terms set out in AAs: While this proposal was supported by EnergyAustralia, Shell and APA, it was opposed by a number of other stakeholders, including:

o AGL who stated that the reliance on AAs could have unintended consequences.

o APLNG who stated that AAs may not be the best reference point to assess the reasonableness of terms and that primary GTAs (excluding foundation contracts) and secondary GTAs would be a better reference point.

o Epic who stated that utilisation of prior AAs or an AA for an equivalent pipeline would introduce increased complexity into the operation of the pipeline by introducing new operational requirements that are inconsistent with standard operational procedures.

o Jemena who stated that the application of an AA for an equivalent pipeline would have the effect of applying coverage to unregulated pipelines.

§ the reasonableness of facility specific terms to be assessed by reference to the terms on which services are available to primary shippers (excluding foundation contracts): This proposal was supported by AGL, EnergyAustralia, APLNG, Shell and Epic, but opposed by Jemena, who noted that primary shippers should be able to retain preferential terms relative to secondary shippers. APA, on the other hand, agreed that primary GTAs could be an appropriate reference point, but did not think a carve-out for foundation shipper contracts was required. APA also noted that the reference to industry practice should be sufficient to direct decision making towards modern contracts.

Stakeholders were also divided on whether the AER should monitor the compliance of the facility specific terms with the Operational GTA Code and NGR principles. For example:

§ AGL was of the view that this type of oversight is unnecessary and stated that shippers should be able to have recourse to contractual remedies if service providers act outside their contractual bounds.

§ EnergyAustralia and APA thought the AER should have a compliance monitoring role.

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§ Jemena, APLNG and Epic were of the view that the AER should have a compliance monitoring role but that it should only be triggered by a customer complaint, or if there was a valid reason.

GMRG’s final recommendation

The GMRG has considered the feedback provided by stakeholders, but remains of the view that service providers should, subject to the exemptions outlined in section 4.4, be required to develop a standardised operational GTA for each asset, which will consist of a set of:

§ standard terms that will apply to all transportation assets; and

§ facility specific terms, which may differ across service providers or facilities due to differences in the operational characteristics of the facility or the contractual arrangements of the facility.

While service providers will have some discretion in relation to the facility specific terms, these terms will need to comply with:

§ the facility specific requirements set out in the Operational GTA Code; and

§ the following principles, which will be set out in the NGR:

a. An overriding requirement that the facility specific terms be reasonable, which is to be assessed having regard to the terms that would be negotiated in a workably competitive market.

b. A requirement that if a pipeline is subject to full regulation then, where applicable, the facility specific terms, must be consistent with the terms of the approved Access Arrangement (AA) for that pipeline and not impose obligations, requirements or other limitations on the secondary shipper’s rights that are more restrictive than those in the AA.

c. Provision for the reasonableness of a facility specific term to be assessed by reference to the terms on which the services are available to other primary and secondary shippers and industry practice. This would be qualified where pipelines have foundation shipper38 contracts containing provisions that no longer represent current contracting practice on the pipeline.

d. A requirement that, except where expressly permitted by the standard terms or where required to comply with a law or undertaking given to the Crown or a regulator, facility specific terms may not vary the standard terms.

The second of these principles has been amended in response to stakeholder feedback and now only requires the facility specific terms to comply with the terms in an AA if the pipeline is subject to full regulation and there is an approved AA in place. If the pipeline is not subject to full regulation, then it will not be required to comply with this principle. The third principle, on the other hand, has not been amended because in the GMRG’s view it is relevant to assess the reasonableness of the terms and conditions of access having regard to the terms and conditions applying to both

38 Foundation shippers are those who funded the construction of a pipeline (or part thereof) either by direct contributions or by signing up as the original shippers to the pipeline. In consideration of this contribution and the risk they take, foundation shippers are often granted special rights.

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primary and secondary shippers and to expressly exclude foundation contracts from this assessment.

The AER will also have the power to conduct a review of a service provider’s facility specific terms if it has any concerns about the terms that have been adopted (or if bona fide concerns are raised by interested parties) and to require amendments if it finds they are inconsistent with the requirements in the Operational GTA Code and/or the principles set out in the NGR.

In the GMRG’s view, these measures are required because:

§ service providers’ interests in facilitating secondary capacity trades may not be closely aligned with the interests of shippers that want to trade capacity; and

§ service providers will face no competition for the provision of operational transfer services.

Facility specific terms could therefore be used to impede trade if service providers were provided unfettered discretion in this area.

In relation to the feedback provided on specific provisions in the draft Operational GTA Code, the GMRG intends to take this into account when developing the next draft of the Operational GTA Code, which will be released for consultation in early 2018. The next draft will also include the provisions required to accommodate the day-ahead auction product and stand-alone compression services.

4.4 Application of the standardised operational GTA

Background

In developing the standardised terms, the AEMC suggested the GMRG consider whether all of the terms should be mandatory, or if shippers and service providers should have the option to negotiate some of the terms and conditions. This issue was discussed with the Standardisation project team, which made the following observations:

§ It needs to be clear whether the negotiate/arbitrate framework in Part 23 of the NGR applies to the standardised terms. If it does, service providers would be required to negotiate within that framework. If it does not, negotiation would be discretionary.

§ Secondary shippers seeking an operational GTA on the standardised terms should not be required or expected to negotiate with service providers before the agreement is entered into.

§ Negotiations will be required if other services are to be added to the operational GTA. However, it will not be mandatory for other services to be provided under the operational GTA and a different form of agreement could be used for those services.

§ There may be value in allowing shippers that have a primary GTA to negotiate to include an operational transfer mechanism in their primary GTA, so that any purchases of secondary capacity can be added to this contract rather than a separate operational GTA.39

39 The main benefits of this option that were cited by these project team members were that it would: allow shippers to access the capacity on the operational, prudential and other contract terms set out

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§ Some qualifications or exceptions to the obligation to offer a standard form operational GTA will be required.


The GMRG’s preliminary view on this issue was that it be mandatory for service providers that provide third party access to:

§ publish a standard form operational GTA that complies with the Operational GTA Code and principles in the NGR; and

§ offer to enter into this agreement with secondary shippers, subject to some limitations.

The GMRG also proposed that:

§ the standard terms be excluded from the negotiation and arbitration framework in Part 23 of the NGR, but if ‘Other Services’ are offered then the negotiation of these services would be subject to Part 23; and

§ the NGL/NGR should not prohibit service providers and shippers from agreeing to terms negotiated between them (including to agree to incorporate an operational transfer mechanism in their primary GTA).

The GMRG also noted that the capacity trading platform and auction should be designed, operated and developed on the assumption that standard form operational GTAs are used to deliver all trades. Individual requirements arising out of negotiated operational GTAs or the use of primary GTAs would therefore be for the shipper and the service provider to manage and AEMO would not be required to look into the specific terms and conditions of the contract being used.


Stakeholders did not raise any specific objections to the proposal to require service providers that are providing third party access to publish a standard form operational GTA on their website or to offer to enter into this agreement with secondary shippers. A number of stakeholders did, however, suggest the adoption of additional:

§ exemptions from the obligation to publish and enter into standard form operational GTAs – for example:

o Jemena suggested that the obligation to publish a standard form operational GTA should only apply to pipelines and services that are traded on the capacity trading platform and auction and should not extend to pipelines servicing a single user.

o APA indicated that the exemptions in Part 23 of the NGR may be appropriate.

§ limitations on the obligation to offer to enter into agreements – for example:

o Epic suggested that the obligation to offer to enter into an operational GTA not extend to secondary shippers that are not registered GSH members, or shippers that have previously breached the operational GTA.

in their primary GTA; minimise the number of contracts that secondary shippers and service providers have to manage, although it was noted that primary and secondary capacity would still need to be distinguished in the service provider’s system; and limit the number of trading right numbers (TRN) that shippers using the Short Term Trading Market (STTM) have to manage.

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o APA suggested that the obligation to offer to enter into an operational GTA not extend to shippers that cannot demonstrate they have the technical and financial capability to meet their contractual obligations.

o EnergyAustralia suggested that the obligation to offer to enter into an operational GTA should not apply if the shipper fails the ‘Know Your Customer’ test, which is used to assess the compliance of companies with anti-money laundering, anti-bribery and anti-corruption regulations.

The majority of stakeholders were of the view that service providers and secondary shippers should be able to:

§ agree to different terms and conditions than those specified in the operational GTA – the exceptions to this were EnergyAustralia and Epic who did not think this was appropriate for the operational GTA; and

§ agree to include the operational transfer mechanism in a primary GTA, although there was some debate about whether this should just be left to negotiations between the parties, or if service providers should:

o be required to allow this to occur if requested by the shipper (or not unreasonably withhold their consent) (AGL, EnergyAustralia and Alinta); or

o have the discretion to determine whether to allow this to occur if requested by the shipper (Epic).

GMRG’s final recommendations

Service provider obligations

In keeping with the feedback provided by stakeholders and the assessment framework set out in Chapter 3, the GMRG recommends that provisions be included in the NGL and NGR to require service providers that are not subject to an exemption to:

§ publish a standard form operational GTA on their website that incorporates the standard terms and facility specific terms for each facility and complies with the Operational GTA Code and principles in the NGR; and

§ offer to enter into the standard form operational GTA on request by a shipper, for one or more facilities as selected by the shipper, subject to the conditions and limitations specified in the operational GTA40 and/or the NGR.

The GMRG also recommends that these obligations be classified as civil penalty provisions in the regulations made under the NGL and that, consistent with the role it plays in other markets, the AER:

§ be responsible for monitoring the service provider’s compliance with the obligation to publish the standard operational GTA and that the facility specific terms are consistent with the Operational GTA Code and the principles applicable to the facility specific terms in the NGR; and

§ have the power to exempt a pipeline (or other facility) from the regime if it meets the exemption criteria set out in the NGR.

40 The standard terms in the operational GTA are likely to state that services will not start until conditions are met, such as the provision of credit support.

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These functions and powers will need to be reflected in the NGL and NGR.

Consistent with the position taken in other areas of the capacity trading reform package, the GMRG recommends that exemptions be available to service providers if the pipeline or compression facility they operate:

§ does not provide third party access; or

§ services a single facility.

These exemptions will be set out in the NGR, which will also provide for exemptions to be extinguished by the AER in the event conditions change.

The GMRG has proposed these exemptions because it is unlikely that any secondary capacity trading will occur on transportation assets that are servicing a single facility or are not providing third party access. There would therefore be no benefit in requiring the service providers of these facilities to prepare a standardised operational GTA.

The NGR will also specify the limitations on the service provider’s obligation to offer to enter into the standard form operational GTA. While the GMRG can see merit in some of the suggestions that have been made by Epic and EnergyAustralia, it does not think the technical competence qualification proposed by APA is required and notes that financial competence will be dealt with through the credit support requirements in the operational GTA. The GMRG intends to consult with stakeholders further upon the scope of the limitations in early 2018 when it develops the draft initial Rules.

Ability to negotiate

The GMRG has considered the issues stakeholders have raised about the ability to negotiate alternative terms to the standard form operational GTA and agrees with the majority of stakeholders that service providers and shippers should not be prevented from negotiating alternative terms, which could occur if:

§ the shipper wants to acquire ‘Other Services’ through the operational GTA; or

§ the shipper wants to incorporate an operational transfer mechanism into its primary GTA.

The GMRG understands that in the latter of these cases, shippers would prefer that service providers be required to include the operational transfer mechanism in a primary GTA if requested by the shipper. However, it is important to recognise that the inclusion of this mechanism in the primary GTA may allow the shipper to access the capacity on more flexible terms than what they are paying the service provider for.41 While this issue could be overcome by including a standardised operational transfer mechanism into primary GTAs as proposed by Alinta, the GMRG understands there may be other cases where it is mutually beneficial to the service provider and shipper to leverage existing provisions in a primary GTA. The GMRG is therefore of the view that service providers and shippers should be able to negotiate the inclusion of the transfer mechanism in primary GTAs, but it should not be compulsory for service providers to allow this to occur.

41 For example, if the primary GTA had a relatively high maximum hourly quantity (MHQ) factor or a generous imbalance regime, then the application of these terms to capacity purchased through the trading platform could impose costs on service providers that they are not compensated for.

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For the reasons set out above, the GMRG recommends that the NGL and NGR not prohibit service providers and shippers from agreeing to terms negotiated between them. The GMRG also recommends that standard terms in operational GTAs be excluded from the negotiation and arbitration framework in Part 23 of the NGR if they mirror the provisions in the Operational GTA Code. However, if ‘Other Services’ are offered then the negotiation of these services would be subject to Part 23.

Whether in standard form or with negotiated changes, operational GTAs will be governed by usual principles of contract law and enforceable as a contract by the parties. They will not have any status as a regulatory instrument.

4.5 Cost recovery for provision of operational transfer services

Background

The use of operational transfers and the capacity trading platform will impose a number of incremental costs on service providers. Service providers will, for example, incur the following types of costs:

(1) establishment costs – this category of costs include the incremental costs that service providers will incur entering into operational GTAs with secondary shippers that want to use the capacity trading platform and/or day-ahead auction and setting the secondary shippers up in their systems;

(2) capacity trading costs – this category of costs includes the incremental:

a. system and communication costs that service providers incur:

o receiving information from AEMO about any trades conducted through the platform and providing AEMO with any confirmations it may require; and

o automating their systems to deal with the information that needs to be provided to and received from AEMO; and

b. trading related costs that service providers incur:

o adjusting primary and secondary shippers’ operational MDQ when trades occur; and

o managing the secondary shipper’s nominations, allocations and billing for overrun and imbalance charges.

No guidance was provided in the East Coast Review on:

§ who should bear the establishment and capacity trading costs;

§ the cost recovery mechanism that should be used by service providers; or

§ whether there should be any oversight of the costs recovered by service providers.

The options that the Standardisation project team considered and the views that they expressed on each option are summarised in Table 4.8.

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Table 4.8: Cost recovery optionsOptions considered Summary of project team’s view

Who should bear the establishment and capacity trading platform costs?The list of potential candidates that could be required to fund the establishment and capacity trading costs listed in (1) and (2) includes: (a) secondary shippers only;(b) secondary shippers and primary shippers that sell

their capacity; (c) secondary shippers and all primary shippers; or(d) secondary shippers, all primary shippers and the

service provider.

Of the four options, the Standardisation project team were indifferent between options (a) and (b), although it was noted by some team members that option (a) may be easier to implement (i.e. because changes to primary GTAs would not be required) and it may reduce the perceived impediments to primary shippers selling capacity. It was also noted in this context that even if the costs were recovered from primary shippers, they were likely to be reflected in the price charged by the primary shipper for secondary capacity, so the secondary shipper would still be liable for the costs.

How should costs be recovered?If a decision is made that shippers should fund the establishment and capacity trading costs listed in (1) and (2), then there are a number of different ways these costs could be recovered, including:(i) recovering the costs through a fixed monthly

administrative charge; (ii) recovering the costs through a per transaction or

per GJ of capacity basis; or(iii) a combination of (i) and (ii) (e.g. establishment

costs recovered through an administrative fee and trading costs through a $ per GJ charge).

Project team members were of the view that option (i) or option (iii) could be used, although it was noted that option (iii) may be more appropriate given the nature of the costs.

Should there be any oversight of the costs recovered by service providers?The options in this case include:(1) providing service providers complete discretion;(2) including a principle in the facility specific principles

that requires these types of charges to reflect the cost of providing the service (including a commercial rate of return) and allowing the AER to review the charges in the same way it can review a service provider’s compliance with other facility specific principles; or

(3) requiring the AER to conduct an ex-ante review of the charges to ensure they are prudent and efficient.

Project team members were of the view that if there was to be some level of oversight, then option (2) would be preferable to the other options and cost less to implement than option (3).


The GMRG’s preliminary view was that service providers should have the opportunity to recover the incremental establishment and capacity trading costs from secondary shippers through a combination of a monthly administrative and per GJ charge, subject to the caveat that the charges are cost reflective and, so far as practical, reflect the outcomes of a workably competitive market.

The GMRG also noted that while it did not consider it necessary to require the AER to conduct an ex-ante review of the charges levied by service providers, there would be value in allowing the AER to conduct a review of a service provider’s charges if it has concerns about their level (or if genuine concerns are raised by an interested party).

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There was widespread support from stakeholders that service providers be able to recover the incremental establishment and capacity trading costs. APA did, however, seek to clarify whether service providers that have already incurred costs developing operational transfer services would be able to recover these costs.

The majority of stakeholders also agreed that service providers should be able to recover these costs from secondary shippers. The exceptions to this were:

§ APLNG, who suggested that the costs should be recovered from both trading parties;

§ TGP Pty Ltd, who stated that if there were no secondary shippers, service providers may need to recover the costs from primary shippers; and

§ APA, who was of the view that the costs should be recovered from all shippers that have an operational transfer facility in place (i.e. primary and secondary shippers).

Mixed views were, however, expressed about how the costs should be recovered. EnergyAustralia, AGL and Epic, for example, suggested that costs be recovered through a combination of a fixed monthly administrative fee and a per trade fee. APA, on the other hand, indicated that costs should be recovered through a fixed monthly fee only and noted that this would reduce forecasting risks for service providers. In contrast to the position taken by APA, APLNG suggested that the costs just be recovered through a per trade fee.

Mixed views were also expressed about whether the charges levied by service providers should be subject to any form of oversight by the AER and the pricing principles that should apply to these charges. For example:

§ AGL suggested service providers should be able to recover the costs on a cost pass-through basis, provided the costs are transparent and a fair and reasonable methodology is employed.

§ EnergyAustralia and APLNG were of the view that the AER should be able to review the charges levied by service providers.

§ APGA suggested the use of a similar cost recovery mechanism to that used for market operator service costs (MOS) in the STTM, which allows service providers to submit an invoice to AEMO to recover its MOS allocation service costs and the AER to approve the payment if it is satisfied the costs have been incurred and are reasonable.

§ Epic was of the view that regulatory oversight is unnecessary, but noted that if it was to be implemented it would prefer the AEMC to conduct the review. Epic also suggested that if a pricing principle is employed, it should require charges to be cost reflective and reflect the outcomes of a workably competitive market.

§ APA and Jemena expressed some concern about the extension of a regulatory approval process to unregulated pipelines. APA did, however, agree that the AER should be able to conduct a review of charges if a “bona fide” complaint is made. APA added that if this occurred, the AER’s assessment should be limited to considering whether the costs have been incurred and are necessary to support the capacity trading market.

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GMRG’s final recommendations The GMRG has considered the feedback provided by stakeholders and, in short, recommends that:

(a) Service providers should have the opportunity to recover the incremental establishment and capacity trading costs and, in the case of service providers that have already invested in systems to facilitate operational transfers that will continue to be used under the new framework, these costs should also be recoverable.

(b) The charges used to recover the costs in (a) should be cost reflective and, so far as practicable, reflect the outcomes of a workably competitive market. In the GMRG’s view, this pricing principle is more appropriate than the cost pass through principle proposed by AGL and APA, because it will impose more discipline on service providers when incurring costs and setting charges.

(c) The AER should be able to conduct a compliance review of a service provider’s charges if it has concerns about the level of these charges (or if bona fide concerns are raised by another party) and have the power to require amendments to the charges if it finds they are inconsistent with the pricing principle in (b). While the GMRG did consider the cost recovery model proposed by APGA, it understands this process is administratively burdensome. The GMRG is also not convinced this type of approval process is required, because the threat of a review by the AER should be sufficient in most cases to encourage service providers to set charges at an appropriate level.

(d) Service providers should have the discretion to determine whether:

(i) charges are imposed on secondary shippers only or a combination of primary and secondary shippers; and

(ii) charges are recovered through a fixed monthly administrative fee, a combination of a fixed monthly administrative fee and a per trade fee, or a per trade fee.

In the GMRG’s view, these measures are required because service providers will not face any competition for the provision of operational transfer services on their assets and may not have an incentive to minimise costs or encourage secondary trade. The GMRG is also satisfied that the measures are fit for purpose, targeted and proportionate to the issue they are intended to address and appropriately reflect the legitimate business interests of service providers.

4.6 Governance arrangements for the operational GTA

Background

The governance arrangements for the operational GTA will need to specify the arrangements for the development, publication and amendment of both elements of the standardised operational GTA (the standard terms and the requirements for the facility specific terms), which will be published together as an Operational GTA Code.

One of the main questions that must be considered in this context is whether the Operational GTA Code should be included in the NGR or should be a separate instrument. If it is to constitute a separate instrument, then consideration must also be given to:

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§ who will be responsible for making the initial instrument; and

§ how the instrument will be amended over time and how these changes will take effect.

In assessing these options, consideration needs to be given to the following factors:

§ Alignment with other roles: Determining the terms and conditions of an operational GTA through the Operational GTA Code would be a new role for the AEMC or any panel established by it and also for AEMO. The AER already has a role in approving the terms and conditions of access in AAs for full regulation pipelines. AEMO will run the capacity trading platform and day-ahead auction. The AEMC is responsible for market development through the NGR rule change process, which will include any provisions in the NGR applicable to the Operational GTA Code, the capacity trading platform and the day-ahead auction.

§ Allocation of roles: The NGL and NGR framework separates the roles of the rule maker and market developer (AEMC), the regulator (AER) and market operator (AEMO) in order to, among other things, avoid potential conflicts of interest that might arise when roles are combined in one entity. Responsibility for amendments can be further allocated among a process administrator, the body responsible for recommending changes and the body responsible for approving changes. Table 4.9 sets out examples of the options that could be employed when these roles are allocated among different entities.

§ Nature of the instrument: Operational GTAs complying with the Operational GTA Code and principles in the NGR will be mandatory for service providers to offer but optional for shippers to request (although it is assumed that shippers will generally seek to trade using these terms, since the day-ahead auction and the capacity trading platform will assume these terms apply to all trades).

§ Interaction with other mechanisms: Changes to the Operational GTA Code may impact on the capacity trading platform and the day-ahead auction and conversely changes to those platforms may require changes to the standard terms instrument.

§ How the initial Operational GTA Code will be made: There are a number of options for how the initial Operational GTA Code could be made, including requiring the market body that is responsible for approving changes to do so, or having the SA Minister make the initial Code in a similar manner to the way in which initial Rules under the NGL can be made for specified purposes.

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Table 4.9: Governance options for the Operational GTA CodeOption Overview

AEMC The initial Operational GTA Code would be made when the initial Rules are made and would be published by the AEMC. The Operational GTA Code would be amended by the AEMC following the usual rule change process, as if the instrument formed part of the rules.

AEMC panel The initial Operational GTA Code would be made when the initial rules are made and would be published by the AEMC. The AEMC would be responsible for establishing a panel of experts to determine and recommend changes to the Operational GTA Code. Change requests would be submitted to the panel via the AEMC. The panel would be required to consult on changes. The AEMC would amend the Operational GTA Code on the recommendation of the panel, having regard to the NGO.

AEMO The initial Operational GTA Code would be made when the initial rules are made and would be published by AEMO. The Operational GTA Code would be subject to a change process aligned with the change process followed by AEMO for the STTM / DWGM procedures, which requires consideration to be given to the NGO.

AEMO panel The initial Operational GTA Code would be made when the initial rules are made and would be published by AEMO. AEMO would be responsible for establishing an industry representative panel to consider and recommend changes to the Operational GTA Code. The panel would be modelled on the Settlement Residue Auction (SRA) panel under the National Electricity Rules (NER). AEMO would provide secretariat services to the panel and change requests would be submitted to the panel via AEMO.AEMO could amend the Operational GTA Code on the recommendation of the panel but would not be required to do so.

AER The initial Operational GTA Code would be made when the initial rules are made and would be published by the AER. The instrument would be subject to change by the AER following public consultation.

AER panel The initial Operational GTA Code would be made when the initial rules are made and would be published by the AER.The AER would be responsible for establishing an industry panel to determine and recommend changes to the Operational GTA Code. The panel would be modelled on the SRA panel under the NER. The AER could also undertake public consultation on behalf of the panel. The AER would provide secretariat services and change requests would be submitted to the panel via the AER.The AER would amend the Operational GTA Code taking into account any recommendation of the panel.

AEMO panel/AER oversight hybrid model

The initial Operational GTA Code would be made when the initial rules are made and published by the AER.AEMO would be responsible for establishing a formal panel to consider and recommend changes to the Operational GTA Code. The panel would consist of industry representatives across the gas supply chain and be modelled on the SRA panel under the NER. AEMO would provide secretariat services to the panel and change requests would be submitted to the panel via AEMO. AEMO could undertake public consultation on behalf of the panel. Changes recommended by the panel after being considered through the panel process would only take effect if approved by the AER. In deciding whether to approve the change, the AER would take into account any recommendation of the panel (but would not be bound by it) and principles in the NGR.

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GMRG’s preliminary viewThe GMRG’s preliminary view was that the Operational GTA Code be published as a separate instrument, with the initial Code made by the South Australian Minister at the same time the initial Rules are made. The GMRG also proposed that future changes to the Operational GTA Code be subject to the hybrid governance model set out in Table 4.3 and that any changes to the Operational GTA Code be dealt with as follows:

§ changes to the standard terms should, subject to any transitional arrangements that are put in place when the change is made, automatically apply to operational GTAs that are already in place and new operational GTAs; and

§ changes to facility specific requirements should, subject to any transitional arrangements that are put in place when the change is made, automatically apply to operational GTAs that are already in place and new operational GTAs, once the service provider has implemented the necessary changes.

It was also noted in this context that if a service provider has to make changes to its facility specific terms, then it should be permitted to do so (subject to the principles in the NGR and reasonable transitional arrangements) and that these changes could apply to operational GTAs already in place and new operational GTAs.


The stakeholders that provided feedback on this issue agreed with the proposal to:

§ publish the Operational GTA Code as a separate instrument; and

§ adopt a hybrid governance model for the Operational GTA Code, with an industry panel established to consider and recommend changes to the Code and AEMO to provide secretariat services to the panel.

Mixed views were, however, expressed about which market body should be responsible for approving changes to the Operational GTA Code. For example:

§ Origin, AGL and EnergyAustralia agreed with the GMRG’s preliminary view that the AER carry out this role, with Origin noting the AER seemed well placed to do so given its role in approving terms and conditions of access to covered pipelines.

§ APGA, Jemena and Epic were of the view that this role should be carried out by the AEMC because in their view it is closer to a rule making role than a regulation or compliance role.

Mixed views were also expressed about how changes to the Operational GTA Code and facility specific terms should be given effect. AGL, EnergyAustralia and Epic, for example, agreed with the GMRG’s preliminary view, while Jemena thought that this should be determined by the industry panel. APA, on the other hand, thought that changes to standard terms and facility specific terms should not automatically apply to contracts that have already been signed because it would undermine ‘contractual certainty’. APA added that if such changes made amendments to the existing contracts necessary then the parties to the contract will be sufficiently incentivised to vary existing agreements bilaterally.

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The GMRG has considered the feedback provided by stakeholders on the governance arrangements for the Operational GTA Code and, in keeping with the position that was taken in the consultation paper, recommends that:

§ the Operational GTA Code be published as a separate instrument; and

§ the initial Operational GTA Code be made by the South Australian Minister at the same time the initial Rules are made.

The way in which the Operational GTA Code will interact with other regulatory and contractual instruments is set out in Table 4.10.

Table 4.10: Interaction of instrumentsInstrument RoleNGL Would contain high level legal framework for standardised terms.

NGR Would contain the detailed obligations to develop and offer standard terms, the principles for developing the facility specific terms and define the mechanism for publishing and amending the Operational GTA Code.The AER would have its usual enforcement role and would also be responsible for issuing any exemptions under the NGR.

Operational GTA instrument(Operational GTA Code)

The instrument containing the standard terms and the requirements for the facility specific terms and the form of agreement allowing these to be incorporated in a binding contract. Does not form part of the NGR.

Service provider's standard offer for an operational GTA for each of its facilities

Published by the service provider on its website, incorporating the standard terms and facility specific terms developed by the service provider applying the principles in the NGR and the requirements for facility specific terms in the Operational GTA Code.

Operational GTA Refers to the contractually binding agreement between a service provider and a secondary shipper formed when the shipper accepts the service provider's standard offer for an operational GTA.

The GMRG also recommends the adoption of a hybrid governance model to deal with future changes to the Operational GTA Code, which will require:

§ An industry panel to be formally constituted by AEMO and accorded responsibility for considering any proposed changes to the Operational GTA Code and making recommendations to the AER on:

o whether the proposed changes should be accepted, rejected or accepted in a modified form; and

o any transitional arrangements that may be required when implementing the changes.

The requirement to establish the panel and its membership will be specified in the NGR.

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§ AEMO to provide secretariat services to the industry panel, including running consultation processes and requesting any specific input or analysis from the AEMC on market development issues if the industry panel believes it is relevant to do so.

§ The AER to decide whether or not to approve changes to the Operational GTA Code and, in doing so, to have regard to the industry panel’s recommendation (but not be bound by it) and principles specified in the NGR. The AER would also have the power to remit a matter to the industry panel for further consideration.

The main benefits of this hybrid governance model are that it will:

§ draw on industry expertise through the establishment of a panel that will consist of industry representatives across the gas supply chain;

§ enable the change process for the Operational GTA Code to be run in parallel with any related changes to the capacity trading platform, day-ahead auction rules and related procedures through the involvement of AEMO; and

§ provide independent oversight of changes through the involvement of the AER.

In the GMRG’s view, independent oversight is required given the mandatory nature of the Operational GTA Code. As highlighted in the consultation paper, the GMRG considered which market body should take on this role and concluded that the AER was the most appropriate body to take on this role because:

§ it is consistent with the AER’s current role in relation to approving the terms and conditions of access to covered pipelines;

§ AEMO may not be regarded as sufficiently independent to provide that oversight since it is also the operator of the capacity trading platform and day-ahead auction; and

§ the role may be perceived as a conflict of interest for the AEMC because it would be both rule maker and regulator.

While APGA, Epic and Jemena have suggested the role is more akin to a rule making function than a regulatory function, the GMRG is not convinced that this is the case and notes that if the AEMC was accorded this role then:

§ it would be able to determine the principles to be considered when assessing changes to the Operational GTA Code through its rule making function; and

§ it would be required to apply these rules in any assessment of the proposed changes to the Operational GTA Code.

In the GMRG’s view, this could be viewed as a conflict of interest. The GMRG is therefore recommending that the AER be accorded this role.

As to how changes to the Operational GTA Code will be given effect, the GMRG recommends that:

§ changes to the standard terms automatically apply to operational GTAs that are in place and new operational GTAs, subject to any transitional arrangements that are put in place, which the industry panel would be expected to advise the AER on; and

§ changes to the facility specific requirements automatically apply to operational GTAs that are in place and new operational GTAs once the service provider has

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implemented the necessary changes, subject to any transitional arrangements that are put in place by service providers, subject to the principles in the NGR.

In relation to the concerns that APA has raised about the potential for automatic changes to existing operational GTAs to undermine contractual certainty, the GMRG considers that the key issue is the impact of changes on particular trades given effect to under Operational GTAs and not on the date of the Operational GTA itself (since focusing on the date of the Operational GTA may lock out any change at all, even for trades not yet entered into).

As noted in Chapter 2, the Operational GTA is intended to operate like a master agreement, with the majority of terms and conditions only being of practical effect when a capacity trade is on foot. If a change to existing Operational GTAs is made and no trade is on foot at the time the change comes into effect, there is no question of contractual certainty – the parties will know what terms apply the next time a trade is entered into. If a change comes into effect when a trade is already on foot (say, half way through a 3-month trade), transitional arrangements are expected to be made. For example, the old terms could be grandfathered for trades on foot when the changes comes into effect and the new terms could apply to any new trades entered into from that date, or the effective date of the change could be delayed until all current trades have come to an end. While the form that the transitional arrangements take would be a matter for the industry panel to advise the AER on, the consultation process is intended to allow shippers and gas transporters to have a say and to give parties notice of forthcoming changes.

The GMRG believes that this approach strikes an appropriate balance between giving the market certainty about the terms applicable to the use of secondary capacity and ensuring change can be implemented on a consistent basis for all market participants.

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5. Other Measures to Reduce Barriers to TradeIn addition to the standardisation reforms outlined in Chapter 4, there are a number of other measures that could be implemented to reduce the barriers to secondary capacity trading and participation in the day-ahead auction. These measures include:

§ improving access to the allocation agreements in place at receipt and delivery points;

§ addressing other contractual impediments to trade in primary GTAs; and

§ harmonising gas day start times and nomination cut-off times across jurisdictions.

The remainder of this chapter sets out the GMRG’s final recommendations on whether these measures should be implemented.

5.1 Allocation agreements and access to receipt/delivery pointsBackground Allocation agreements specify the rules that are to be used by the allocation agent42 to allocate gas that is metered as having been supplied (or deemed to have been delivered) to a multi-user receipt or delivery point between shippers using these points. These rules can include, allocating gas on a pro-rata basis, a swing shipper basis, a defined formula basis or using a marked based approach. The GMRG understands that the scope of the allocation agreements and the allocation rules specified therein can vary markedly across receipt and delivery points. The GMRG also understands that:

§ Shippers wishing to transport gas to or from a multi-user receipt or delivery point must be a party to the allocation agreement to nominate gas at the point. If there is no agreement in place at a delivery point then pipeline operators can apply a default allocation rule. The default rule cannot, however, be applied at most receipt points because these points are controlled by the producers.

§ Contribution agreements may be used in conjunction with allocation agreements at points where shippers have invested in the construction of a receipt or delivery point and require the payment of a fee to use this point. Access to these points may, depending on the arrangement that has been reached with the service provider, require the approval of the shipper(s) that funded the point, or may just require a contribution to the costs.

§ Some allocation agreements provide for sub-allocation levels and accord the shipper responsibility for sub-allocating the gas to parties they have traded with.

In the East Coast Review, the AEMC noted that some changes to these agreements may be required to enable capacity to be traded and to facilitate greater receipt and delivery point flexibility.43 These issues were considered by the Standardisation project team, who informed the GMRG that allocation agreements may act as an impediment to capacity trading because:

42 The allocation agent may, or may not be, the pipeline operator.43 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 90-93.

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§ there is limited publicly available information on allocation agreements or the process a shipper needs to follow and who it needs to contact to become a party to an allocation agreement at a particular point;

§ there are some allocation agreements that restrict the number of shippers that can become a party to the agreement, or otherwise limit access to a particular receipt or delivery point - it was noted that this tends to occur at:

o locations where there is also a contribution agreement in place; and

o receipt points controlled by producers, with some producers reportedly requiring shippers to have a Gas Supply Agreement with the producer to become a party to the allocation agreement; and

§ differences in the allocation rules used at some points (e.g. at pipeline interconnection points) may result in differences in the volume of gas a shipper is allocated to have supplied into, or taken from, the pipeline and result in an imbalance and ‘loss’ of gas.

The Standardisation project team identified a number of measures to try and overcome these impediments, including:

§ publishing information on how shippers can become a party to an allocation agreement at each point;

§ options to reduce the administrative costs, time and complexities that may be associated with becoming a party to a number of allocation agreements, such as:

o deeming secondary shippers to be a party to any allocation agreement that may be in place at the receipt and delivery points they want to use;

o including all the allocation agreements as schedules to the operational GTA; or

o allowing AEMO to become a party to all the allocation agreements and to be responsible for sub-allocating gas to secondary shippers; and

§ standardising the allocation rules in all allocation agreements or at key interconnection points.

While some consideration was given to the latter two options, the project team identified a number of specific issues with each option (see Table 5.11) and therefore suggested that the GMRG focus on the transparency measures. The project team stopped short, however, of recommending the allocation agreements be made public, because they noted the agreements can contain confidential information.

Table 5.11: Project team feedback on other options to reduce the barriers posed by allocation arrangementsOptions considered Project team’s view on the options

Deeming secondary shippers party to the agreements

Some project team members noted that deeming secondary shippers as a party to an allocation agreement could be disputed, which would affect the integrity of the operational GTA and secondary capacity market.

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Options considered Project team’s view on the options

Adding allocation agreements as schedules to the operational GTA

The project team noted that before adding the allocation agreements to the operational GTA, service providers need to seek the agreement of the relevant parties, which they suggested could be a complex and costly undertaking for service providers and raise further change management issues. The project team also noted that there may be confidentiality concerns because allocation agreements are not generally made public, nor available to the service provider when they are not the allocation agent.

AEMO as sub-allocation agent

Project team members noted that having AEMO as a sub-allocation agent in all agreements would restrict the way parties manage their imbalance accounts, introduce an additional level of complexity in these agreements and add additional administration cost.

Standardisation of allocation rules

A number of team members noted that standardising allocation rules could adversely affect parties operating under legacy arrangements and added that this could conflict with the AEMC’s recommendation that counterparties to existing contracts should not be materially disadvantaged through the standardisation process.


In the consultation paper, the GMRG agreed with the Standardisation project team’s suggestion that information on the allocation agent and contact details at all the relevant points should be published on the BB. The GMRG did, however, note that while this may reduce some of the impediments posed by allocation agreements, it would not address:

§ the impediments posed by having to sign up to a number of allocation agreements and to potentially incur administrative costs at all of these points;

§ the concerns that had been raised about the potential for differences in allocation rules where pipelines interconnect to expose shippers to significant costs and risks; and

§ the potential for contribution agreements and the control of some receipt and delivery points by shippers to impede access at these points.

The GMRG therefore sought feedback on how significant these issues were and whether additional measures were required to address these impediments.


Stakeholders were generally supportive of the proposal to require information on allocation agents and contact details to be published (either on the BB or service providers’ websites). Mixed views were, however, expressed about whether additional measures are required to address the impediments posed by having to sign up to multiple allocation agreements.

Shell and APLNG, for example, were of the view that the requirement to sign up to a number of allocation arrangements could act as a barrier to new entrants and suggested this could be addressed by standardising allocation agreements and deeming shippers party to the agreements. AGL, EnergyAustralia, Origin, Jemena and Epic, on the other hand, indicated that this is not a significant impediment to trade and raised concerns with the proposal to deem secondary shippers party to the agreements. Origin also raised concerns about standardising allocation agreements and noted it could adversely affect shippers operating under legacy arrangements, contrary to the AEMC’s recommendation

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that counterparties to existing contracts should not be materially disadvantaged through the standardisation process. AGL, Jemena and Epic also thought standardisation of agreements was unnecessary, while EnergyAustralia suggested that it could be explored.

APA also noted in its submission that it did not think allocation agreements should be seen as an impediment to trade. It did, however, note that it would be preferable for trading activities to occur at in-pipe trade points, rather than via allocation stacks at receipt and delivery points, because:

§ these points are accessible to all shippers;

§ allocations are deemed and not subject to physical variations; and

§ there is greater transparency at these points.

This view was supported by one shipper in bilateral discussions, who suggested that in-pipe trading points could greatly simplify arrangements and enable trades to occur with counterparties adjacent to the physical points. This shipper also noted in-pipe trading points would be particularly useful at points adjacent to the DWGM and the STTMs, to enable producers wishing to transport gas to customers in these locations, but do not necessarily want to participate in the facilitated markets, to do so without having to deal with the costs and complexities associated with allocation agreements at these points.

Stakeholders also expressed diverse views on whether a common allocation rule should be adopted across the east coast. Jemena and Epic, for instance, noted that there may be good reasons to have different allocation rules at different points and that standardisation may result in a loss of flexibility in the market. APLNG, on the other hand, suggested that there should only be limited points where a standard pro-rata allocation is not utilised. While AGL did not think a market wide rule was required, it did suggest there could be value in implementing a consistent allocation rule across interconnected pipelines and noted that an area that would benefit from such an approach, is Moomba. Moomba was also identified by a number of other shippers in bilateral discussions as a location that would benefit from a common allocation rule, with some noting that gas had been ‘lost’ at Moomba as a result of the differences in allocation rules currently in place.

The final matter that stakeholders commented on was the barriers posed by shippers controlling points and contribution agreements. Mixed views were expressed on whether this is an impediment, with AGL stating that if contribution agreements and charges apply to all shippers in a fair and transparent manner they should not be a barrier to trade, while EnergyAustralia indicated that they could act as a barrier to trade. In bilateral discussions, a number of market participants also noted these arrangements have been used to block or otherwise impede access.


The GMRG understands that the opaqueness surrounding allocation agreements could act as an impediment to trade and is therefore recommending that information on allocation agents at all the relevant points in the east coast and their contact details be published on the BB. In the GMRG’s view, this measure will promote the NGO because it is a relatively low cost measure and will reduce the search and transaction costs secondary shippers would otherwise face.

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This measure on its own will not, however, be sufficient to address some of the other impediments to trade posed by allocation arrangements. While the stakeholder feedback received to date has provided some insight into the nature of these impediments and identified some potential solutions, the GMRG is of the view that there would be value in carrying out more detailed work on this issue with AEMO and market participants in early 2018. Specifically, there would be value in carrying out further work to:

§ address the allocation issues that have been identified at Moomba and develop a common allocation rule that can be used at other key interconnection points in the east coast;

§ assess the merits of the solutions that stakeholders suggested could be used to overcome the impediments posed by allocation arrangements (e.g. making greater use of in-pipe trading points, standardising allocation arrangements or deeming secondary shippers to be a party to an allocation arrangement); and

§ determine whether any specific measures need to be implemented to prohibit shippers from using allocation or contribution agreements to prevent access to individual receipt or delivery points.

In addition to these matters, the GMRG intends to work with the ACCC in early 2018 on whether there is value in publishing any other information on allocation agreements to reduce the opaqueness in the gas market.

The GMRG recommends the Energy Council task it to carry out this work in early 2018 and provide its recommendations to SCO and the Energy Council by mid-2018.

5.2 Contractual limitations on capacity trading in primary GTAs

Background

The GMRG understands from discussions with a number of stakeholders and the feedback provided to the AEMC in the East Coast Review that there may be provisions in some primary GTAs that limit the ability of shippers to trade capacity, or otherwise discourage or impede trade.

Some of the examples that stakeholders cited in this context include provisions that:

(a) prohibit the primary shipper from trading its capacity through either a bare transfer or operational transfer, or requiring the primary shipper to obtain the service provider’s consent before it can trade its capacity; 44 and

(b) prohibit the shipper from requesting a change to their receipt and delivery points, limit the number of changes a shipper can request or otherwise impede the shipper’s ability to change receipt or delivery points (e.g. by charging fees that are higher than the cost of providing this service).

In relation to the latter of these examples, the AEMC noted in the East Coast Review that non-technical restrictions on changes to receipt and delivery points and the time service providers can take to approve such changes can impede secondary capacity trading. The AEMC therefore recommended that shippers be provided greater flexibility to change their 44 The term ‘trade’ is used in this context to refer to a temporary transfer of capacity that does not

affect the primary shipper’s rights against, and obligations to, the service provider.

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receipt and delivery points and noted that the options likely to best achieve this objective would involve:45

§ developing zones that cover multiple receipt and delivery points and allowing changes to occur relatively easily within these zones and by putting in place rules that clearly define how changes across zones will be dealt with;

§ only allowing pipeline operators to reject changes to receipt and delivery points on technical and operational grounds, as opposed to commercial grounds; and

§ requiring pipeline operators to respond to a request to change a receipt or delivery point within a specified time.

This was classified as a preferred outcome by the AEMC. The merits associated with the first of these options are discussed in further detail in Chapter 6. In short, the GMRG thinks that the zonal model should be used to facilitate trade on the capacity trading platform and that this will provide shippers with greater receipt and delivery point flexibility.

As to the other process based options that the AEMC identified, the GMRG understands the concerns regarding the potential for some aspects of the receipt and delivery point change process to act as an impediment to secondary trade. Similar concerns were also raised with the GMRG in bilateral discussions, with some stakeholders noting that service providers have a considerable degree of discretion in this area and may not have an incentive to consent to changes that facilitate trade.

This issue was considered by the Standardisation project team, which noted that service providers usually have full discretion to determine whether to consent to a change to receipt and delivery points and, when deciding whether to exercise that discretion, will usually consider:

§ the technical feasibility of the change and what, if any, impact the change may have on other shippers’ use of the facility (which may require modelling of flows); and

§ the commercial feasibility of the change, which will typically involve an assessment of whether the service provider’s profitability will be adversely affected by the change (e.g. because the change results in the payment of a lower tariff, higher costs or less capacity).

The GMRG also understands that while some service providers provide shippers with a response within five business days, other service providers allow themselves 30 days (~22 business days) to respond to the request. Project team members also informed the GMRG that some service providers and/or primary GTAs:

§ place a cap on the number of requests a shipper can make in a defined period; and/or

§ charge shippers a fee to change their receipt or delivery point (or to provide access to new receipt or delivery points) and/or to carry out the investigative work required to determine whether the change is technically feasible.

The Standardisation project team identified a number of options to try and improve the process outlined above, including:

§ providing greater clarity about the circumstances in which a service provider can withhold its consent in response to a request by a primary shipper;

45 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 91-92.

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§ requiring service providers to inform shippers of whether their request has been accepted, or if further work is required within a specified time;

§ adopting rules that specify how changes within, or across, zones are treated; and

§ removing any restrictions on the ability of shippers to request a change but, where appropriate, charging a fee for the incremental costs incurred by the service provider.

The project team’s views on these options are summarised in the table below.

Table 5.12: Project team feedback on the receipt and delivery point change processIssues Summary of project team’s view

Circumstances in which a request can be rejected

Service provider representatives in the project team noted that changes to receipt and delivery points can have technical and commercial implications and it is appropriate to consider both of these factors when assessing a shipper’s request and to be able to reject a request on this basis. Elaborating further on the commercial implications, service provider representatives noted that they should be kept financially whole and added that this was consistent with the way rule 106 of the NGR has been applied to date and the approach used in other jurisdictions. Other project team members agreed that service providers should not be worse off as a result of the change, and it is relevant to take into account commercial considerations. It was, however, suggested by some team members that the scope of the commercial considerations be more clearly defined to limit this discretion.

Time taken to respond to requests

Project team members noted that if flow modelling or other investigative work is required then it may take the service provider longer to respond to the request than in other cases where this type of work is not required. Project team members were therefore of the view that it would not be possible to standardise the time service providers have to accept or reject the request. They did, however, think there may be value in requiring the service provider to inform the shipper within 5 business days of receiving the request whether:§ the request had been accepted or rejected; or § if further investigative work is required to assess the request, the nature of any work

and likely timing of a response.

Rules for changes within and across zones

Project team members in this case noted that:§ transfers of a primary shipper’s capacity within a zone should occur on a one-for-one

basis, subject to capacity being available at the relevant point; and§ transfers of capacity outside a zone could not be dealt with using a simple rule,

because the ability to move capacity across a zone will depend on a range of technical issues (such as pressure or capacity differentials across zones) and may require flow modelling.

The project team also considered whether flow modelling could be completed up front (i.e. prior to requests for transfers) to reduce the time taken to assess transfers across zones, but concluded this would be too complex.

Limits on requests and charges

Some project team members suggested that rather than limiting the number of requests a shipper can make, it would be better to charge shippers the incremental costs of carrying out any investigations that may be required.


In the consultation paper, the GMRG noted the potential to overcome any contractual limitations on the ability of primary shippers to trade their capacity by way of a bare transfer or operational transfer, for example by extending the operation of rule 105(2) to non-scheme pipelines. Rule 105 sets out principles for capacity trading requirements in access arrangements for non-scheme pipelines. Unless otherwise covered by market rules, the requirements must allow a user, without the service provider’s consent, to transfer all or any of its contracted capacity to another party if its rights against, and obligations to, the service provider are unaffected by the transfer.

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The GMRG also noted the potential to overcome contractual limitations on receipt and delivery point changes in primary GTAs by including provisions in the NGR that:

(i) provide primary shippers and service providers with greater guidance on the rights shippers have to seek a change (or to add a new point) and the circumstances in which a service provider can withhold its consent;

(ii) specify the timeframes service providers would have to respond to a request to change a receipt or delivery point or zone;

(iii) override any provisions in primary GTAs that limit a shipper’s ability to seek a change in receipt or delivery points; and

(iv) require any charges levied by service providers to be cost reflective and, so far as reasonably practicable, reflect the outcomes of a workably competitive market.


Stakeholder feedback received on the contractual limitations outlined above was relatively diverse. While some stakeholders noted that they could impede trade and that steps should be taken to remove these impediments, others were not convinced that anything needed to be done to address these limitations.

APLNG, for example, was of the view that steps should be taken to remove any constraints on capacity trading if they prohibit greater utilisation of pipelines. Other stakeholders, on the other hand, were less convinced that this was an issue, with:

§ AGL noting that shippers usually have the ability to trade by entering into bare transfers;

§ APA noting that its Standard GTA permits the assignment of capacity from one shipper to another and that it also has a standing offer to include a capacity transfer service in its existing GTAs for any shipper that requests it; and

§ Jemena noting that its primary GTA provides for bare transfers of capacity and/or assignments, but acknowledged that in many cases shippers must obtain its consent before they trade the capacity.

AGL and Origin also expressed some concern about the potential re-opening of primary GTAs to address this type of limitation and claimed it would give rise to uncertainty and risk for both the service provider and shipper. Concerns were also raised by AGL and APA about extending the operation of rule 105(2) to non-scheme pipelines, with APA noting there may be valid commercial or technical reasons for pipelines to restrict trades.

As to limitations on receipt and delivery point changes, EnergyAustralia, Shell and APLNG suggested there was value in amending the NGR to overcome this type of limitation in primary GTAs. AGL, Origin, Jemena, APA and Epic, on the other hand, did not think this was necessary, with Origin, APA and Epic noting that the adoption of the zonal model should be sufficient to address the issues the AEMC originally raised. APA also expressed some concerns about the potential for changes to the NGR to override existing contractual rights and disagreed with a number of the suggestions that appeared in the consultation paper regarding the circumstances in which consent could be withheld and the timeframes within which service providers should respond.

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The GMRG has considered the feedback provided by stakeholders on the contractual limitations outlined above and while it understands the reluctance that pipeline operators and some incumbent shippers may have to addressing these impediments, it is of the view that steps need to be taken to ensure they do not act as a barrier to secondary trade. The GMRG is therefore recommending a number of changes to overcome these limitations. Further detail on these proposed changes is provided below.

Limitations on shippers trading capacity

In the GMRG’s view, it is difficult to see any legitimate reason for the inclusion of clauses in GTAs that prevent or otherwise impede the trade of capacity by way of a bare or operational transfer if the shipper selling the capacity remains liable to pay for the capacity it contracted for and the shipper buying the capacity has an operational GTA with the service provider.46 Given the potential for such clauses to impede trade and restrict competition in the secondary market, the GMRG recommends that provisions be included in the NGL/NGR to provide for users to transfer some or all of their capacity without the service provider’s consent if these conditions are met.

This rule would not apply to assignments or novations, which the GMRG agrees should be subject to the consent of the service provider given these types of transfers can involve the termination or modification of the primary shipper’s payment obligations to the service provider. If primary shippers already have the right to trade capacity and do not require the service provider’s consent, then the rule will have no effect on the primary shipper’s rights.

If primary shippers already have the right to trade capacity and do not require the service provider’s consent, then these new provisions will have no effect on the primary shipper’s rights. It can, however, be expected to benefit those primary shippers that are currently subject to these limitations, which will benefit the market more generally by enabling more shippers to compete to provide secondary capacity. This can, in turn, be expected to promote the efficiency with which transportation capacity is allocated and used and foster the development of a more liquid secondary market, which is consistent with the broader objectives of the capacity trading reform package. It is also consistent with the Energy Council’s Vision and a number of the outcomes it expected to pursue in the next phase of gas market reform (i.e. outcomes 2(b) and 3(b) – see ). The GMRG is therefore satisfied that this recommendation will promote the NGO.

Limitations on receipt and delivery point changes

Although some stakeholders questioned the need to reform the receipt and delivery point change process, it does, as outlined above, fall within the scope of what the AEMC intended, which was that pipeline operators should only be able to reject changes in limited circumstances and should be required to respond to requests within a specified time. While the introduction of the zonal model (see Chapter 6) will overcome these issues 46 Further support for this view can be found in the explanatory material that accompanied the original

National Third Party Access Code for Natural Gas Pipeline Systems, which noted that the capacity trading provisions in an access arrangement must “comply with a number of principles designed to limit the ability of the Service Provider to restrict competition in the Secondary market by unreasonably limiting the resale of capacity”.

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to some extent, it is important to recognise that under this model primary shippers will only have the right to sell capacity within the zone that their receipt or delivery points are located. If shippers want to sell capacity outside the zone, then they will need to seek a change to their receipt or delivery points. The receipt and delivery point change processes employed by service providers will therefore continue to have an important bearing on secondary trade and could, as the AEMC and other stakeholders have noted, impede trade if they:

§ prohibit the shipper from requesting a change to their receipt and delivery points;

§ limit the number of changes a shipper can request; or

§ otherwise impede the shipper’s ability to change receipt or delivery points.

To overcome this potential impediment, the GMRG recommends that provisions be included in the NGL/NGR to:

(i) Provide shippers and service providers with greater guidance on:

o the rights that primary shippers have to seek a change to their receipt or delivery points (or add a new point); and

o the circumstances in which a service provider can withhold its consent, which in the GMRG’s view should only occur if: - the change is not technically feasible;- the change would adversely affect another shipper’s access; and/or- the change results in the service provider receiving less revenue under its

contract with the shipper47 or incurring additional costs that the shipper is not prepared to pay for.

(ii) Specify the following timeframes for service providers to respond to a request to change a receipt or delivery point or zone:

o For changes within a zone, service providers should inform shippers within five business days of receiving the request whether consent will be granted or not.

o For changes across zones, service providers should inform shippers within five business days of receiving the request whether consent will be granted or not, or if further investigations are required. If further investigations are required, then the service provider should be required to: - inform the shipper of how long the investigations are expected to take and

what, if any, charges the shipper will be liable to pay; and- provide its final response to the shipper within 20 business days of receiving

the request.Extensions to these timeframes will be available if the service provider needs to obtain the consent of a third party (e.g. another shipper at the relevant point or the allocation agent), or if both parties agree to the extension.

(iii) Require any charges that service providers levy for receipt or delivery point changes (or the inclusion of new receipt or delivery points), or to investigate the technical

47 Note that this could occur if the pipeline operator utilises distance based or zonal tariffs, but would not occur if the pipeline utilises postage stamp tariffs (i.e. because the shipper’s charges would not change as a result of the move).

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feasibility of such a change to be cost reflective and, so far as reasonably practicable, reflect the outcomes of a workably competitive market.

In the GMRG’s view, these provisions will appropriately balance the concerns that have been raised about the receipt and delivery point change process, with the legitimate interests of service providers and other shippers, and the safe and reliable operation of the pipeline. This is because the provision will still allow service providers to reject a change if there are valid commercial or technical reasons for doing so. Service providers will also be able to recover the costs they incur in investigating and making the changes from shippers, subject to the pricing principle outlined in (iii). The legitimate interests of service providers should not therefore be adversely affected by the inclusion of the proposed provision. The provision is not intended to affect the flexibility that some primary shippers have been able to negotiate in their primary GTAs and its application will therefore be limited in these situations.

More generally, the GMRG believes these provisions are fit-for-purpose and proportionate to the issues that have been identified and is consistent with:

§ the AEMC’s preferred outcome that shippers be provided greater flexibility to change their receipt and delivery points;

§ the broader objectives of the capacity trading reform package, because it will remove any artificial impediments to primary shippers moving their receipt and delivery points, which should improve the efficiency with which capacity is allocated and used and enable the market more generally to adapt to changing circumstances; and

§ the Energy Council’s Vision and a number of the outcomes it expected to pursue in the next phase of gas market reform (i.e. outcomes 2(b) and 3(b) – see ).

The GMRG is therefore satisfied that this recommendation will promote the NGO.

5.3 Gas day start times and nomination cut-off times

Background

In February 2017, the AEMC decided to amend the rules to require the gas day start times in the facilitated markets (i.e. the STTM, the GSH and the DWGM) to move to 6 am (AEST) on 1 April 2021. The benefits of harmonisation that the AEMC cited in this context were that it would:48

§ reduce the costs and complexities that market participants operating (or wishing to operate) across multiple facilitated markets currently face, including pipeline operators located at the interface of markets with different gas day start times; and

§ increase the interoperability and interconnection between markets and, in so doing, promote participation and liquidity in these markets and trade between locations.

48 AEMC, Final rule determination: National Gas Amendment (Gas day harmonisation) Rule 2017, 16 February 2017, pp. 21-24.

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The AEMC also noted that some market participants were currently using contractual and operational arrangements to manage differences in gas day start times (e.g. through linepack and imbalance allowances), these arrangements were not costless and may not be available in all circumstances.49

While the focus of the rule change was on the facilitated markets, the AEMC noted that employing the same gas day start time for the capacity trading reforms and harmonising pipeline schedules would be “desirable” because it would enable “seamless trading between regions” and “promote participation, competition and liquidity in these markets”.50 A similar observation was made by the ACCC in the East Coast Gas Inquiry, with the ACCC noting that alignment of gas day start times and the nomination times employed by pipeline operators and other facilities would “reduce any potential barriers to trade and transaction costs”.51

The 1 April 2021 commencement date was adopted by the AEMC for this rule change because at the time it made the rule the capacity trading reform package was expected to be implemented in 2021.52 Given a decision has subsequently been made to bring forward the implementation of these reforms, it is relevant to consider whether:

§ the harmonisation of gas day start times in the facilitated markets should be brought forward;

§ the application of the gas day start time harmonisation should extend to all pipelines, production facilities, compressor and storage facilities in the east coast; and

§ the nomination cut-off times should also be harmonised across pipelines and other facilities that will be subject to the capacity trading reforms (e.g. compressors).

In considering the above, it is important to understand the effect that differences in gas day start times and nomination cut-off times will have on:

§ the timing of the close of trade for day-ahead products on the capacity trading platform; and

§ the timing of the day-ahead auction.

These effects are highlighted in Table 5.13. The top section of this table sets out indicative times for the close of trade on the capacity trading platform and the day-ahead

49 The AEMC cited the following example in its rule change to highlight how these differences are dealt with on the South West Queensland Pipeline (SWQP).

“The western end of the APA pipeline is at Moomba which operates with a 6.30 am AEST gas day start time. The eastern end of the SWQP is at Wallumbilla where the GSH operates on a gas day that starts at 8.00 am AEST. Nevertheless, shippers using this pipeline are not required to enter into a two-day transportation contract, nor required to negotiate a pro-rating arrangement so that the gas flow matches either the Moomba or Wallumbilla gas day. Instead, SWQP shippers nominate their requirements for a ‘gas day’ and the linepack available on the pipeline allows APA to operate it in a way that accommodates the difference in the gas days of the markets to which the pipeline is connected without any specific contractual requirements or any other action by the shippers.”

AEMC, Final rule determination: National Gas Amendment (Gas day harmonisation) Rule 2017, 16 February 2017, p. 21.

50 ibid, p. 23.51 ACCC, Inquiry into the east coast gas market, April 2016, p. 79.52 AEMC, Final rule determination: National Gas Amendment (Gas day harmonisation) Rule 2017, 16

February 2017, p. i.

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auction under the current gas day start times and nomination cut-off times. The middle section shows what would occur if gas day harmonisation occurred but nomination cut-off times were not harmonised. The bottom section of the table demonstrates the effect of harmonising both gas day start times and nomination cut-off times.

Table 5.13: Gas day start times, nomination cut-off times and indicative timings for the day-ahead auction and close of trade on the trading platform (all times AEST)

Gas Day Start Time

Indicative Timing for Capacity Trading Platform Close for Day-Ahead Products*

Pipeline Nomination Cut Off Time for Gas Day D+1**

Indicative Timing for Day-Ahead Auction***

Auction Capacity Published

Auction Bids Due

Auction Completed

Current Gas Day and Nomination Cut-Off TimesNSW/ACT 6:30 am

11:00 am

2 -2:30 pm

5:45 pm 6:15 pm 6:45 pm

SA 6:30 am 3:30 pm

Queensland 8:00 am 3-4:00 pm

Tasmania 6:30 am 1:30 pm

Northern Territory 8.30 am n.a. 2-2:30 pm

Victoria 6:00 am n.a. n.a. n.a. n.a. n.a.

Harmonised Gas Day but Different Nomination Cut-Off TimesNSW/ACT

6:00 am9:00 am

1.30-2 pm

4:45 pm 5:15 pm 5:45 pm

SA 3 pm

Queensland 1-3 pm

Tasmania 1 pm

Northern Territory

11.30am-12pm

Victoria n.a. n.a. n.a. n.a. n.a.

Harmonised Gas Day and Nomination Cut-Off TimesNSW/ACT

6:00 am 12:30 pm 3:00 pm 4:45 pm 5:15 pm 5:45 pm

SA

Queensland

Tasmania

Northern Territory

Victoria n.a. n.a. n.a. n.a. n.a.Notes: * Trading assumed to end 2.5-3 hours before nomination cut-off time to allow pipeline operators to make MDQ transfers.** Nomination cut-off times assumed to be offsets to gas day start times.*** Capacity assumed to be published 1.5 hours after nomination cut-off time. Shippers are then assumed to have 30 minutes to make their bids in the auction. The auction is then assumed to be completed within 10 minutes of bids closing.

As the top panel of Table 5.13 highlights, a lack of alignment of gas day start times and nomination cut-off times will result in:

§ the close of trade for day-ahead products on the capacity trading platform being set by reference to the earliest nomination cut-off time (currently 1.30 pm (AEST)), which means that trade will need to cease by 11 am (AEST); and

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§ the timing of the day-ahead auction being set by reference to the latest nomination cut-off time (currently 4 pm (AEST)), which means that the earliest the auction could be conducted is by 6.45 pm AEST.

If gas day start times are aligned, but nomination cut-off times are not, then as the second panel in Table 5.13 highlights it will result in:

§ the close of trade for day-ahead products on the capacity trading platform will be 9 am (AEST) because the earliest nomination cut-off time will be 11.30 am (AEST) once the harmonisation of gas day start times occur (note pipeline operators have advised that nomination cut-off times will be brought forward because they are currently determined as off-sets to the gas day start times); and

§ the timing of the day-ahead auction being brought forward by one hour because the latest nomination cut-off time will be 3 pm (AEST)).

If, on the other hand, gas day start times were harmonised and a common nomination cut-off time of, for example, 3 pm (AEST)53 was adopted (see last panel of Table 5.13) then:

§ the trade of day-ahead products on the capacity trading platform could close at 12.30 pm (AEST), which would give shippers an additional 1.5 hours (compared to the current gas day and nomination cut-off time) to sell any spare day-ahead capacity they may have on the capacity trading platform; and

§ the auction could be conducted at 5.45 pm (AEST), which would provide shippers that procure capacity through the auction with more time to co-ordinate their capacity, commodity and downstream arrangements for the next day.

The issues associated with bringing forward the gas day start time harmonisation, extending the application of the harmonised gas day start times and adopting a common nomination cut-off time were discussed with the Standardisation, Capacity Trading Platform and Day-Ahead Auction project teams. The views expressed by these project teams can be summarised as follows:

§ Bringing forward gas day start time harmonisation for the facilitated markets – Mixed views were expressed on this issue, with some project team members indicating there would be value in bringing the harmonisation forward to 2019 to remove impediments to capacity trading across jurisdictions. Other team members, on the other hand, indicated that the current timing should be maintained because the benefits of bringing forward harmonisation would be unlikely to outweigh the costs. These project team members added that any differences in gas day start times in the intervening period could be dealt with by using the contractual and operational arrangements that shippers and pipeline operators are currently using to overcome the impediments posed by this difference. One project team member also noted that if a decision was made to bring the harmonisation forward it could impose additional costs on other facilities that are directly affected by the harmonisation (e.g. the distribution networks in NSW, South Australia and Queensland).

§ Extending the application of gas day harmonisation beyond the markets – A number of project team members highlighted that the AEMC’s rule change only applies to the facilitated markets and noted that there would be value in extending the application of the harmonised gas day start time to the operators of all production,

53 The 3 pm timing is based on the latest nomination cut-off time that will exist once gas day harmonisation occurs.

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pipeline, compressor and storage facilities. These project team members also noted that mandating the change through the NGL and/or the NGR would be more cost effective than requiring facility operators to negotiate changes with all of their existing users and would also address the risk that some users refuse to allow the change.

§ Adopting a common nomination cut-off time – Project team members had mixed views on this issue. Some project team members indicated that there would be value in harmonising nomination times, that it should occur when gas day harmonisation occurs and should be mandated through the NGL and/or NGR. Others, on the other hand, noted that differences in timing across jurisdictions can benefit shippers and service providers from a resourcing perspective.


In the consultation paper, the GMRG noted that there was likely to be value in adopting:

§ a common gas day start time of 6 am (AEST) across the east coast (and the Northern Territory once it becomes connected via the Northern Gas Pipeline) that would apply to the operators of all production, pipeline, compressor and storage facilities and mandated through the NGL/NGR; and

§ a common nomination cut-off time of 3 pm (AEST) for pipelines and other facilities that will be subject to the capacity trading reforms and that this should be mandated through the NGL/NGR.

While consideration was given to requiring harmonisation to occur in October 2019, it was noted that there may be some risks to this timing. Stakeholders were therefore asked whether they thought there would be any value in bringing forward the harmonisation of gas day start times from 1 April 2021 to 1 October 2019. Stakeholders were also asked if they thought provisions should be in included in the standardised operational GTA to require service providers operating at the interface of markets to accommodate the differences in gas days until harmonisation occurred.


The feedback provided by stakeholders on harmonisation was generally positive, with all of the stakeholders that provided a response to this issue agreeing that a common gas day start time should apply to all facilities in the east coast and mandated through the NGL/NGR. The majority of stakeholders also thought this should be brought forward to 2019, with the only exceptions to this being Origin, who stated that differences in gas day start times would not impede secondary trading, and Shell, who questioned whether the benefits of bringing forward harmonisation would outweigh the costs.

The GMRG has held further discussions with the transmission pipelines, distribution networks and other parties that will be affected by bringing gas day harmonisation forward to get a better understanding of whether harmonisation could be brought forward to 1 March 2019, which is when the auction is expected to commence. Mixed views were expressed on whether:

§ harmonisation by 1 March 2019 was technically feasible: AEMO and a number of affected transmission pipelines and distribution networks, for example, noted that this timing was achievable from their perspectives. Shell, on the other hand, stated that it would require a 24-month lead time from when the NGL/NGR changes are

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implemented and noted that it would require key resources to be diverted away from other priority gas projects. While APLNG is facing a similar task to Shell, it believes there is value in bringing harmonisation forward to 2019 and noted that an April 2019 – October 2019 time frame was achievable if it had a 12-month lead time from when the NGL/NGR changes are made.

§ there was value in trying to align the harmonisation of gas day start times and nomination cut-off times with market start: While a number of stakeholders indicated that there would be value from a system perspective in aligning the two, others were of the view it may represent too much change for the market to cope with at once, while others were undecided and could see the pros and cons associated with both options.

As to whether any amendments need to be made to the operational GTA to accommodate differences in gas day start times until harmonisation occurs, AGL and Shell were of the view that this should occur, while Epic, Jemena and APA did not think this was necessary.

In contrast to gas day start times, stakeholders were divided on whether nomination cut-off times should be standardised. Origin, EnergyAustralia and Jemena, for example, did not support this form of harmonisation and noted that differences in nomination times can benefit shippers and pipeline operators from a resourcing perspective. AGL, Shell and APLNG, on the other hand, think there is value in harmonising nomination cut-off times, although AGL noted that the timing would need to take into account the National Energy Market (NEM) pre-dispatch time lines. Epic agreed there would be value in harmonising nomination cut-off times, provided it was no earlier than 3 pm (AEST). Elaborating on this further, Epic noted that the nomination cut-off time needed to accommodate the electricity market pre-dispatch and that an earlier nomination time would result in greater uncertainty and may lead to inflated nominations by some shippers to manage electricity market risks. APA, on the other hand, suggested a 2 pm nomination cut-off time was more appropriate to cater for pipeline scheduling and the additional steps that will be required as part of the auction and capacity trading reform


Having regard to the feedback provided by stakeholders and the objectives of the reforms, the GMRG recommends that:

§ A common gas day start time of 6 am (AEST) apply to all facilities and the facilitated markets in the east coast and Northern Territory once connected

In the GMRG’s view, the harmonisation of gas day start times and the application of this to all facilities and facilitated markets will, as the AEMC and ACCC have previously observed:

o reduce the costs and complexities that market participants operating across multiple facilitated markets would otherwise face; and

o increase the interoperability and interconnection between markets and, in so doing, promote participation, competition and liquidity in these markets and trade between locations.

The GMRG is therefore satisfied that this will promote the NGO and should be mandated through the NGL and NGR.

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§ A common nomination cut-off time of 3 pm (AEST) apply to pipelines and other facilities subject to the capacity trading reforms

As noted above, the adoption of a common nomination cut-off time will be critical to the functioning of the capacity trading platform and day-ahead auction, given the auction can only be conducted once the last nomination cut-off time occurs. It will also:

o enable shippers to make greater use of the capacity trading platform and day-ahead auction, which will benefit the broader market because the capacity trading platform will be able to be open for longer and the auction will be able to occur earlier (as highlighted in Table 5.13); and

o provide shippers in NSW/ACT, Queensland, Tasmania and the Northern Territory with more time to make nominations than they would otherwise have, because, as noted above, pipeline operators have advised that once gas day start times are harmonised nomination cut-off times will be adjusted to maintain the same offsets.

In the GMRG’s view, these benefits will outweigh the resourcing issues54 that a small number of stakeholders have raised and are in the long-term interests of consumers. The GMRG is therefore satisfied that this reform will contribute to the NGO and should be mandated through the NGL and NGR.

A 3 pm nomination cut-off time has been selected because, in the GMRG’s view, it provides an appropriate balance between:

o the need for service providers to have an appropriate length of time to carry out scheduling activities;

o the value shippers place on nominating as late in the day as possible; and

o the risk identified by Epic that an earlier nomination cut-off time may result in inflated nominations if it doesn’t accommodate the NEM pre-dispatch process.55

§ Harmonisation of gas day start times and nomination cut-off times should occur by 1 October 2019

As outlined above, the GMRG considered whether gas day and nomination cut-off time harmonisation should be aligned with the commencement of the auction (1 March 2019) and while it thinks there would be benefit in doing so, the GMRG understands this may not be feasible for some market participants. The GMRG is therefore proposing that harmonisation occur by 1 October 2019. In a similar manner to the 1 April 2021 date adopted by the AEMC, this date has been selected to avoid the peak summer and winter periods in the gas and electricity markets and minimise the disruption that the change may otherwise have on these markets.

While the GMRG understands that there may be some incremental costs associated with bringing forward harmonisation from 2021 to 2019, it expects the benefits associated with the removal of impediments to capacity trading across jurisdictions, as

54 It is worth noting that even if a common nomination cut-off time is adopted, there is nothing stopping shippers from trying to manage their resourcing requirements by submitting nominations earlier.

55 The GMRG understands that the pre-dispatch schedule must be issued as soon as possible after 12.30 pm on a day-ahead basis and no later than 4 pm. The GMRG also understands that the day-ahead schedule is typically issued at 12.30 pm and subsequent schedules published every 30 minutes on a rolling basis.

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outlined above, to outweigh these costs. The GMRG is therefore satisfied that this will promote the NGO.

The adoption of a 1 October 2019 time line means that there will be a gap between when the capacity trading reforms commence and when harmonisation occurs. Some transitional measures will therefore be required to deal with the differences in gas day start times and nomination cut-off times until harmonisation occurs. The close of trade on the capacity trading platform will, for example, need to be set at an earlier time while the day-ahead auction will need to be concluded later. Provisions will also need to be included in the standardised operational GTA to require service providers operating at the interface of markets to accommodate the differences in gas days. These provisions will be consulted upon in early 2018.

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Part B: Capacity Trading PlatformIn the East Coast Review, the AEMC recognised that steps had been taken by some pipelines to facilitate more capacity trading but noted that the following factors were limiting the ability of shippers to access competitively priced secondary capacity:56

§ a lack of information on the existence of prospective buyers and sellers of capacity, which the AEMC noted may be resulting in high search and transaction costs, particularly for short-term trades; and

§ limited information on the secondary capacity market, which the AEMC noted may lead to additional transaction costs as parties try to determine the value of capacity.

To address these issues, the AEMC recommended the development of a capacity trading platform that would provide for both: 57

§ an anonymous exchange mechanism that shippers can use to buy or sell commonly traded transportation products; and

§ a listing service that shippers can use to buy or sell more bespoke products.

The AEMC also suggested that the trading platform provide for as many services as possible to be traded through the exchange.58 While the AEMC expected the platform to principally be used by shippers, it noted the potential for service providers to also use the platform to sell any spare primary capacity they may hold.

Together, these reforms are expected to facilitate a greater level of secondary capacity trading by:59

§ reducing search and transaction costs; and

§ providing shippers with confidence that secondary trades are non-discriminatory (i.e. by requiring trades conducted through the exchange to be anonymous and requiring shippers to advertise products ahead of time on the listing service).

Table B.1 provides further detail on the AEMC’s recommendations, which were classified as either required or preferred outcomes.

In the East Coast Review, the AEMC identified a number of organisations that could operate and administer the capacity trading platform, but did not reach a concluded position on this issue. The AEMC therefore recommended that the GMRG consider the options in further detail. The GMRG’s recommendations on this issue were presented to the Energy Council in July 2017. In short, the GMRG recommended that AEMO be accorded responsibility for the operation and administration of a single capacity trading platform that would form part of the GSH trading exchange, which is currently used by participants in the east coast to trade gas and compression services at Wallumbilla. This recommendation was endorsed by the Energy Council at its 14 July 2017 meeting.60

56 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 93-94.57 ibid, p. 95.58 ibid, p. 104.59 ibid, p. 87.60 COAG Energy Council, 12th Energy Council Meeting Communique, 14 July 2017.

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Table B.1: AEMC’s Recommendations: Capacity trading platform reformsRequired outcomes

§ Creation of capacity trading platform(s) which include electronic anonymous exchange-based trading for commonly traded products in addition to a capacity listing service typical on current capacity trading platforms.

§ Trades carried out through trading platform to be given effect through an operational transfer

Preferred outcomes§ Single capacity trading platform operating across the east coast. § As many services as possible capable of being traded on the platform (e.g., transportation,

hub (compression) and pipeline storage services), recognising the need to avoid unnecessary complexities.

Source: AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, p. 17.

Following the Energy Council’s decision, the GMRG has worked closely with AEMO and the Capacity Trading Platform project team on the development of the end-to-end design of the capacity trading platform, which will comprise:

§ an exchange that will be used to facilitate the trade of standardised transportation products (e.g. day-ahead, daily, weekly and monthly firm forward haul, compression and park products) through either:

o the screen trade service – this service allows participants to place anonymous offers to sell or bids to buy a specified quantity of capacity (measured using the MDQ metric) at a specified price, which are automatically matched by the exchange; or

o the pre-matched trade service – this service allows participants to bring a bilateral trade in one of the GSH products to the exchange for settlement; or

§ a listing service that will allow market participants to list more bespoke transportation products (including locational swaps) that can be traded on a bilateral basis.

While the design of the capacity trading platform will share many of the same operational, market, financial, contractual and governance features of the GSH (see Appendix E for an overview of the GSH), further consideration needed to be given to:

§ the initial list of products to be sold on the capacity trading platform;

§ how the number of buyers and sellers on the exchange will be maximised;

§ the delivery process that will give effect to trades conducted through the exchange;

§ the settlement and credit risk management processes that will apply to trades conducted through the exchange;

§ the way in which the financial and delivery risks associated with exchange-based trades will be managed through the capacity trading platform; and

§ whether any changes need to be made to the NGL, NGR or other subordinate instruments to implement the capacity trading platform.

The GMRG has worked with AEMO and the Capacity Trading Platform project team to consider these issues since March 2017 and on 7 September 2017 published a consultation paper that set out a number of options for the form these design elements

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could take and the GMRG’s preliminary view on these options. Stakeholders were given four weeks to provide written feedback on the options presented in this consultation paper and were also invited to attend a public forum in Sydney on 14 September 2017. The consultation period for this paper ended on 4 October 2017.

The stakeholders that provided written submissions on this consultation paper included AGL, Origin, EnergyAustralia, Alinta, Stanwell, APGA, MEU, APLNG, Shell, Senex, APA, Jemena, Epic and TGP Pty Ltd. These submissions can be accessed on the GMRG website.61 Feedback on the capacity trading platform was also provided through extensive bilateral discussions with stakeholders (including a number of consumer groups) and by the GMRG’s Advisory Panel.

In general, stakeholders were broadly supportive of this element of the capacity trading reform package and agreed with the majority of the GMRG’s preliminary views set out in the consultation paper. A number of issues were, however, raised about, amongst other things:

§ the initial list of products to be made available on the capacity trading platform;

§ the specification of receipt and delivery point zones and the governance arrangements that will apply under the zonal model;

§ the delivery process and assumed timings for the capacity trading platform; and

§ the way in which financial and delivery default will be managed.

These issues have been further considered by the GMRG in developing its final recommendations.

Table B.2 provides a high-level summary of the GMRG’s final recommendations on this element of the reform package, which have been developed using the assessment framework set out in Chapter 3.

Consistent with the overarching objective of the capacity trading reforms, the recommendations set out in this table are expected to facilitate a greater level of secondary capacity trading and foster the development of a more liquid market by:

§ providing shippers with access to a single capacity trading platform that they can use to anonymously buy and sell standardised capacity products through the exchange (or more bespoke services through the listing service), and to co-ordinate trades across transportation assets (regardless of ownership) and to procure gas and other services;

§ maximising the pool of prospective buyers and sellers of secondary capacity and facilitating a greater level of competition between shippers for the provision of secondary capacity by implementing a zonal receipt and delivery point model with secondary firm rights at individual receipt and delivery points;

§ implementing a capacity trading platform that, from a shipper’s perspective, is easy to use, enables quick and effective execution of trades, aggregates prudential and settlement requirements across gas and capacity products, provides certainty of outcomes and effectively manages financial and delivery default risks;

61 See http://gmrg.coagenergycouncil.gov.au/publications/standardisation-related-reforms-and-capacity-trading-platform-consultation-paper

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§ minimising the implementation costs (e.g. by drawing on existing GSH procedures and processes and using existing communications systems for delivery);

§ reducing search and transaction costs and aiding the price discovery process;

§ instilling a greater level of confidence in the secondary capacity market through the use of robust delivery, settlement, credit and other risk management processes and governance arrangements; and

§ being able to adapt to changing circumstances through the ability to add and amend the product list and receipt and delivery point zones.

The recommendations can also be expected to contribute to the Energy Council’s Vision of the direction gas market development should take and, in particular, the outcomes described in 2(b), 3(c) and 3(d) in .

In the GMRG’s view, the recommendations are also fit for purpose and reflect the operational and technical requirements necessary for the safe and reliable operation of transportation assets. They also strike an appropriate balance between the legitimate business interests of service providers and other parties that have rights to use the assets, including both primary and secondary shippers.

The GMRG is therefore satisfied that the recommendations will contribute to the achievement of the NGO.

The remainder of this part of the report provides further detail on the GMRG’s final recommendations on the design of the capacity trading platform and the feedback stakeholders provided in response to the consultation paper.

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Table B.2: Summary of the GMRG’s final recommendations on the capacity trading platform Design Element RecommendationOperation of the capacity trading platform

The GMRG recommends that the capacity trading platform, which will be operated by AEMO and form part of the GSH trading exchange, provide for both:§ Exchange-based trading of commonly traded transportation (pipeline and compression) products, which can be conducted through either:

– the screen trade service, which allows participants to place anonymous bids or offers for standardised products that are automatically matched; or – the pre-matched trade service, which allows participants to bring a bilateral trade in one of the GSH products to the exchange for settlement.The screen trade service will operate on a fully anonymous basis (i.e. the names of counterparties will not be revealed pre-or post-transaction), with AEMO informing the relevant service provider of the trade once it has been executed. The service provider will then confirm the trade with each counterparty separately, maintaining the anonymity of the trading parties through this process.

§ A listing service that shippers can use to list more bespoke transportation products and imbalance trades.Trades conducted through the exchange will utilise existing GSH settlement, prudential and reporting frameworks, which means participants will receive one settlement statement for all traded products and be able to aggregate their prudential requirements across gas and secondary capacity products.

Initial set of services to be listed on the exchange

The GMRG recommends that the initial set of standardised products to be sold on the exchange include: § firm forward haul services on all major transmission pipelines (if the pipeline is bi-directional, services will be available in both directions);§ firm compression services at Moomba and Wallumbilla; and § firm park (storage) services on all the major transmission pipelines.These products will be available as day-ahead, daily (available on a 6-day rolling basis), weekly (available on a 4 week rolling basis) and monthly (available on a 3 month rolling basis) products and will have a minimum contract size of 500 GJ/day. The terms and conditions on which the buyer can use these products will be set out in the operational GTA, which, amongst other things, will specify the maximum hourly flexibility the buyer will have and provide the buyer with a reasonable endeavours renomination right.

Zonal model The GMRG recommends that a zonal model with secondary firm rights at receipt and delivery points be used to maximise the pool of prospective buyers and sellers of firm forward haul services through the capacity trading platform. To implement this model, receipt and delivery point zones will need to be established on each pipeline that will be listed on the exchange and will need to reflect the technical pipeline requirements and market requirements.

Management of financial and delivery default risks

There are two key risks that buyers will be exposed to under the proposed design of the capacity trading platform:§ The seller’s primary GTA is terminated by the service provider: In this case, the GMRG recommends that the service provider be obliged to honour the

transaction for up to two weeks after the primary GTA is terminated and receive the price established through the exchange in return for doing so. The GMRG believes this approach is necessary because the buyer will not know the seller’s identity so will be unable to carry out its own assessment of the financial viability of its counterparty prior to entering into the trade. By keeping the trade on foot for two weeks, buyers will have time to find alternative arrangements, which will promote an orderly transition and minimise the impact of default on the gas market.

§ The seller short-sells capacity: In this case, the GMRG recommends that service providers give the seller an hour to rectify the short position and if it can’t be rectified, the trade cancelled and the buyer(s) compensated. Because individual counterparties will not be known, if a trade is cancelled all secondary shippers’ capacity would be pro-rated down.


The GMRG recommends that the governance framework that currently applies to the GSH be maintained, but the necessary changes be made to the NGR, the Exchange Agreement and procedures to accommodate capacity trading and the recommendations set out above. In relation to the zonal model, the GMRG recommends that any proposal to change the zones be submitted to the Industry Panel for consideration and approved by the AER. Principles will be included in the NGR to guide this process and enable any person to make a request to change the zone.

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6. Initial Set of Capacity Products In the East Coast Review, the AEMC noted that the capacity trading platform could be used to sell a range of services on a firm, as available or interruptible basis including:62

transportation services, such as forward haul, backhaul or bi-directional services;

pipeline storage services, such as park63 or loan64 services; and

hub compression services.

While the AEMC was of the view that as many services as possible should be capable of being traded on the platform, it noted that in the initial stages of development there may be value in avoiding any unnecessary complexity by, for example, limiting the services to be sold to the most popular transportation routes at market start.65 The AEMC also noted that to maximise the pool of potential buyers and sellers of secondary capacity via the exchange, some degree of product standardisation would be required.

The remainder of this chapter sets out the GMRG’s final recommendations on:

§ the products that should be available on the exchange at market start;

§ how the pool of prospective buyers and sellers of products will be maximised;

§ how the exchange traded products should be standardised; and

§ the charging parameters that should be used for transportation products.

6.1 Initial set of products to be sold on the exchange

Background

Transportation assets can, as the AEMC noted, be used to provide a variety of transportation, storage and compression services on a firm, as available and interruptible basis (see Appendix D for an overview of these services). Like the AEMC, the Capacity Trading Platform project team were of the view that the initial set of exchange traded products should seek to maximise the level of trade and value to the market.

This view is reflected in Table 6.14, which contains a summary of the position the project team reached on the transportation, storage and compression services that should be available on the capacity trading platform at market start. As this table highlights, the project team was of the view that the initial set of products should be limited to firm forward haul, park and compression services on the transportation assets connecting major supply and demand centres in the east coast.

62 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, p. 101.63 A park service allows a shipper to inject more gas into a pipeline than it takes out on a particular day, up to a specified

level, without incurring imbalance charges. The additional gas supplied into the pipeline (positive imbalance) may be withdrawn by the shipper at a later point in time, although the total volume of gas withdrawn on a particular day must not exceed the capacity specified in the shipper’s transportation contract.

64 A loan service allows a shipper to inject less gas than it takes on any given day (negative imbalance), up to a specified level, without incurring imbalance charges. Any additional gas taken by the shipper on a particular day (i.e., the loan) must be ‘repaid’ within the time specified in the contract.

65 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, p. 97.

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Table 6.14: Project team’s views on products to be listed on the exchangeProduct View

Transportation services (forward haul, bi-directional and backhaul)

The project team agreed that firm forward haul products should be included on the exchange and be available in both directions on bi-directional pipelines. Questions were, however, raised about the value of including as available or interruptible transportation services (including backhaul services) on the exchange, with project team members noting that:§ there was unlikely to be much demand for these services given the uncertainty

surrounding deliverability; and § primary shippers usually only pay for these services when they use them and so do

not have as strong an incentive to sell these services as shippers with firm forward haul products where the shippers usually have to pay for firm capacity irrespective of whether or not they use it.

Park, or park and loan services

The project team thought there would be value in including a firm park product on the exchange because it would: § provide secondary shippers that have an existing transportation service with greater

flexibility to manage variations in demand; and § allow primary shippers that have to pay for this service irrespective of whether or not

they use it, to recover some of the fixed costs for this service.When asked if a park service could be sold on a separable basis, the project team stated that it could but noted the buyer would need its own transportation service to utilise the park service (i.e. because gas must be supplied into the pipeline and ultimately transported to the end location). In a similar manner to transportation services, the project team did not think there would be value in including an as available or interruptible park product.The project team also considered whether a park and loan service could be traded on the exchange, but concluded that the risk associated with the loan component of this product may expose the service provider to too great a risk if the shipper did not ‘repay’ the gas it had taken at the end of the trade.

Compression services between interconnecting pipelines

The project team noted that AEMO has already introduced a compression product on the GSH, which is available in the Wallumbilla Hub. Mixed views were expressed by the project team about whether the list of compression products should be expanded, with some questioning the value of including this service on the exchange, while others noted that difficulties in getting access to these services could impede trading across the market. The two scenarios that the project team discussed in this context were:1. Compression services provided in a GSH (i.e. Wallumbilla and Moomba), which

members noted could be sold on a stand-alone basis.2. Stand-alone compression services offered in other locations where the compression

service is required to address pressure differentials between interconnecting pipelines and the operator of the compression facility differs from the pipeline operator (e.g. the compressor Santos owns at Ballera, which is required to access the Carpentaria Gas Pipeline (CGP) and the compressor Lochard owns at Iona, which is used by some shippers in conjunction with storage services, to access the SEAGas Pipeline).

In the latter case, the project team thought that if compression was to be traded then the transportation product could be sold on a bundled basis through the exchange, although it was noted that the buyer would need to have operational GTAs in place with the service provider of both the pipeline and the compression facility to utilise both facilities. Like transportation and park services, the project team thought that if compression services were to be included on the exchange, it should be sold on a firm basis only.

In addition to the products outlined above, the project team considered whether locational gas swaps should be developed as part of this process and listed on the capacity trading platform (see Box 6.5 for more detail on swaps). Mixed views were expressed on this

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issue, with some team members noting that there would be value in developing locational swaps for trade through the GSH. Others were of the view that it went beyond the scope of the AEMC’s recommendations, which was to enable capacity that is not being used by primary shippers to be released to other shippers. It was also noted in this context that:

§ the delivery obligations are quite different under a locational gas swap than they are under a secondary capacity trade because swap counterparties have an obligation to deliver gas to the relevant location, while the seller of transportation capacity only has to release capacity to another shipper to use; and

§ the contractual arrangements required to underpin the swap would be quite different from the operational GTA that has been developed for capacity trades, so further work would be required to develop these arrangements.

Given these issues, the project team agreed that the initial focus of the capacity trading platform should be on the capacity products listed above and consideration given to the inclusion of locational swaps at a later date.

Box 6.5: Locational gas swaps

A physical gas swap involves the exchange of gas at different locations. Swaps may be entered into for a variety of reasons, including to overcome pipeline constraints, production constraints and geographic demand-supply imbalances. They may also be used to reduce or avoid transportation costs. The location at which gas is swapped will depend on the parties’ requirements but in general, the swap may occur at the point of production, a delivered location or a combination of the two.

The way in which a swap can work can be seen in the following example, which assumes that:

§ Santos has 20 PJ p.a. of gas in the Gippsland Basin that it wants to supply to its LNG facility in Gladstone; and

§ AGL has a 20 PJ p.a. gas supply contract in place with producers in the Bowen/Surat basins and takes delivery of that gas at Wallumbilla and then transports it to Sydney (via the SWQP and Moomba to Sydney Pipeline (MSP)) and Victoria (via the SWQP, MSP and the Declared Transmission System (DTS)).

The alternative locations at which this gas could be exchanged are as follows:

§ Santos could take delivery of the gas at either Wallumbilla or Moomba and then transport the gas to Gladstone via the SWQP and the dedicated GLNG pipeline. If the gas is taken at Moomba then AGL would have to transport the gas under its transportation contract on the SWQP from Wallumbilla to Moomba; and

§ AGL could take delivery of the gas in Sydney and/or Victoria. If the gas is supplied in Sydney, then Santos would require a GTA with either the Eastern Gas Pipeline (EGP) or the DTS and MSP to enable the gas to be delivered from the Gippsland Basin to Sydney. If the gas is supplied to Victoria then Santos could just deliver the gas into the DTS.

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The GMRG’s preliminary view on the initial set of products to be listed on the exchange was that it should include firm forward haul, park and compression services on all the major transmission pipelines.

The GMRG also agreed with the project team that the initial list of products should not include backhaul services because there were unlikely to be many suppliers of this service. This is because, in contrast to firm forward haul products where shippers usually have to pay for capacity irrespective of whether or not they use it, backhaul services are typically only paid for when they are used so primary capacity holders do not have as strong an incentive to sell these services as firm forward haul services.

In relation to locational gas swaps, the GMRG noted that while it understood swaps were becoming more prevalent, the nature of the product is quite different from the capacity products that the AEMC recommended be developed as part of the capacity trading reform package. The GMRG therefore agreed with the position the project team reached on this issue and noted that the decision to focus on capacity products would not prevent parties from entering into locational gas swaps, or advertising swaps on the listing service.

The GMRG concluded by noting that while the initial list of products may appear somewhat limited, shippers could use the listing service to advertise other products and execute these through a bilateral trade. It was also noted that if there was sufficient interest in other products, they could be added to the exchange at a later time using the Exchange Agreement change process outlined in Appendix E.


The majority of stakeholders supported the GMRG’s preliminary view on the initial list of products. There were, however, some exceptions to this. Some stakeholders, for example, thought that the initial list of products should include backhaul services. The MEU, for example, stated that backhaul services are likely to become more prominent under current market conditions (e.g. reverse flows on the MSP) and should be included to promote efficiency in gas transportation. Service providers, on the other hand, stated that backhaul services are not firm and as such shippers do not have a right to trade these services to another shipper.

Some stakeholders also questioned whether park services should be included. Jemena, for example, questioned whether this service should be offered at market start due to its complexity and noted that the priority of service must be specified because it offers multiple park services with differing priorities.

Stakeholders also expressed differing views on whether swaps should be included on the capacity trading platform. Shell, for example, noted that it was keen to see these listed on the GSH before the capacity trading platform was launched. Other stakeholders, however, suggested that while swaps are valuable, they should not be included in the initial product list given the extra complexity involved in developing standardised swap products and the risk of delays. AGL also noted that while swaps are useful they are also inflexible because they require specific swap locations to be specified. AGL also noted that the capacity trading platform would enable a participant to buy gas from one region and connect with a

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number of haulage arrangements and that this was more flexible and valuable than swaps.

In relation to compression services, a number of parties agreed with the proposed list of compression services, but others questioned whether further compression products should be added. The MEU, for example, noted that there was no proposed compression product from the Southern Hub into north flowing pipelines, even though the AEMC’s Southern Hub proposal requires compression at both Port Campbell and Longford. AGL, on the other hand, stated that there is little value in including a compression product at market start and noted that while a Wallumbilla compression product is available on the GSH it is yet to trade.


Having considered the feedback provided by stakeholders and the AEMC’s original expectations, the GMRG recommends that the initial set of exchange-based products include:

§ firm forward haul services on all major transmission pipelines (if the pipeline is bi-directional, services will be available in both directions);

§ firm compression services at Moomba and Wallumbilla; and

§ firm park (storage) services on all the major transmission pipelines.

In the GMRG’s view, this list strikes the right balance between:

§ including products that market participants will utilise; and

§ concentrating liquidity and reducing complexity at market start.

The initial list of products does not include backhaul services, because as a number of stakeholders noted:

§ these are an interruptible service and there is no firm transportation right that can be transferred under the secondary trade; and

§ primary shippers ordinarily only pay for these services when they use them and thus do not have as strong an incentive to sell these as shippers with firm forward haul products, which they usually have to pay for irrespective of whether or not it is used.

While backhaul services will not be included in the initial list of products, it is important to note that if a pipeline operates in a bi-directional manner (e.g. the MSP, the SWQP, the Moomba to Adelaide Pipeline System (MAPS) and the Roma to Brisbane Pipeline (RBP)) then firm forward haul services will be available in both directions. It is also worth noting that the GMRG is proposing that on pipelines that do not operate in a bi-directional manner an interruptible backhaul service will be available through the auction. The reform package will therefore provide market participants with greater access to backhaul services.

In relation to locational swaps, the GMRG understands the value these products present to the market and agrees with a number of market participants that there would be value in adding swaps between major trading locations to the GSH. The GMRG does not, however, think that locational gas swaps should be added to the capacity trading platform, because the objective of this platform, and the capacity trading reforms package more

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generally, is to facilitate the trade of secondary capacity and enable other shippers to utilise capacity that is not otherwise being used by the primary shipper. While swaps can achieve a similar objective to capacity trading, the delivery obligations are quite different. In short, swap counterparties have an obligation to deliver gas to the relevant location, while the seller in a capacity trade just has to release the capacity to another shipper to use. The contractual arrangements required to give effect to a swap are also quite different from the operational GTA that has been developed for capacity trades.

While swap products have not been included in the initial set of products, this will not prevent parties from entering into locational gas swaps, or advertising swaps on the listing service. Nor will it prevent AEMO from developing a gas swap product on the GSH using the Exchange Agreement change process. This change process can also be used to add other products to the capacity trading platform over time as the market develops.

Finally, in relation to compression services, the GMRG remains of the view that stand-alone compression services should be available at the Wallumbilla and Moomba GSH to enable parties to trade these services and facilitate the movement of gas across these major hubs. The GMRG has considered the concerns that the MEU has raised about compression products in Victoria and notes that the compression services required to move gas from Longford on the Eastern Gas Pipeline (EGP) or from the interconnect into NSW via the MSP will form part of the firm forward haul transportation service on these pipelines.

The only potential gap is at Port Campbell, where compression is required to transport gas from Victoria into the SEAGas Pipeline. The GMRG understands that the only third party provider of this service is Lochard, but that it only sells this service as part of a bundled underground storage and compression service. It does not appear therefore that shippers that have access to this compression facility would be in a position to sell compression on a stand-alone basis. The GMRG agrees with the MEU that this is a gap in the market, but it is unclear how this can be resolved unless a bundled compression and storage service is added onto the platform. This would require additional work to develop a standardised operational GTA that can cover underground storage and is likely to involve some other complexities. The GMRG therefore suggests that further consideration be given to including this product following market start.

6.2 Maximising the pool of prospective buyers and sellers

Background

Transportation services on contract carriage transmission pipelines have traditionally been sold on a point-to-point basis between the receipt and delivery points specified in the shipper’s GTA. While the point-to-point model works relatively well for primary sales of capacity, it may act as an impediment to secondary trade by limiting the number of buyers and sellers that can trade with each other (i.e. because few shippers are likely to have exactly the same receipt and delivery point requirements).66

66 The GMRG understands from the work carried out by the AEMC on this issue that the point-to-point nature of capacity rights may be more of an issue for industrial customers and gas fired generators because they have traditionally only sought to have gas transported from a receipt point to their facilities. Larger retailers, on the other hand, tend to enter into contracts that provide for the use of multiple delivery and receipt points. That said, larger retailers may be limited in their ability

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To overcome these impediments and maximise the pool of prospective buyers and sellers, the Standardisation project team recommended the use of a zonal receipt and delivery point model with secondary firm rights at individual points for trades carried out through the exchange. Under this model:

§ primary shippers would be able to sell their point-to-point capacity on a zone-to-zone basis; and

§ secondary shippers would be able to acquire capacity on a zone-to-zone basis and to have secondary firm rights at all the receipt and delivery points within each zone.67

The secondary firm rights concept68 is required under the zonal model, because:

§ the capacity that is sold by the primary shipper may be released from a different receipt or delivery point in the zone to the receipt or delivery point the secondary shipper intends to use in that zone; and

§ the capacity of individual receipt and delivery points within a zone will usually be lower than the zonal capacity.

To deal with these limitations of the zonal model, while also recognising the firm rights that primary shippers have to use receipt and delivery points, the secondary firm rights concept allows secondary shippers to use any receipt or delivery points within a zone but their rights at those points are subordinate to primary shippers with firm rights at those points. There is a risk therefore that if the secondary shipper nominates to use a receipt or delivery point that is fully used by primary shippers, it will not be able to use those points. The nature of this risk was discussed at some length by the Standardisation project team, which observed the following about the risks at receipt and delivery points:

§ Receipt points:

o The risk would be relatively low on pipelines that have a single receipt point, separate zones for each receipt point or can only be supplied by producers (i.e. because producers will only agree to supply gas if the receipt point is not expected to be fully utilised on a day).

o The risk may be higher on pipelines that have multiple receipt points within a zone that can be supplied with gas from other pipelines (e.g. at the entry point to the RBP, which can be supplied from Wallumbilla runs 1, 2, 3, 4 and 7).

§ Delivery points:

to add further delivery (or receipt) points to accommodate a capacity trade if they haven’t already specified those points in their GTA. They may also be constrained in their ability to transfer the capacity that they have reserved for a particular delivery (receipt) point to another delivery (receipt) point even if the delivery (receipt) point they want to transfer the capacity to is already specified in their GTA.

67 Prior to using a multi-user receipt or delivery point within a zone, the secondary shipper will need to become a party to the relevant allocation agreement and any other arrangements that may be in place at the point they wish to use.

68 The GMRG understands that the secondary firm rights concept is currently employed in in the United States and is also used on a number of transmission pipelines in Australia where shippers have rights to all the receipt and/or delivery points on the pipeline.

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o The risk would be very low at single user delivery points because the user would not agree to purchase secondary capacity (or purchase gas on a delivered basis from another party) if its delivery point was expected to be fully utilised on a day.69

o The risk would be relatively low at other delivery points because the secondary shipper is unlikely to try and use a delivery point unless, in the case of a retailer, it has won a customer from another shipper, or in the case of an end-user, it has decided to reduce supply from elsewhere. The only potential caveats to this that the project team identified were that:

- if there is a step increase in the demand for gas at a delivery point then some curtailment of secondary firm rights may be required if there is insufficient capacity; or

- if a location is serviced by two pipelines and shippers can use either pipeline then some curtailment of secondary firm rights may be required if secondary shippers try to transport more gas on one pipeline than the available delivery point capacity.

While the risk in most cases is expected to be relatively low, there is still a possibility that curtailment will be required, which is why the project team advocated the use of the secondary firm concept.

To enable secondary shippers to understand the nature of this risk and the likelihood that they will be interrupted, the project team recommended that information on the capacity of receipt and delivery points and historic flows to these points be published on the BB. If, on the basis of this information, the secondary shipper considers the risk to be too great, then it would have the option of entering into a bilateral trade with a primary shipper that has capacity at the receipt and delivery points it requires access to. In addition to having recourse to historic information, the project team noted that the risks associated with secondary firm rights could be managed by implementing one of the following options:

§ Option 1: The buyer could be notified of the points the seller is releasing capacity from at the time of transacting (either immediately before the transaction – giving the buyer an opportunity to decline, or immediately after the transaction – providing the buyer with an understanding of which points they are more likely to have firm access to). However, this approach was considered to devalue the zonal product, potentially reducing liquidity, and is potentially complex to implement.

§ Option 2: The buyer could have an opportunity to input preferred delivery and receipt points within the zone when they enter their bid on the capacity trading platform. The netting process of the platform could work to match buyers with sellers where possible. Again, this was considered too complex to implement at this stage, but could be revisited in the future if a need is identified.

To implement the zonal model, receipt and delivery point zones will need to be established on each of the pipelines that will be listed on the exchange. Some preliminary work carried out by APA, Epic, Jemena and SEAGas on receipt and delivery point zones indicates that the establishment of these zones is technically feasible, but the way in which zones are defined on each pipeline may differ as a result of differences in:

69 For example, EnergyAustralia would not agree to purchase secondary capacity to supply its Tallawarra Power Station if it knew that the delivery point capacity would already be fully utilised on that day.

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§ the capacity, pressure requirements, bi-directional capability, number and location of receipt and delivery points and other operating conditions across pipelines; and

§ legacy commercial arrangements and customer requirements at particular points (for example, hourly flexibility or gas specification requirements).

While some preliminary work was carried out on zonal definitions, further work will need to be carried out before the capacity trading platform is implemented. The principles that the Standardisation project team thought should guide the development of these zones and any future changes to the zonal definitions are set out below:

§ The bounds of the zones should maximise the pool of prospective buyers and sellers of capacity while also:

o ensuring that capacity can be transferred between points within the zone on a one-for-one basis if there is physical capacity at the relevant point; and

o minimising the risk that secondary shippers will not be able to access capacity at a receipt or delivery point within the zone.

§ The bounds of the zones should be capable of coping with future operational changes to the pipeline to minimise changes to the zonal definition over time.

§ The specification of the receipt and delivery point zones should promote the NGO and the Energy Council’s Vision and be consistent with the broader objectives of the capacity trading reform package (i.e. to improve the efficiency with which capacity is allocated and foster the development of a more liquid market for secondary capacity).

The project team also noted though there may be an inherent tension between some of these principles, so trade-offs may be required when defining the bounds of the zones.


In the consultation paper, the GMRG agreed with the project team that the zonal receipt and delivery point model should be adopted for trades carried out through the exchange, because it would enable more shippers to trade capacity and foster the development of a more liquid secondary capacity market. The GMRG also agreed with the project team’s proposal that shippers purchasing capacity through the exchange have secondary firm rights at receipt and delivery points and proposed the following prioritisation for rights at these points:

§ primary shippers with firm rights at a receipt or delivery point have the highest priority;

§ shippers with secondary firm rights have the second highest priority and are treated equally if there is insufficient capacity at a point (i.e. they all receive a pro-rata allocation of capacity); and

§ shippers with as available or interruptible rights at a receipt or delivery point have a lower priority than shippers with secondary firm rights.

The GMRG also proposed that information on the capacity and utilisation of receipt and delivery points be published on the BB so that shippers can evaluate the risk before they use the exchange to procure capacity. The GMRG did not, however, come to a view on whether any additional measures need to be put in place to manage the risks. It instead sought further feedback from stakeholders on this issue.

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Feedback was also sought on the preliminary work that APA, Jemena, SEAGas and Epic had carried out on the way in which the zonal model could be applied on their respective pipelines. The GMRG also sought feedback on whether:

§ pipelines that are connected to another pipeline should be required to define a transit point delivery zone (i.e. a zone that just consists of the delivery points that enable gas to be transported into the next pipeline) to minimise the risk that gas cannot be transported between the two pipelines;70 and

§ pipelines connected to an STTM should be required to define an STTM delivery zone (i.e. a zone that just consists of the delivery points within the STTM) to minimise the risk that gas cannot be supplied into the STTM.71

In the consultation paper, some thought was also given to the governance arrangements that would apply to the initial development of the zones and any changes that may be required in the future to accommodate:

§ technical or operational factors, such as the development of new receipt or delivery points, changes in pipeline flows, pressure or other operational conditions; and

§ market developments (e.g. the risk of interruption within a zone may be considered too great to encourage trade).

In short, the GMRG suggested that the initial set of zones be developed by pipeline operators in conjunction with AEMO and the GMRG and that future changes to the zonal definitions be subject to the same governance arrangements that will apply to the Operational GTA Code (see section 4.6). That is, service providers and market participants would be able to propose changes to the zonal definitions by submitting a change request to the industry panel, who would then make a recommendation to the AER on whether the change should be made or not.

Feedback provided through the consultation process The proposal to introduce a zonal model with secondary firm rights at receipt and delivery points was widely supported by stakeholders, with a number of stakeholders noting that the adoption of this model would provide for greater liquidity and ease of access to shippers buying and selling capacity products. Further detail on the feedback that stakeholders provided in response to the questions raised in the consultation paper is provided below.

Prioritisation of rights at receipt and delivery points

Stakeholders were broadly comfortable with the project team’s assessment of the risks associated with the zonal model with secondary firm rights and were of the view that the risk would not have a material effect on the utilisation of the platform. Alinta, for example, stated that the risks appeared manageable and the publication of capacity and utilisation data would assist with understanding this risk. APLNG also thought the risks were manageable and that historic information would assist secondary shippers understand the nature of the risk. Origin expressed a similar view about the publication of information on the capacity of receipt and delivery points and historic flows to these points on the BB.

70 For example, should the delivery zone at the western end of the SWQP only comprise the Moomba delivery point, or should it also include the Ballera delivery point?

71 For example, should the delivery zone at the Sydney end of the MSP only include Wilton?

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APGA also supported the use of secondary firm rights and stated that it is the simplest way to balance the primary rights at each receipt and delivery point and the desire to introduce a zonal trading model. APGA added that maintaining the primacy of primary firm rights is vital to ensuring sufficient investment occurs at specific receipt and delivery points to meet peak demand requirements.

Stakeholders were generally of the view that the primary shippers’ renomination rights should continue to have priority over any secondary trades and that the risk of interruption would be minimal, particularly if:

§ the renomination rights are a best or reasonable endeavours obligation; and

§ the primary shipper has released capacity from the same point.

Origin, for example, noted that it is essential primary shippers’ existing renomination rights are preserved under the zonal model because renominations (including intra-day) are crucial to managing fluctuations in gas demand. Origin added that if these arrangements are curtailed, it would undermine the ability of shippers to efficiently manage their energy portfolio. AGL and APLNG also noted that a primary shipper’s renomination rights should transfer to the secondary shipper along with the MDQ, thus slightly reducing the chance of interruption as the primary shipper will not be utilising its capacity (assuming they use the same points).

Epic also noted that it did not consider this to be a significant issue because delivery point constraints are typically limited to user specific delivery points, such as power stations and pipeline laterals. In Epic’s view, user specific agreement should already have been reached with that primary user if a secondary shipper wants to use those locations. Epic added that where a lateral is utilised, ensuring the secondary shipper acquires capacity from a current holder of firm lateral rights would ensure that the capacity is not constrained and each shipper has equal access to the capacity.

Indicative zonal definitions

While stakeholders were generally supportive of the indicative zonal definitions developed by service providers, a number of refinements were proposed by stakeholders, including:

§ Alinta who suggested that the Condamine delivery point be added to the delivery point zones in the definition of ‘Upstream of Brisbane STTM’ in the RBP section.

§ AGL who suggested that the ‘EGP Wilton’ be added to the delivery ‘Moomba’ on the MSP and as a delivery point on the EGP.

§ Epic who proposed a number of changes to the MAPS zones to expand list of delivery points.

§ TGP Pty Ltd who noted that there are some constraints on the way zones can be established on the TGP and that it was working on how best to structure the concept of zones to maximise the pool of prospective sellers, whilst also maintain technical and safe operation of the pipeline.

A number of service providers also reiterated that the zones were indicative only and that before they could be finalised detailed capacity modelling would be required.

A number of stakeholders also thought there was merit in having transit point delivery zones to minimise the risk that gas cannot be transported between two pipelines. APA

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stated that defining a single delivery point as a zone in and of itself will reduce the risk that gas cannot be transported between the two delivery points, but would limit flexibility and therefore the pool of prospective buyers and sellers.

APGA, on the other hand, thought that it seems sensible that receipt and delivery points likely to attract the most trade activity, being connection points between major pipelines and the delivery points to STTMs or other markets, be specified as single points rather than multi-point zones. Alinta supported the implementation of points that minimise the risk that gas cannot be transported between two pipelines and/or into an STTM.

There was also some debate about whether having a delivery zone is necessary for the STTM zones. APA, for example, stated that defining an STTM delivery zone is appropriate to ensure certainty when interacting with the STTM and associated market obligations. However, AGL stated that pipelines connected to the STTM do not require a specific STTM delivery point as a trading right is required to be established or confirmed prior to the utilisation of the haulage service.

AGL thought that the issues related to connected pipelines would be better managed with a common allocation agreement rather than transit point delivery zones. Elaborating on this further, AGL noted that clear and common allocation agreements that define the priority of service are a cost effective and efficient solution to resolving this matter and pointed to the Culcairn allocation agreement as a good example of how this could work.

During the consultation process, questions were raised about whether the segmentation approach employed in the United States should also be considered as part of the zonal model. The segmentation approach requires interstate pipeline operators to allow shippers to segment capacity they have purchased into separate parts for their own use, or to release the capacity to other shippers, where it is operationally feasible. The Capacity Trading Platform project team were asked their views on this issue. In short, the project team was of the view that there may only be one or two pipelines where it would be feasible to segment capacity (e.g. the MSP and RBP), because segmentation is only of value if gas can come in at multiple points on the pipeline. The project team went on to add that making provision for segmentation at this stage may overcomplicate things and it should be considered as a potential future development.

Governance arrangements for the zonal model

While shippers supported the GMRG’s preliminary view on the governance arrangements for the zonal model, service providers were of the view that they should be solely responsible for determining the bounds of the zones, because they have full knowledge of the operational requirements of each pipeline and bear the delivery obligations (with associated liability). Service providers also raised some specific concerns about the ability of the industry panel to consider the unique operational and contractual arrangements of each pipeline and noted there may be some confidentiality issues that would have to be overcome.

Elaborating on this further, APA noted that the requirement to seek approval to change zones was unnecessarily burdensome and suggested that the service provider be free to change the bounds of a zone, provided the objectives of the zonal concept are maintained. APA also noted that changes proposed by shippers should be required to be considered by the service provider, which must provide the requesting shipper with clear

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reasons for not accepting a change. APA noted that the requesting shipper could then refer the service provider’s response to the AER for review if it was not satisfied with the response, at which point the AER may seek expert advice, and ultimately require the change to zones if it is satisfied that the above principles are met.

Shippers and service providers also held differing views about whether the NGR should specify any principles regarding the specification of zones. In this case, the majority of shippers supported the inclusion of principles in the NGR, although Shell questioned whether this was appropriate given the technical nature of the rules. AGL also thought that amending the NGR to include these principles was unnecessary.

Service providers were also opposed to the inclusion of principles in the NGR. Epic, for example, noted that service providers should be able to amend the zones to take into account operational changes over time without imposing additional regulation on the change process. Epic stated that market participants should not be able to propose a change in zones as it is the service provider’s responsibility to operate the pipeline efficiently and market participants will not have the necessary background to inform their position. Jemena also thought that a service provider should not be required to accept arrangements, which result in financial detriment or are operationally not reasonably feasible. Jemena concluded that a flexible principle based approach would be preferable to a strict set of rules.


In keeping with the feedback provided by stakeholders and the broader objective of the capacity trading reform package, the GMRG recommends that the zonal model with secondary firm rights at individual receipt and delivery points be used for trades carried out through the exchange. The GMRG also recommends that provisions be included in the NGR to require service providers to accept the secondary shippers’ nominations at the points they select if it is technically feasible to do so and complies with the following prioritisation schedule:

§ primary shippers with firm rights at a receipt or delivery point have the highest priority and renominations by these shippers will have priority over other capacity holders if the service provider is able to accommodate the renomination;

§ shippers with secondary firm rights have the second highest priority and are treated equally if there is insufficient capacity at a point (i.e. they all receive a pro-rata allocation of capacity); and

§ shippers with as available or interruptible rights at a receipt or delivery point have a lower priority than shippers with secondary firm rights.

To enable secondary shippers to understand the risks associated with secondary firm rights, the GMRG recommends that information on the capacity of receipt and delivery points and historic flows to these points be published on the BB. This information is not currently available on the BB, so a rule change would be required to give effect to this recommendation. In relation to the other options that the project team noted could be used to manage the risks associated with secondary firm rights, the GMRG thinks that Option 2 may have some merit, but agrees with the project team that it is too complex to introduce at this stage. This is a refinement that could, however, be considered by AEMO in the future.

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In relation to the zones that will be adopted on each pipeline, the GMRG has considered the feedback provided by stakeholders and agrees that further work on the zonal definitions will be required during the implementation phase in 2018. The GMRG intends therefore to work with service providers, AEMO and stakeholders on this issue and, in doing so, will have regard to the feedback that has been provided through this consultation process. As part of this process, the GMRG will also consider whether provision should be made in the NGR to require service providers to allow shippers to segment their capacity, as a further measure to maximising the pool of prospective buyers and sellers of capacity.

As noted in the consultation paper, the success of the capacity trading platform will be critically dependent on the receipt and delivery point zones that are established on each pipeline. The development of the initial set of zones will therefore be guided by the overarching objectives of the capacity trading reform package and the principle that the bounds of the zones should seek to maximise the pool of prospective buyers and sellers of capacity, subject to:

§ the need for capacity to be transferred between points within the zone on a one-for-one basis if there is physical capacity at the relevant point;

§ any risk that secondary shippers will not be able to access capacity at a receipt or delivery point within the zone being at an acceptable level; and

§ the operational and technical requirements necessary for the safe and reliable operation of the pipeline and being able to adapt to future operational changes to the pipeline (i.e. to minimise changes to the zonal definition over time).

Future changes to zonal definitions to accommodate technical or operational factors and/or market developments, will also be subject to these guiding principles and the same governance arrangements that will apply to the operational GTA. Service providers and market participants will therefore be able to propose changes to the zonal definitions by submitting a change request to the industry panel, who will then consider the proposal having regard to the principles set out in the NGR and make a recommendation to the AER on whether the change should be made or not.

The GMRG understands that service providers are opposed to the use of these governance arrangements, but in its view some form of oversight is required given the critical role zones will play in facilitating trade and fostering liquidity in the secondary capacity market. The GMRG does, however, agree with service providers that if a market participant proposes a change to the zonal definitions, then service providers should have an opportunity to assess the feasibility of this change and to provide advice to the industry panel on the implications of the change. This will be provided for in the governance arrangements that will apply to both the operational GTA and the zonal model.

6.3 Standardised products to be sold on the exchange

Background

As the AEMC noted in the East Coast Review, before the firm forward haul, park and compression products can be listed on the exchange, they will need to undergo some degree of standardisation across the following service dimensions:

§ contract path (i.e. the zones between which capacity will be transported);

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§ contract size (MDQ and MHQ); and

§ contract tenor.

Table 6.15 provides a summary of the Capacity Trading Platform project team’s views on how these service dimensions should be standardised. These views have informed the development of an initial set of standardised forward haul, park and compression products that can be traded on the exchange, the details of which are set out below.

Table 6.15: Summary of views on standardised productsFirm forward haul service Firm compression service Firm park service

Contract paths or facility

The project team thought that standardised forward haul services should be available on all the major transmission pipelines in the east coast and the Northern Territory, once it is connected. The specific pipelines that were identified in this context include the RBP, Queensland Gas Pipeline, SWQP, CGP, MSP, EGP, MAPS, SEAGas Pipeline, the TGP, the Northern Gas Pipeline (NGP) and Amadeus to Darwin Pipeline (ADP).

The project team thought that if standardised compression services are to be offered on the exchange then they should be available at Wallumbilla and Moomba to facilitate trade through the hub. Some project team members also noted that there may be value in having either a stand-alone or bundled compression-transportation service at other facility interconnection points, such as Ballera.

The project team thought that standardised park services should be available on all the pipelines that offer this as a firm service, which includes the RBP, SWQP, MSP, EGP, MAPS and TGP.

Contract size

MDQ A number of project team members noted that while the current minimum MDQ parcel size for the GSH is 1 TJ, there may be value in adopting a smaller contract size for capacity products. The two alternatives that the project team identified in this context were 100 GJ and 500 GJ. Of these two alternatives, the 500 GJ option was considered more appropriate although there was some support for the 1 TJ option. The project team also agreed that these products should have a reasonable endeavours renomination right, which is reflected in the draft standard terms.

MHQ The project team noted that it may not be possible to have a standardised MHQ factor of more than 1 (i.e. MDQ/24) because not all pipelines offer MHQ flexibility. This was confirmed in the GMRG’s discussions with a number of service providers, with Epic, APA and Jemena advising that an MHQ factor of 1.1 would be possible on their respective pipelines, while TGP and SEAGas advised that they could only offer an MHQ factor of 1.

n.a.

Contract tenor The project team agreed that the term of the standardised products should, with the exception of the balance-of-day product,72 be aligned with the GSH products, which currently include:

§ a day-ahead product, which is available at the start of trade on D-1 until close of trade for the day-ahead product on D-1. § a daily product (6 days), which is available at the start of trade on D-7 until close of trade on D-2.§ a weekly product (next 4 weeks), which is currently available from Sunday until Saturday with the trading window opening four weeks prior to gas day D and closing at the end of trade on D-2. § a monthly product (next 3 months), which is currently available three months prior to the gas day until close of trade on D-2. Some members of the project team also suggested that there may be value in developing a quarterly product that could be traded out to 12 months on a rolling basis. This proposal was not, however, endorsed by all of the project team, with some members noting that it

72 A balance-of-day product will not be possible to trade because of the operation of the day-ahead auction.

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Firm forward haul service Firm compression service Firm park servicewill increase the risk in terms of forward exposure, which will increase from three months to 12 months. It was also noted that the collateral required for up to 12 months was likely to be substantial and was likely to discourage anyone from using this product.


The GMRG’s preliminary view on the initial list of standardised products that should be available on the exchange is set out in the table below.

Table 6.16: Preliminary view on standardised screen-traded products

Contract Tenor Minimum Contract Size

Day-ahead product MDQ: 500 GJ

Daily product (available on a 6 day rolling basis)

Weekly (available on a 4 week rolling basis)

Monthly (available on a 3 month rolling basis)

Firm Forward Haul Products

Pipeline Service providerRBP APA QGP JemenaSWQP APA CGP (includes compression service at Ballera) APA MSP APA EGP JemenaMAPS Epic SEAGas APA /RESTTGP (includes TGP transfer service provided by Jemena) TGP Pty LtdDTS Transfer Service JemenaNGP JemenaADP APA

Firm Park Products

Pipeline Service providerRBP APA GroupSWQP APA GroupMSP APA GroupMAPS Epic EnergyTGP TGP Pty LtdEGP Jemena

Firm Compression ProductsCompressor location Compression product Service providerWallumbilla73 Wallumbilla LPTP to Wallumbilla

HPTPAPA

Moomba MCF to SWQP In-pipe Trade Point APA

As is currently the case for gas products, the exchange-based products will be available for screen trading and pre-matched trades. Members of the project team noted that some additional pre-matched trade products may be required to enable primary shippers on

73 The current Wallumbilla compression product listed on the GSH is delivered through a swap instead of an operational transfer. A required outcome from the AEMC’s East Coast Review is that trades carried out on the capacity trading platform be given effect through an operational transfer. A new Wallumbilla compression product will therefore need to be developed to meet this requirement.

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smaller pipelines or laterals that may be subject to the day-ahead auction to trade their capacity relatively easily (for example, the Angaston and Whyalla laterals). Some other project team members suggested that the pre-matched service should be available between all zones on a pipeline, or between all points on a pipeline. There are, however, some regulatory limits on pre-matched products. The listing of these types of pre-matched products may therefore be limited by other regulatory requirements at market start.


Stakeholders generally supported the standardised products listed in Table 6.16, although some stakeholders suggested that longer dated products be considered. Origin, for example, suggested that the inclusion of a quarterly product could provide market participants with additional certainty to undertake longer-term gas trades, but noted that liquidity may be limited, particularly at market start. Origin also noted that the credit support requirements for longer dated products could limit the ability of smaller market participants to trade longer dated quarterly products. APA expressed a similar view, noting that longer tenors would introduce credit risk issues that could complicate the market design.

Jemena, on the other hand, noted that offering day-ahead services on the platform may be challenging, given the limited time available to implement the trade and make it available for use. Jemena suggested that the inclusion of this product would add considerable cost to the platform.

In relation to contract size, some stakeholders supported the proposed 500 GJ minimum contract size, while others supported a 1 TJ minimum contract size. APA, for example, was of the view that a 500 GJ minimum contract size was appropriate for the start of the market, and noted that smaller contract sizes could be added in the future if there is demand for it. Epic and Shell agreed with this view. Origin, on the other hand, noted that while it is comfortable with the proposed contract size, it is lower than the minimum contract size of 1 TJ for products traded on the GSH. Origin went on to add that, to the extent there is a desire to align the standardised contract size with the GSH, it may be appropriate to allow smaller volumes to be traded off-market. Stanwell and APLNG also suggested there was value in aligning the minimum contract size for capacity products with the 1 TJ minimum size available on the GSH.


The GMRG has considered the feedback provided by stakeholders on contract tenor and while it can see merit in adding longer date products, it agrees that doing so could add considerable complexity to the initial design, particularly in relation to the credit risk arrangements. The GMRG is therefore recommending that the term of the initial list of standardised products be limited to day-ahead, daily, weekly and monthly products.

In relation to contract size, the GMRG recommends that a 500 GJ minimum contract size be adopted and applied to all standardised transportation products available on the exchange. While this is lower than the minimum contract size for gas products on the GSH, the GMRG understands that:

§ smaller shippers prefer a smaller minimum contract size; and

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§ shippers are not limited to purchasing gas through the GSH (i.e. they may have their own gas supply contracts in place).

The GMRG does not therefore think it is necessary to align the minimum contract size for transportation products with gas products and believes that a lower minimum contract size will promote liquidity on the exchange.

In terms of the MHQ factor that will apply to the standardised firm forward haul and compression products, the GMRG understands it is not possible to develop a standardised MHQ factor because not all pipelines offer MHQ flexibility. The MHQ factor will therefore be specified in the facility specific terms of the standardised operational GTA that service providers will be required to offer.

Table 6.4 sets out the GMRG’s final recommendation on the standardised exchange based products that should be available at market start. The contract paths appearing in this table have been developed having regard to the preliminary work carried out by APA, Epic, Jemena and SEAGas on receipt and delivery point zones. As noted in section 6.2, the GMRG will work with service providers and AEMO on the zonal definitions during the implementation phase in 2018. Accordingly, some refinements may be required to the contract paths set out in Table 6.17.

Setting this aside, the GMRG is of the view that the standardised products set out in Table6.17 will make capacity more fungible, which should facilitate more secondary capacity trading through the exchange.

Finally, it is worth noting that the standardised parameters that are adopted at market start can be amended over time through the Exchange Agreement change process if there is interest in doing so. Market participants could therefore propose the inclusion of longer dated products if there was interest in having such products on the exchange.

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Table 6.17: Final recommendations on standardised exchange productsContract Tenor Contract Size

Day-ahead product MDQ: 500 GJ Daily product (available on a 6 day rolling basis) Weekly (available on a 4 week rolling basis)Monthly (available on a 3 month rolling basis)

Firm Forward Haul ProductsPipeline Receipt Zone Delivery Zone Service providerRBP Wallumbilla zone (runs 1, 2,

3, 4 and 7)Brisbane STTM zone APA

Darling Downs (Kogan North, Scotia, Woodroyd, Condamine, Windibri, Argyle)

Wallumbilla (Low Pressure Trade Point (LPTP)74

QGP Wallumbilla (High Pressure Trade Point (HPTP)75

Gladstone (Gladstone, Wide Bay, NOR, Qld Alumina, Boyne, Yarwun, Orica)

Jemena

SWQP Wallumbilla (HPTP) Moomba Compression Facility (MCF)76

APA

Moomba (MCF) Wallumbilla (LPTP)CGP Ballera (includes

compression service provided by Santos)

Mt Isa (Mt Isa Mine, Diamantina, Mica Creek, Phosphate Hill, Osborne, Cannington)

APA

MSP Moomba (MSP Inlet) Sydney STTM (Wilton) APA Moomba (MSP Inlet) Culcairn (Culcairn South)Culcairn (Culcairn North) Moomba (MCF)Culcairn (Culcairn North) Sydney STTM (Wilton)

EGP Longford Sydney STTM JemenaMAPS Moomba (MAPS IPT) Adelaide STTM (Metro Mainline) Epic

Adelaide STTM Moomba (MAPS IPT)SEAGas Brumby Adelaide STTM APA /RESTTGP Longford (includes TGP

transfer service provided by Jemena)

Hobart TGP Pty Ltd

DTS Transfer

Longford zone Entry point of DTS Jemena

Firm Park ProductsPipeline Service providerRBP APA SWQP APA MSP APA MAPS Epic SEAGas APA /RESTTGP TGP Pty LtdEGP Jemena

Firm Compression ProductsCompressor location Compression product Service providerWallumbilla77 Wallumbilla LPTP to Wallumbilla HPTP APA

74 The LPTP (Low Pressure Trade Point) is a notional point in APA’s Wallumbilla hub at the low pressure header.

75 The HPTP (High Pressure Trade Point) is a notional point in APA’s Wallumbilla hub at the high pressure header.

76 The MCF (Moomba Compression Facility) is a notional point in APA’s Moomba hub at the low pressure header.

77 The current Wallumbilla compression product listed on the GSH is delivered through a swap instead of an operational transfer. A required outcome from the AEMC’s East Coast Review is that

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Firm Compression ProductsCompressor location Compression product Service providerMoomba MCF to SWQP In-pipe Trade Point APA

6.4 Charging parameters for capacity products

Background

The GMRG understands that while the charges levied by service providers for firm forward haul, park and compression services are usually capacity based (i.e. $/GJ of MDQ) and payable irrespective of the volume of gas actually transported, there are some shippers that are currently paying:

§ a purely variable charge ($/GJ), with the charge levied by the service provider depending on the volume of gas actually transported; and

§ a combined capacity and variable charge.

This variation in charging parameters raises an important question about how the price of capacity products on the exchange should be expressed, with the options including a capacity based charge, a variable charge or a combined fixed and variable charge. The latter two of these options are problematic because they may result in the primary shipper obtaining information on how much gas the secondary shipper transported (unless the variable charge was payable to the service provider rather than the primary shipper). These two options would also result in higher system costs and complexity for AEMO, who would also need to know how much gas was transported to calculate the settlement amounts. Of the three options, the Capacity Trading Platform project team thought the fixed capacity charge ($/GJ of MDQ) option was the most workable.

If a capacity charge is applied, then the next question that must be considered is how to deal with the variable charge that the primary shipper is required to pay under its primary GTA. There are three potential ways in which this issue could be resolved:

§ Option 1: The variable charge could be paid by the secondary shipper to the service provider, which would need to be set out in the operational GTA (note that this may not be equal to the charge in the primary shipper’s GTA).

§ Option 2: The variable charge could be paid by the primary shipper to the service provider, based on the actual volume of gas transported by the secondary shipper. This implicitly allows for the primary shipper to convert the variable charge into a fixed charge when the primary shipper offers the capacity on the exchange.

§ Option 3: The primary shipper’s variable charge could be converted by the service provider into a capacity charge for that portion of capacity that has been sold for the duration of the trade (i.e. it is assumed they use all the capacity every day of the trade and the service provider retains any difference between the reserved capacity and actual volume of gas transported).

trades carried out on the capacity trading platform be given effect through an operational transfer. A new Wallumbilla compression product will therefore need to be developed to meet this requirement.

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In the consultation paper, the GMRG agreed with the project team that a fixed capacity charging parameter ($/GJ of MDQ) should be adopted for capacity products. The GMRG did not, however, express a view on the options for dealing with any variable charges that primary shippers may be required to pay and sought further feedback from stakeholders on the options identified.


Stakeholders were divided on the three options identified, with:

§ Origin and Shell supporting Option 1 because they thought it would be easier to implement and transparent with the variable charge set out in the operational GTA.

§ Stanwell, the MEU, Epic and Jemena supporting Option 2 because they thought it was appropriate for the liability to pay the variable charge to remain with the primary shipper. The MEU and Epic also suggested that the use of the fully anonymous delivery model would mean primary capacity holders would not actually know who was using the capacity so the transfer of this information on actual flows may not be a significant issue.

§ APGA, APA and AGL supporting Option 3 because they thought it would be relatively easy to implement and primary shippers would be able to factor in the variable component when determining the prices at which they are willing to trade. These parties also noted that this is the current approach applied and which shippers are comfortable working with.

§ APLNG stating that any option that results in the primary shipper becoming aware of the volumes transported by the secondary shipper should be avoided.


Consistent with the position reached in the consultation paper, the GMRG recommends that all the capacity products be sold using a fixed capacity charging mechanism ($/GJ of MDQ).

As to the approach that should be used to deal with variable charges, the GMRG has considered the feedback provided by stakeholders on each of the options and while it recognises that no option is perfect, it recommends that Option 3 be implemented because it will cause the fewest distortions and provide all parties with greater certainty about the price being paid. Under this option, the service provider will convert the variable charge into a capacity charge by assuming that all the capacity is used on every day of the trade and the primary shipper would incorporate the fixed charge into its offer.

In relation to the other options, the GMRG notes that while Option 1 would be the easiest to implement, it cannot deal with the situation where the primary shipper’s charge is a pure throughput charge or if a variable transportation charge is set at different levels for shippers on the same pipeline. There is also a risk that some secondary shippers will pay a higher variable charge than the primary shipper because the service provider will need to establish a common variable charge for all secondary shippers. The GMRG is not therefore advocating the adoption of this option. As to Option 2, the GMRG notes that a major limitation with this option is that it requires the primary shipper to be informed of the

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secondary shipper’s actual volumes shipped under the capacity transferred. Even under the fully anonymous delivery model, this could result in the primary shipper having access to information that the secondary shipper may consider confidential. The GMRG is not therefore advocating this option.

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7. Delivery Process for Exchange Traded Products Once a trade has been conducted on the exchange, the capacity will need to be transferred by the service provider from the seller’s GTA to the buyer’s operational GTA. 78 This transfer will need to occur ahead of the gas day so that the buyer can take ‘delivery’ of the capacity and make nominations against the capacity prior to the service provider’s nomination cut-off time.

At a high level, the delivery process is expected to involve:§ the provision of transaction information to service providers;§ service providers transferring the capacity from the seller to the buyer and providing

AEMO and the buyer with confirmation that the transfer has occurred; and§ AEMO transferring the STTM trading rights and/or updating the DWGM accreditation

constraints where applicable.

The remainder of this chapter sets out the GMRG’s final recommendations on these elements of the delivery process.

7.1 Provision of transaction information to service providers

The way in which transaction information is provided to service providers will depend on:

§ whether anonymity is to be preserved post-transaction; and

§ the frequency with which information is transferred.

7.1.1 Anonymity post transaction

Background

Trades executed through the exchange will occur on an anonymous basis. After a transaction occurs on the exchange there are two options with respect to anonymity:§ Partial anonymity: Under this option the counterparties’ names would be revealed

after the transaction so they can jointly confirm the transfer of capacity with the service provider; or

§ Full anonymity: Under this option AEMO would confirm the transaction with the service provider so counterparty names are not revealed.

Further detail on these options is provided below.

Partial anonymity

Under the partially anonymous approach, counterparties would be anonymous until the capacity needs to be transferred. At this point, AEMO would reveal the counterparty names so that participants can provide this information to the service provider. The


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information that counterparties would be expected to provide to the service provider, includes: § the amount of capacity that has been traded;§ the buyer’s and seller’s identities; § the seller’s GTA that the capacity will be transferred from and the receipt and delivery

points from which the capacity will be released; and§ the buyer’s operational GTA that the capacity will be transferred to and the receipt and

delivery points the buyer intends to use (note that information on receipt and delivery points could also be provided through the nomination process).

The partially anonymous option is illustrated in Figure 7.3. The top line shows a transaction taking place on the exchange. To facilitate the transfer of capacity, AEMO would reveal counterparty names and shippers would confirm the capacity transfer with the service provider separately.

Figure 7.3: Partial anonymity

The key difference between this option and the fully anonymous option is that rather than AEMO providing the transaction information directly to the service provider, AEMO would provide the information to the trading counterparties as part of the trade confirmation. The information would then be provided by the counterparties to the service provider. The cost of advising the service provider about any trades would therefore be borne by shippers rather than AEMO. From AEMO’s perspective, this cost saving is likely to be relatively low because data links would still be required for the day-ahead auction and to potentially facilitate the transfer of STTM trading rights.

Full anonymity

Under the fully anonymous option, the names of counterparties would not be revealed post transaction. AEMO’s systems would send the transaction information to the relevant service provider each day and service providers would then transfer the capacity. The way in which the fully anonymous option would operate is illustrated in Figure 7.4.

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Figure 7.4: Full anonymity

Project team’s views on the options

The options outlined above were discussed with the Capacity Trading Platform project team and a number of service providers. In short, the project team and service providers initially consulted were of the view that the fully anonymous option should be employed.


In the consultation paper, the GMRG agreed there would be merit in adopting the fully anonymous option, but sought further feedback from stakeholders on the two options.


Stakeholders supported the adoption of the fully anonymous approach, with the only exception being APA who suggested a partially anonymous system be adopted at market start and for this approach to be reviewed as liquidity increases and demand warrants. Shell, on the other hand, cautioned against the use of the partially anonymous option and noted it could have unintended consequences, such as encouraging future trades to occur off-market (i.e. because buyers and sellers names will be revealed and parties may decide to go directly to each other to avoid the platform fees).


In keeping with the views expressed by the majority of stakeholders, the GMRG recommends the adoption of the fully anonymous approach to the execution of trades on the exchange and the transfer of information. While the GMRG recognises this option will cost more to implement, it will also provide for a more robust and credible method for delivery. It is also likely to encourage more secondary trading because it reduces the risk of error and encourages parties to use the platform by preserving the anonymity of counterparties post-transaction.

In response to APA’s suggestion, the GMRG notes that AEMO considered that any cost savings associated with the partially anonymous approach are likely to be minimal, because the costs AEMO would otherwise incur providing information to service providers

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would shift to buyers and sellers and the risks could increase. There is therefore no clear benefit in implementing this option as a transitional measure.

7.1.2 Frequency with which information is relayed to service providers

Background

The consultation paper identified the following options for the provision of trading information from AEMO to the service provider:

Option 1: after each transaction – Under this option AEMO would send service providers a transaction report after each trade takes place on the platform and, subject to verification, the capacity would be transferred immediately after each trade.

Option 2: once a day for all transactions in the last 24 hours – Under this option AEMO would send net positions to the service providers once a day for all the trades that have occurred in the last 24 hours (including day-ahead trades and trades with longer tenors). Subject to verification, the service providers would transfer capacity for all tenors in time to allow shippers to nominate against any day-ahead products they had purchased.

Option 3: once a day for transactions that will be on foot the following day – Under this option AEMO would send net positions to service providers for the transactions that will be on foot the next day. Service providers would then transfer that capacity prior to the nomination cut-off time, subject to verification. AEMO could also provide additional information on transactions applying past day-ahead. This would facilitate monitoring of future positions.

These options were considered by the Capacity Trading Platform project team and service providers, who were of the view that Option 2 should be implemented because it would:

§ provide parties greater scope to resolve any issues that may arise during the capacity transfer process; and

§ enable service providers to be more informed about the expected use of their facilities.

GMRG’s preliminary view In the consultation paper, the GMRG agreed with the project team and service providers that Option 2 should be implemented and noted that this option provided a more appropriate balance between the costs of transferring information to the service provider and the management of risks.


The stakeholders that provided feedback on this issue agreed that Option 2 should be implemented. Some parties did, however, note that Option 1 could be implemented in the future, subject to the performance and liquidity of the exchange.

The consultation paper also questioned whether AEMO should net out shippers’ positions prior to transaction information being provided to service providers to transfer capacity. While most submissions supported this approach and thought it would reduce costs and complexity, Jemena noted that ‘net positions’ may not provide the detail required by service providers to effect the trades. It went on to note that it may be necessary to

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provide the full details of the intermediate trades to follow the origin of the capacity bought to enable the service provider to balance MDQs and correctly allocate any imbalance or overrun. Shell also noted the potential for the netting out positions to reduce shippers’ ability to trade at interim shipping locations (e.g. where a shipper has purchased transport as two separate legs) and could reduce trading volumes.


Based on the feedback provided by stakeholders, the GMRG recommends that Option 2 be implemented, which will require AEMO to send net positions to the service providers once a day for all the trades that have occurred in the last 24 hours. In the GMRG’s view, this approach:

§ provides a more appropriate balance between the costs of transferring information to the service provider and the management of risks;

§ provides parties greater scope to resolve any issues that may arise during the capacity transfer process; and

§ will enable service providers to be more informed about the expected use of their facilities.

As to whether AEMO should net out shippers’ positions before sending the transaction information to service providers, the GMRG believes the netted position should be sufficient for service providers’ purposes. In relation to the concerns Shell has raised about netting, it would appear that there is some confusion about what netting involves. The way in which netting is expected to work can be seen in the following example, which assumes that there are four trades and that:

§ one trade involves the sale of 20 TJ of capacity from AGL to Origin between Wallumbilla and Moomba on the SWQP;

§ one trade involves the sale of 20 TJ of capacity from Origin to ERM between Wallumbilla and Moomba on the SWQP;

§ one trade involves the sale of 10 TJ of capacity from AGL to Shell between Wallumbilla and Moomba on the SWQP and between Moomba and Sydney on the MSP; and

§ one trade involves the sale of 5 TJ of capacity from AGL to APLNG between Wallumbilla and Moomba on the SWQP and between Moomba and Sydney on the MSP.

In this example, the netting process would result in the following net positions being reported to APA as the owner of both the SWQP and MSP:

§ AGL sales of 35 TJ between Wallumbilla and Moomba and 15 TJ between Moomba and Sydney;

§ ERM purchase of 20 TJ between Wallumbilla and Moomba;

§ Shell purchase of 10 TJ between Wallumbilla and Moomba and Moomba and Sydney; and

§ APLNG purchase of 5 TJ between Wallumbilla and Moomba and Moomba and Sydney.

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As this example highlights, the only thing the netting process does is take into account offsetting positions once the trade has occurred (i.e. the 20 TJ purchase of capacity by Origin is netted against the 20 TJ sale of capacity by Origin), which is done to simplify the administration of the trades. The netting process is not therefore expected to affect the volume of trades.

7.2 Transfer of capacity

Background and GMRG’s preliminary view

Once the service provider has received information on the trades that have occurred, it will need to transfer the capacity in sufficient time for shippers to nominate against any day-ahead products that may have been purchased on the exchange.79 Service providers will also be required to confirm with AEMO that the transfers have occurred and provide buyers with notification as to when they can make nominations. The confirmation provided to AEMO could, where applicable, act as a trigger for STTM trading rights to be transferred or DWGM accreditation constraints updated.

There may be circumstances in which the service provider is unable to transfer capacity because, for example: § the seller has insufficient capacity at the time of transfer; § the seller’s primary GTA has been terminated or the seller has breached its obligations

under the Exchange Agreement and membership is terminated by AEMO; or§ the service provider’s or AEMO’s systems or processes fail.

The first two of these risks are discussed in Chapter 9, while this section considers how the risk of technical failure will be managed in the design of the trading platform. In the consultation paper, the GMRG noted that further consideration needed to be given to this issue and sought feedback from stakeholders. Feedback was also sought on whether service providers should provide AEMO with confirmation that the trade has occurred.


Most stakeholders supported the proposal for service providers to provide AEMO with confirmation that the transfer has occurred. APLNG, for example, was of the view that confirmation is required particularly in the fully anonymous model where the service provider has full visibility regarding the trading counterparties. Jemena, on the other hand, suggested that such a confirmation was unnecessary because shippers would be able to log on to service providers’ systems and review their contracted capacity levels. Jemena added that if shippers had any concerns they could raise it directly with the service provider, whereas if AEMO was involved it would give rise to some uncertainty regarding accountability.

As to whether buyers should be provided a confirmation by service providers, AGL and APLNG suggested that the buyer should only be notified if there is a problem with the transfer, while APA suggested there may be value in the buyer being notified either way.

79 Service providers will need to consider whether transferring MDQ will be undertaken manually or if systems will be built to automate this transfer.

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A number of stakeholders provided suggestions on how the risk of technical failure should be dealt with. For example:

§ AGL was of the view that the risk could be dealt with by providing the service provider additional time (such as 4/8/12 hours) to complete the transfer and that trading should be suspended until the issue has concluded.

§ Stanwell noted that failure of AEMO or service providers’ systems should not be very common and suggested a simple procedure be adopted (e.g. the transfer of capacity occurs as soon as the systems are online again).

§ Jemena noted that technical failures will happen from time to time because IT systems are not perfect and suggested that this be dealt with by cancelling trades and parties refunded any money owning. Epic and APA agreed with this suggestion.


The GMRG agrees with the majority of stakeholders that:

§ service providers should be required to provide AEMO with a confirmation once capacity has been transferred;80 and

§ buyers should only be notified if there is a problem with the transaction and the trade has to be voided (given the range of potential causes of an invalid trade, it would be sensible for AEMO to provide this notification).

In relation to the risk of technical failure, the GMRG has considered the suggestions made by stakeholders and is of the view that cancelling the trade could undermine confidence in the market. The GMRG is therefore of the view that, service providers should have a period of time to rectify the failure and complete the capacity transfer, with the rectification period to depend on the duration and start date of the capacity traded. For example, if the trade was commencing in seven days’ time, then the service provider could potentially have up to six days to rectify the problem. In the GMRG’s view, this will promote certainty and transparency for the buyer and facilitate secondary trading on the platform.

7.3 Key timings on the capacity trading platform


A number of activities will need to occur the day prior to the gas day (D-1) for the capacity trading platform and day-ahead auction to function effectively and in the manner envisaged by the AEMC. In the consultation paper, the following figure was included to provide stakeholders with an indication of the potential timing of these activities assuming a 4 pm nomination cut-off time and a fully anonymous and automated approach to transferring capacity. Stakeholders views were sought on the indicative timeframes. It is worth noting that some refinements have been made to this timeline since the consultation paper was issued. These changes are reflected in Table 5.13.

80 In this regard it is worth noting that capacity trades will need to be provided with a matching buy and sell transaction, so if one side of the trade is deemed ineligible the pair will be rejected and hence the service provider will have to inform AEMO the trade is invalid.

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Figure 7.5: Illustrative D-1 timeline

In the consultation paper, the GMRG noted that the capacity trading platform could be configured to enable the trade of day-ahead products to close at either:

§ a uniform time across all pipelines (e.g. 11 am); or

§ different times depending on the pipeline’s nomination cut-off time.

It was also noted that while different cut-off times for day-ahead products would provide participants with more flexibility, it might add to complexity for little additional benefit.

The GMRG therefore proposed the adoption of a uniform close of trading time, but sought feedback from stakeholders on this option.


Proposed timeframes for platform

Most shippers provided in principle support for the proposed timeframes, although some questions were raised about the time at which particular activities are assumed to occur. EnergyAustralia and AGL for example, stated the timings set out in Figure 7.5 seemed appropriate, although AGL supported a shortening of the trading period for day-ahead products because there are few options to source gas after 3 pm for the next day (Wallumbilla and the DWGM being two exceptions). Stanwell, on the other hand, was of the view that an 11 am cut-off for the trading of day-ahead products was too early and suggested that further consideration be given to whether:

§ service providers require 3.75 hours to transfer capacity; or

§ service providers could be provided more time to update capacity on a day-ahead basis, by being sent the capacity trades as they occur rather than waiting for a daily report from AEMO.

APLNG also questioned whether service providers require 3.75 hours to transfer capacity.

Shell suggested nomination cut-off times be brought forward to enable the day-ahead auction to be conducted earlier in the day, but suggested that further industry consultation may be necessary to determine an appropriate time.

Service providers raised some concerns with the timing assumed for the provision of information on auction capacity, with a number of service providers noting that one hour

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would be insufficient to carry out the scheduling and determine auction quantities. APA noted that a period of at least two hours would be required given the time scheduling currently takes and the additional complexity introduced by the capacity calculation, validation and data transfer process. Jemena also noted the proposed timing may provide service providers very little time to set up the pipeline for operation the following gas day, which has the potential to impact security of supply. It also expressed some concerns about D-1 trading compromising the ability to develop accurate pipeline flow forecasts.

Epic, on the other hand, thought the proposed timings were acceptable although they would have to adjust them slightly to align with their nomination cut off times. Epic was of the view that a minimum of one hour should be provided between when a set of data becomes available and any expectation for a service provider to execute an action based on that data.

Trading period for day-ahead products

While most shippers supported the adoption of a uniform trading time, Shell and Stanwell stated that they would prefer the close of trade to be linked to the nomination cut-off time for each pipeline to allow shippers additional time to trade on the platform. Shell and Stanwell stated that this was consistent with the objectives of encouraging trade to occur ahead of the day-ahead auction. Stanwell went on to add that traders already deal with different times and allowing this for capacity products would provide traders additional flexibility.

Some service providers also raised concerns with introducing a uniform trading time. APA, for example, considered that a uniform trading time should only be introduced when gas day harmonisation occurs. Jemena was of the view that each pipeline should have the flexibility to set its own trading times as suits its operation. It noted that the cost impost to lesser used pipelines in providing the same utility as busier pipelines is disproportionate to the benefit shippers would receive.

In the consultation paper, stakeholders were asked if uniform close of trading time was to be adopted, whether 11am was the appropriate time. Mixed views were expressed on this issue, with some parties suggesting a later time, while others suggested the closing time be brought forward.


As the preceding discussion highlights, a number of activities will need to occur the day prior to the gas day (D-1) and deciding on the appropriate timeframes for these activities requires a number of factors to be balanced. Having considered the feedback provided by stakeholders, the GMRG is of the view that there would be value in carrying out further work on the timings of key activities for the capacity trading platform and the day-ahead auction once the design of the day ahead auction and the system requirements are better understood. The GMRG intends therefore to work with AEMO and stakeholders on this issue in early 2018.

While the timing of particular activities will be subject to further consultation, the GMRG recommends that a uniform close of trade be implemented for day-ahead products. This is consistent with the GMRG’s recommendation that a uniform nomination cut-off time of 3 pm be adopted by 1 October 2019 (see section 5.3) and will reduce the complexity of the

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market for both shippers and service providers. The table below provides an indication of what this will mean for the close of trade for day-ahead products both pre and post harmonisation of gas day start times and nomination cut-off times.

Table 7.18: Indicative timings for the trading platform and auction (all times AEST)Gas Day Start Time

Indicative Timing for Capacity Trading Platform Close for Day-Ahead Products*

Pipeline Nomination Cut Off Time for Gas Day D+1**

Indicative Timing for Day-Ahead Auction***

Auction Capacity Published

Auction Bids Due

Auction Completed

Current Gas Day and Nomination Cut-Off TimesNSW/ACT 6:30 am

11:00 am

2-2:30 pm

5:45 pm 6:15 pm 6:45 pm

SA 6:30 am 3:30 pm

Queensland 8:00 am 3-4:00 pm

Tasmania 6:30 am 1:30 pm

Northern Territory 8:30 am n.a. 2-2:30 pm

Victoria 6:00 am n.a. n.a. n.a. n.a. n.a.

Harmonised Gas Day and Nomination Cut-Off Times

NSW/ACT

6:00 am 12:30 pm 3:00 pm 4:45 pm 5:15 pm 5:45 pm

SA

Queensland

Tasmania

Northern Territory

Victoria n.a. n.a. n.a. n.a. n.a.Notes: * Trading assumed to end 2.5-3 hours before nomination cut-off time to allow pipeline operators to make MDQ transfers.** Nomination cut-off times assumed to be offsets to gas day start times.*** Capacity assumed to be published 1.5 hours after nomination cut-off time. Shippers are then assumed to have 30 minutes to make their bids in the auction. The auction is then assumed to be completed within 10 minutes of bids closing.

7.4 Interaction between the delivery process and other markets


The consultation paper contained a detailed discussion on integration with both the STTM and DWGM81 and sought feedback on the following issues:

§ The timing interactions between the STTM and the platform, in particular whether participants had any concerns about the proposal that shippers wanting to participate in the ex-ante STTM schedule would need to purchase the capacity on D-2.

§ How to achieve integration of the capacity trading platform and the STTM, including the process for transfer of STTM trading rights, with the options including transferring STTM rights on:

o a manual and partially anonymous basis;

o an automatic and fully anonymous basis; or

81 See Section 8.3 of the GMRG Standardisation and Capacity Trading Platform Consultation Paper – Sept 2017

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o a manual and fully anonymous basis (hybrid option).

§ How market participants currently manage MHQ constraints in the DWGM and the options for dealing with accreditation constraints, which included:

o a standing accreditation constraint: A default accreditation constraint could remain in place for all transactions unless a participant requests a change.

o an automatic accreditation constraint: Automatic update of accreditation constraint when capacity is purchased on the capacity trading platform.

o a blank accreditation constraint: No accreditation constraint is entered for capacity purchased on the platform or auction.


STTM timing interactions

Only a small number of stakeholders commented on this issue, all of whom raised concerns with the potential D-2 timing limitation. EnergyAustralia, for example, suggested that it would be better if the timing was closer to the D-1 bid/offer cut off time, however it understood that transferring Trading Rights Number (TRN) and registration could take time. AGL noted the timing was linked to the TRN process, but stated that in its view the TRN process is complicated and should be reviewed to negate/reduce this D-2 limitation.

Stanwell, on the other hand, indicated that while the situation was not ideal, it expects traders to be able to work with this timeframe including by organising trades on D-2 and participating in the STTM through the MSV schedule. Stanwell did not support a change to the timings of the STTM or any other proposal which alters existing markets just to better integrate the day ahead capacity product with the STTM.

Process for transferring STTM trading rights

Generally, participants supported an automatic and fully anonymous approach to transferring STTM trading rights, although some suggested that further consideration of the systems and costs is required.

AGL and Stanwell, for example, suggested that the integration with the STTM be delayed until after market start given the short amount of time to market start and the amount and cost of IT work for AEMO, service providers and shippers and the potential for this integration to be quite complex.82 Origin also noted that automating the flow of information would provide for a more efficient transaction process and reduce the risk of administrative error, but suggested that further information describing the extent to which this automation can be achieved, and the overall implementation costs, is needed to fully evaluate this proposal.

Accreditation for DWGM

The majority of stakeholders did not comment on this issue. The stakeholders that did comment suggested that this is a detailed implementation issue that did not need to be resolved at this stage of the process.

82 For example, which TRN do you reduce if there’s more than one, what service priority does a trade get and what if a participant’s firm TRN in the STTM is not listed as priority ‘1’)

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AGL was the only stakeholder to provide any feedback on the options identified in the consultation paper. In short, AGL was of the view that:

§ standing constraints may work if they are published and set in a manner than does not cause more traditionally accredited shippers to be disadvantaged (i.e. the accreditation should not be more generous); and

§ blank accreditation would be a concern if they are treated as ‘unconstrained’ in scheduling given that any unconstrained bid/offer would be superior to a more accurate bid/offer that is subject to the constraints of accreditation.


The GMRG recognises the practicalities associated with integrating the DWGM and STTM with the capacity trading platform require further consideration and development. AEMO has also advised that further consideration and assessment is required on these matters before a final decision can be made. The GMRG intends therefore to work closely with AEMO during the implementation phase and carry out further consultation with stakeholders as required. As part of this process, the GMRG and AEMO will consider whether there are any solutions to the D-2 limitation for participation in the ex ante schedule for the STTM.

On a separate but related issue, it is worth noting that trading rights can currently only be transferred from one shipper to another through a bare transfer. That is, under the NGR, there is no relationship between the service provider and buyer of secondary capacity. When a capacity trade occurs, the seller makes nominations to the service provider on behalf of the buyer. As outlined in Part A, a required outcome under the AEMC’s recommendations is that trades carried out through the exchange and day-ahead auction be given effect through an operational transfer. Under this transfer mechanism, a relationship is established between the buyer of secondary capacity and the relevant service provider. Changes will therefore need to be made to the NGR to enable STTM trading rights to be transferred between shippers via an operational transfer.

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8. Settlement and Credit Risk Management Effective settlement and credit risk management processes provide participants with confidence in the integrity of the market. The remainder of this chapter sets out the GMRG’s final recommendations on the settlement and credit risk management processes that should apply to capacity products purchased through the exchange.

8.1 Centralised settlement system

Background

Currently on the GSH trades carried out using the screen trading or pre-matched service are settled centrally by AEMO, with settlement amounts calculated and reported to each market participant on a daily basis.83 The daily settlement calculation enables the credit risk of trading participants to be monitored on a daily basis.

The settlement amount for a trading participant that has purchased capacity products through the exchange will be calculated having regard to:

§ the face value (i.e. price x quantity) of each transaction the trading participant has entered into;

§ the value of any reallocation that the trading participant has entered into;84

§ the market fees payable by the trading participant; and

§ any miscellaneous settlement items that do not fit into the above categories.

While settlement amounts are calculated on a daily basis, the GSH billing cycle is monthly. Final settlement statements are therefore prepared and issued by AEMO to participants on a monthly basis, in part based on information provided by trading participants about deliveries. AEMO also prepares revised settlement statements three months after the final settlement, which are based on the most recent gas delivery information and include any adjustment that may be required to account for differences between the settlement amount specified in the final settlement statement and the revised settlement statement.

When presenting its proposal to operate the capacity trading platform, AEMO proposed to combine the settlement amount for capacity products with the settlement amount for GSH gas products and to issue one settlement statement for all products traded on the GSH.85 This proposal was supported by project team members.

83 AEMO uses the Austraclear system to clear the market and process security deposits provided for prudential purposes (see AEMO Market Clearing Procedure). This system provides real-time gross settlement of transactions and is widely used in the finance industry for the settlement of transactions.

84 See Box 9.1 of the consultation paper for more detail on reallocations.85 A breakdown of the settlement amounts for capacity products would, however, be listed as a

separate line item on the settlement statement.

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In the consultation paper, the GMRG agreed that there would be value in using the existing GSH settlement process and combining the settlement amounts for capacity products and gas products, but sought further feedback on these issues.


The stakeholders that provided feedback on this issue supported the GMRG’s preliminary view. AGL, for example, noted its support for any move to combine or simplify settlement amounts, but noted that some changes to the current settlement arrangements might be required to calculate daily settlement amounts with monthly invoicing that aligns with the GSH. Shell and APLNG were also of the view that it is sensible to combine the settlement amounts and for one statement to be issued, subject to the caveat that separate information is listed for gas and transport products.


In keeping with the views expressed by stakeholders, the GMRG recommends that a centralised settlement system be implemented. The centralised system, which will cover all products traded through the GSH, including both gas and capacity products, will facilitate access to the exchange by reducing trading costs. This recommendation will also enable the co-ordination benefits associated with having a single platform that market participants can use to trade gas, hub services and secondary capacity and to co-ordinate secondary capacity trades across pipelines to be realised.

8.2 Centralised credit risk management

Background

Credit risk in the GSH is managed centrally by AEMO through the collection of credit support (collateral) from each trading participant to cover their prudential exposure. In a similar manner to settlement, AEMO has proposed to aggregate the prudential requirements across all products on the GSH, which means that if a trading participant has an offsetting exposure in another product, it will reduce the collateral requirements.

In the event of a payment default AEMO would call upon that trading participant’s collateral to meet payments to traders that are owed money from the market. In the unlikely event there is a payment default and the trading participant’s credit support is insufficient to meet its exposure, then any shortfall will be borne by market participants that are owed money by the market.

The primary mechanism that is used for credit support in the GSH is an unconditional bank guarantee from an authorised financial institution or state-owned treasury. Cash deposits, which are treated as an interest-bearing security deposit, may also be used for collateral up to a cap of $100,000 if a participant has not lodged a bank guarantee with AEMO, or if a bank guarantee has been lodged up to the value of the bank guarantee. Cash deposits are not considered a payment for goods or services, but are made by the participant as a pre-payment against future liabilities. The security deposit must therefore be lodged against a specific billing period, and unless alternative instructions are

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provided, the security deposit and applicable interest are applied to the settlement of the designated billing period. Reallocations are another mechanism available to participants to reduce exposure to AEMO and therefore collateral requirements.

Under the GSH, prudential assessments are performed each business day to assess the trading position of each participant against the level of collateral provided and to determine whether further collateral is required. The trading position is determined once a day within the settlement and credit risk management system.

The consultation paper provided a detailed explanation of the current GSH procedures to calculate participant’s credit exposure against which they have to provide a form of collateral. The collateral participants are required to provide varies as follows:

§ during the settlement period buyers provide 100% collateral against the face value of their net position and sellers are owed 100% of the face value of their net positions;

§ during the delivery period buyers provide 100% collateral against the face value of their net position while sellers are owed 25% of the face value of their net positions; and

§ during the forward period buyers and sellers are required to hold 25% collateral against their net positions.

The rationale behind a lower collateral requirement in the forward period is that if a default occurs, then AEMO will cancel the transaction and the counterparty has time to go back to the market and purchase or sell the product to try and make itself whole. The risk is that the market price has moved in an adverse direction from the time of the original transaction. Without daily margining, this risk cannot be completely removed. However, it can be mitigated by requiring traders to hold some collateral that can be used by AEMO to compensate the impacted market participant.

In discussions with the Capacity Trading Platform project team, project team members questioned whether the same amount of collateral should be required for capacity products because:

§ the price of capacity is effectively capped at the as-available price offered by the service provider; and

§ in contrast to gas, capacity prices are likely to exhibit low levels of volatility in the short-term.

One of the options discussed in this context was to reduce the collateral requirement for capacity products in the forward period to, for example, 10%. The risk with reduced collateral is that compensation paid to a counterparty impacted by a default is reduced, which may result in a loss on the original transaction. Further, if quarterly products are listed 12 months out, then there may be a greater level of volatility over that period and the lower level of collateral may be insufficient to compensate the impacted counterparty. The other point to bear in mind with the collateral is that transportation products are lower cost products than gas products, so a 25% collateral level applied to a $1/GJ of MDQ forward haul product is only $0.25/GJ of MDQ. This is in contrast to gas products, where a 25% collateral level applied to an $8/GJ gas price is $2/GJ.

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In the consultation paper, the GMRG agreed with AEMO’s proposal to aggregate the prudential requirements across all products on the GSH, but sought further feedback from stakeholders on whether the same level of collateral should be provided for both capacity and gas products, or should it be reduced.


There was widespread support from stakeholders to aggregate the prudential requirements across gas and capacity products on the GSH. Differing views were, however, expressed about whether lower levels of collateral should be required for capacity products:

§ AGL, for example, thought that with the proposed contract durations (as long as one month) the current collateral requirements seems appropriate (i.e. enough to cover the potential compensation under a default). Stanwell was also comfortable with the current arrangements and noted that because capacity is typically a relatively low value product, the level of collateral is unlikely to constitute a barrier.

§ EnergyAustralia, on the other hand, thought that a lower level of collateral would be beneficial for the secondary capacity market.


For similar reasons to those set out for the centralised settlement arrangements, the GMRG recommends that the prudential requirements be aggregated across all products traded through the GSH. In short, the GMRG expects the aggregation of the prudential requirements to facilitate access to the exchange by reducing the barriers to trade and enable the co-ordination benefits associated with a single platform to be realised.

As to the level of collateral that should apply to capacity products, it is important to recognise that the design of the collateral requirements will have a bearing on the effectiveness of the platform and requires careful balancing between protecting participants from default and not acting as a barrier to entry. Having regard to the feedback provided by stakeholders, the GMRG is of the view that the same collateral levels should apply to capacity and gas products and that if the longest dated product is a one month product, then the current collateral levels seem appropriate. The GMRG does, however, think this should be revisited by AEMO if longer dated products are introduced, because a 25% up-front collateral requirement could act as a barrier to trade.

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9. Financial and Delivery Default ArrangementsA seller of capacity products on the exchange, which could be either a primary or secondary shipper, could default on its delivery obligations for one of the following reasons:

1. the seller defaults on its primary GTA or operational GTA with the service provider and the service provider decides to suspend or terminate the contract;

2. the seller defaults on its delivery obligation – in the case of capacity, most likely due to the seller selling more capacity than it has a right to use under a primary GTA or other secondary trade (short-selling); and/or

3. the seller defaults on its financial obligations in the GSH and AEMO decides to close out the seller’s trades.

While measures are in place under the NGR and Exchange Agreement to deter trading participants in the GSH from defaulting on their financial and delivery obligations (see Appendix E), the Capacity Trading Platform project team was of the view that additional measures may be required to deal with the risks outlined above.

The GMRG agrees with this view and notes that the inclusion of credible and robust arrangements for resolving these forms of financial and delivery defaults will provide market participants with additional confidence in the capacity trading platform, which should, in turn, encourage more trade through the exchange. The remainder of this chapter sets out the GMRG’s final recommendations on the arrangements that should be put in place to deal with the financial and delivery default risks outlined above.

9.1 Seller defaults on its GTA with the service provider

There are two potential ways in which a seller of secondary capacity could default on its GTA with a service provider:

§ the seller defaults on its primary GTA; or

§ the seller defaults on its operational GTA.

9.1.1 Seller defaults on its primary GTA


If the seller of capacity is a primary capacity holder that defaults on its obligations under the primary GTA, then the service provider may suspend or terminate the primary GTA, which means the capacity may no longer be available to the primary capacity holder to transfer to the buyer(s). This risk is not currently addressed in the GSH arrangements.

The following options were identified in the consultation paper to deal with this risk:

1. The trade is cancelled and the buyer compensated (currently 25% of the face value of the trade), which is the approach that is currently used in the GSH. If more than one

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secondary shipper holds the defaulted capacity, the cancelled capacity would be shared between the secondary shippers on a pro-rata basis.

2. The service provider honours the trade, either in its entirety or for a defined period of time (e.g. one month), and receives the price that was established through the exchange in return for doing so.

3. The trade is cancelled and the buyer is compensated, but either:

a. the buyer has a first right of refusal to acquire the capacity released by the primary shipper from the service provider for the remaining term of the trade at a price specified in the operational GTA; or

b. the operational GTA allows the buyer to initiate good faith negotiations with the service provider about access to the capacity for the remaining term of the trade.

It was also noted that under each of these options, the service provider may still have a claim to payment for the capacity under the primary GTA.

The Capacity Trading Platform project team suggested that to promote an orderly transition and minimise the impact of default on the operation of the gas market, the second and third options were worth exploring further and that a combination of the two could also be used. For example, the service provider could be required to honour the trade for up to one month and if the trade extends beyond this, the buyer could initiate negotiations directly with the service provider to access the capacity for the duration of the contract.

The GMRG did not express a view on the options outlined above in the consultation paper. Rather, stakeholder feedback was sought on how this risk should be managed and, in particular, whether the trade should be kept alive, or if the current compensation arrangements available through the GSH were sufficient.


Mixed views were expressed by stakeholders on this issue. Service providers, for example, argued strongly against Option 2 (i.e. keeping the trade on foot):

§ Jemena believed that capacity should be treated in the same way as gas traded on the GSH and noted that service providers should be free to sell the capacity to any party (including the secondary shipper) that is willing to buy it.

§ APA suggested it would be inappropriate for a service provider to assume liability for a trade entered into by the primary shipper.

§ Epic was of the view that service providers should not be obliged to continue to supply the capacity where the risk of supply potentially outweighs the capacity price obtained. Instead, Epic suggested that Option 1 or Option 3(b) was more appropriate, because it removes any risk that the capacity was transacted as a bundle at a potentially low price.

§ APGA stated that where default does occur and the service provider has the ability to complete delivery, the capacity provided should be treated as any other uncontracted capacity for sale.

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AGL and Stanwell indicated that Option 1 (i.e. trade cancelled and parties compensated) was reasonable, although AGL noted this was subject to the caveat that the secondary shipper has the option to purchase the capacity from the service provider. Stanwell, on the other hand, did not support any extra obligations being placed on service providers and noted the potential for a seller at risk of default under their primary GTA to believe selling their capacity on the platform (at reduced rates) will help to avoid default.

In contrast to AGL and Stanwell, Shell and APLNG supported Option 2 (i.e. keeping the trade on foot) and noted that this was required because secondary shippers will have likely also entered into gas sales. Shell recommended a modified version of Option 2 with 6 weeks continued use and the right for the buyer to have first refusal for the capacity.

Stakeholders were also divided on whether the buyer should have a first right of refusal to acquire the capacity released by the defaulting primary shipper. AGL and Shell, for example, thought this was reasonable. Service providers, however, did not think this was appropriate. APA, for example, stated that introducing such a measure would require significant procedural complexity for something that would not be expected to occur on a regular basis and noted that a secondary shipper would be able to approach the service provider to buy primary capacity at any time and that no special rights or arrangements were necessary for this to occur. Jemena also noted that this option could overcomplicate the issue. Epic thought that it was important to consider the effect on the queuing arrangements the service provider may have. Stanwell was of a similar view to service providers, but noted that if buyers are to have the option then they should only have a general right to initiate good faith negotiations.


Before setting out the GMRG’s final recommendation on this issue, it is worth noting that the market conduct rules in Part 22 of the NGR (rule 543) have been put in place to deter participants from defaulting on their financial or delivery obligations and to deal with any default that does occur. The risk of default under a primary GTA is therefore expected to be a low probability event, which means that any obligation imposed on service providers is likely to have minimal effect in practice.

While the probability of this form of default is low, the GMRG believes that there should be a clear and credible mechanism for effectively managing this risk and protecting the integrity of the exchange, particularly given that buyers will be unable to conduct their own risk assessment of the sellers. Buyers will therefore rely on the exchange to have appropriate default arrangements in place. In this context, it is appropriate for the buyer to have some protection against the risk of default, otherwise confidence in the market will be undermined.

To this end, the GMRG recommends that service providers be required to honour any trades that have been entered into by a primary shipper for up to two weeks following the suspension or termination of the primary GTA and to receive the payment the primary capacity holder would otherwise have received from the secondary shipper.86 Service providers will not, however, be required to provide the buyer with a first right of refusal to acquire the capacity. In practice this obligation means that:

86 The service provider may still have a claim to payment for the capacity under the primary GTA.

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1. if the trade is due to be completed within that two week window, it will be honoured in its entirety;

2. if the trade extends beyond the two week window, then it will only be honoured for the two week period and the buyer will then have to put in place other arrangements for the remaining term; and

3. if the trade is not due to commence until after the two week window, it will be cancelled.

In the latter two of these cases, the buyer would receive compensation through the GSH for any part of the trade that is cancelled.

In the GMRG’s view, this approach will provide for an orderly termination process that minimises the impact on the operation of the gas market and appropriately balances the interests of both buyers and service providers. As one project team member noted, service providers are better placed to manage this risk of termination (i.e. because the decision to terminate is within their control) than secondary shippers and could also benefit from such an arrangement, because in any subsequent action against the primary shipper, they would be able to demonstrate that they had taken steps to mitigate their loss.

Keeping the trade on foot will also minimise the risk of systemic default across the gas and capacity markets (i.e. since the cancellation of a capacity trade may also affect gas trades given the complementary nature of these products), because it will provide the buyer more time to manage its exposure and to seek alternative solutions.

Finally, it is worth noting that the GMRG did give some thought to whether the risk could be dealt with by increasing the collateral requirements on sellers and the compensation paid to buyers, but concluded that this option would not be as effective and could give rise to additional barriers to trade. In this regard, it is worth noting that because the GSH is a voluntary market, the trade-offs around the costs and benefits of managing risk need to be considered keeping in mind that participants can bypass the market. The checks and balances need to be rigorous enough to provide confidence in the platform, but not so costly as to deter participation.

9.1.2 Default under operational GTA


If the seller of capacity is a secondary capacity holder that defaults on its obligations under the operational GTA, then the service provider may suspend or terminate the operational GTA.

This risk was discussed with the Capacity Trading Platform project team, who noted that if default under the operational GTA occurred:

§ after the transfer is effected, the trade could stay on foot because the transfer would give the buyer “good title” (subject only to a default under the primary shipper’s primary GTA); or

§ before the transfer is effected, the transfer could be cancelled and the buyer would receive 25% of the face value of the trade as compensation.

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The GMRG did not express a view on either of these options in the consultation paper. It instead sought further feedback from stakeholders on the approach proposed by the Capacity Trading Platform project team.


With the exception of Jemena, stakeholders agreed with the approach proposed by the Capacity Trading Platform project team to deal with default under an operational GTA both before and after the transfer is affected. Shell, for example, noted that keeping transactions on foot to the extent possible would provide participants with more confidence in the market. Jemena, on the other hand, stated that keeping the transaction on foot could have a “catastrophic” effect on pipeline operations that may impact the entire market. Elaborating on this further, Jemena noted that the breach of an operational GTA could be a result of imbalance issues or off specification gas, which would affect all shippers. Jemena added that it thought the proposal only covered a shipper that has on sold the capacity in its entirety leaving it with a net zero MDQ.


The GMRG has considered the feedback provided by stakeholders and for similar reasons to those set out in section 9.1.1, is of the view that the approach proposed by the Capacity Trading Platform project team is a sensible way of dealing with the risk of default under an operational GTA. The GMRG therefore recommends that if the default occurs:

§ after the transfer is effected, the trade would stay on foot because the transfer would give the buyer “good title” (subject only to a default under the primary shipper’s primary GTA); and

§ before the transfer is effected, the transfer would be cancelled and the buyer would receive 25% of the face value of the trade as compensation.

In relation to the concerns that Jemena has raised, the GMRG notes that the proposed solution will not prevent service providers from suspending or terminating the secondary shipper’s operational GTA. If this occurs, however, the capacity will not revert to the service provider. It will revert to the primary capacity holder. This is an important distinction between this situation and the situation described in section 9.1.1 and in the GMRG’s view means that if the trade has been effected it should stay on foot.

9.2 Seller short-sells capacity


Consistent with the GSH arrangements for gas products, the proposed design of the platform does not require trading participants to provide evidence that they have capacity that can be sold through the exchange. Trading participants will instead be required to warrant as a term of each product that they have all necessary rights under agreements with gas transporters to deliver the capacity. There is therefore a risk that a seller could sell more capacity than it has the right to use, either deliberately or inadvertently.

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This risk was discussed with the project team and while some consideration was given to developing a registry of capacity contracts that could be used by AEMO as part of a pre-trade verification process,87 the project team noted that:

§ the development and maintenance of such a registry would be a major task because AEMO would need to be provided access to all GTAs (including bilateral trades) and monitor changes in capacity rights across contracts over time; and

§ the costs of developing such a registry were likely to outweigh the benefits of preventing short-selling.

The project team therefore considered other options for dealing with the risk of short-selling. The two options that were identified included:

1. Cancelling the trade as soon as the service provider becomes aware that the seller does not have sufficient capacity to sell to give effect to the trade. Under this option, the trade would be cancelled by the transfer cut-off time and the buyer would be compensated for the cancellation.

2. Providing the seller a period of time within which to rectify the short position if there is any spare capacity on the pipeline. Under this option, the short seller would have an opportunity to rectify the short position by, for example, purchasing additional capacity through the capacity trading platform or from the service provider, and if it fails to do so the trade would be cancelled and the buyer would be compensated.

Some project team members noted that another option that could be used if financial players are to be encouraged to participate in the market is for participants to enter into an arrangement with a service provider ahead of time to obtain firm capacity up to a specified level if they end up with a short position (in effect, a call option).

The GMRG did not come to a view on these options in the consultation paper. It instead sought feedback from stakeholders on whether there was value in developing a register of capacity contracts and, if not, the options that should be used to address the risk of short-selling and what should occur if the short-sale cannot be rectified.


There was broad agreement among stakeholders that the costs of establishing and maintaining a capacity registry to prevent short-selling would outweigh the benefits and that the risk of short-selling should be managed in the same way as trades through the GSH. A number of stakeholders noted that the registration process in the GSH, the market conduct rules and other prudential controls in the GSH should prevent or discourage any uncovered speculative trading from occurring and that the risk of short-selling occurring was therefore relatively low. APGA and a number of service providers did, however, note that if short-selling did occur service providers should have the ability to refuse to honour those trades.

As to the options that could be used to manage short-selling, a number of participants were of the view that the trade should be immediately cancelled (AGL, Epic, APA and Stanwell). Shell, on the other hand, did not consider this the most effective option to deal with short-selling that occurs due to genuine errors. Shell’s preference was that the trade

87 That is to verify a seller had the requisite amount of capacity before the trade was entered into.

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remain on foot and the seller provided the opportunity to source the required capacity either through the capacity trading platform or other means. Shell went on to add that the time available to rectify the issue should relate to how close the deal is to closing and suggested that for day-ahead products, sellers should only have 30 - 60 minutes, but if the trade is not due to commence for a number of days the seller should have 24 hours to rectify the position. APLNG also suggested that the seller should have a period of time to rectify the short-sale and suggested a three business day window.

Jemena, on the other hand, stated that in the case of day-ahead trades there would be no time for a shipper to rectify the shortfall and added that a service provider cannot delay scheduling to permit a seller to find additional capacity. Jemena went on to note that there needs to be a consistent approach to dealing with trades to ensure there is no confusion and was of the view that trades should be cancelled immediately.

Stanwell and Shell also noted the potential for sellers that are interested in having a “short position” to enter into a separate contract with a pipeline to cover them in such circumstances (e.g. the seller could enter into an agreement with the service provider to provide capacity at a set price when required). Shell suggested that this option be subject to a more detailed review to ensure it does not have any unintended consequences (e.g. it could reduce the volume of primary capacity made available to other shippers).

A number of stakeholders also commented on the way in which a cancellation of a short-sale would be dealt with and, in particular, whether there should be a pro-rata adjustment across all secondary shippers that were to use capacity on the day or some other mechanism. Jemena was of the view that a pro-rata approach would severely undermine confidence in the market. AGL and APA also argued that this would create significant uncertainty for all trading participants, with APA stating that the offending party should be liable to their matched trading participant only. Shell and APLNG, on the other hand, were of the view that affected parties should be curtailed on a pro-rata basis. APLNG also stated that parties should be able to seek compensation from the seller (on a pro-rata basis) for any losses incurred as a result of such curtailment.


The GMRG agrees with stakeholders that the risk of short-selling should be relatively low given the arrangements that are currently in place in the GSH. There is, however, still a need to have comprehensive and credible arrangements in place to deal with short-selling if it occurs, either through an error or a deliberate action.

While the GMRG has given some thought to the registry option, it agrees with stakeholders that the costs and complexity of establishing such a register would outweigh the benefits. The GMRG is not therefore advocating this option. The GMRG is instead recommending that delivery default be managed in line with the approach that is currently used for gas products on the GSH, whereby shippers warrant they have the capacity they are selling. The GMRG also recommends that in the event of a short-sale the following process should followed:

§ Service providers will be notified by AEMO of the net trading positions during gas day D-1 and will be able to identify any short sales by comparing the net sell positions to participant contractual rights.

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§ If the service provider identifies a short sale, then it is not obliged to execute the associated transfer of capacity. It must, however, notify the shipper in question and provide it with one hour to rectify the situation. The service provider must also notify AEMO.

In the GMRG’s view, one hour is a sufficient period of time to try and rectify the issue (which could involve procuring spare primary capacity from the service provider or purchasing it bilaterally from another shipper). While the GMRG can see some merit in Shell’s proposal to have alternative time frames for rectification, it is concerned that this would add further complexity to the process and create a false perception that the trade is valid and the behaviour is appropriate.

§ If the short-selling is not rectified in the permitted time, then the trade will be cancelled and the affected buyers will be compensated using the collateral posted by the seller. AEMO will be responsible for notifying the affected buyer(s) that the trade has been cancelled.

§ In the scenario of multiple transactions of that capacity product on the day, it will not be possible to identify the buyer that has been sold the un-contractual capacity. It is appropriate therefore for the capacity of all affected secondary shippers be curtailed on a pro-rata basis.

§ If a shipper short-sells capacity it will be issued with a financial penalty, irrespective of whether it is able to rectify the short-sale. This penalty is in recognition that given the complementary nature of gas and capacity products, the buyer could suffer multiple liabilities if a capacity trade is cancelled. It will also act to strengthen the incentive on participants to manage the risk of short-selling through an error.

§ Further penalties may also be possible if the AER decides to institute civil proceedings in the Federal Court and seek an injunction, or an order that the participant cease or remedy the conduct, and/or an order that a penalty be paid under the NGR market conduct rules.

These recommendations will result in the following two additional features to the current GSH arrangements:

§ short-sellers will have a one-hour window to rectify the situation, and

§ short-sellers will face an additional financial penalty above their collateral requirements, in recognition that there is likely to be a lower level of liquidity for capacity products.

The GMRG recognises the differing stakeholder views on the appropriate processes to manage this risk. However, it is concerned that if short-selling occurred at a time of market stress or low liquidity, a market participant that has purchased the affected capacity may not be able to rectify the situation and it may have flow on effects in the gas market. It is important therefore for a credible process to be implemented to maintain the integrity of the capacity trading platform and instil confidence in the market.

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9.3 Seller defaults on financial obligations in the GSH


As explained in the consultation paper, there are already arrangements in place in the GSH to deal with a seller’s default on its GSH financial obligations. In short, if this occurs:

§ AEMO may suspend or terminate the participant’s membership and use the Close Out and Offset Procedures (see Box E.6) to cancel any transactions that are on foot; and

§ the counterparty to the trade will be compensated 25% of the face value of the transaction, which will be paid for using the collateral collected from the trading participant.

The consultation paper did, however, identify another potential option that could be used in this case, which was that if the transfer of capacity from the seller to the buyer has already occurred, the transaction could be treated as being fully “delivered” and excluded from any close out and offset calculation. For example, if there is a month long transaction that is notified for the full term on the day after being transacted and the seller subsequently defaults on its financial obligations in the GSH, there may be no need to close this trade out due to a risk of non-delivery.

The GMRG did not form a view on this in the consultation paper but rather sought further feedback from stakeholders.


AGL and Stanwell were the only stakeholders that provided feedback on this issue. AGL was of the view that if the primary GTA remains on foot, then trades conducted prior to the default should be honoured, even if the seller is banned from the GSH post trade. Stanwell also suggested that keeping the trade on foot was a sensible option, but noted that more detail was required from AEMO on whether this was feasible.


Like AGL and Stanwell, the GMRG is of the view that if the transfer of capacity from the seller to the buyer has already occurred and the seller subsequently defaults on its GSH obligations, the trade should be kept on foot and excluded from the close out and offset procedure.

As noted in section 9.1.1, the platform will be fully anonymous, so buyers will be unable to conduct their own risk assessment of the sellers and therefore will rely on the platform design to have appropriate default arrangements. The other important point to note in this context is that capacity is different from commodity, in the sense that the provision of the service effectively rests with the service provider not with the seller. So as long as the seller continues to honour its obligations under the primary GTA there would be no risk of non-delivery of the traded capacity. In these circumstances, the GMRG believes that keeping trades on foot, where it is possible to do so, will promote the NGO because it will provide market participants more certainty and confidence to trade on the platform.

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10. Capacity Listing Service and Bilateral TradingIn addition to the exchange, the capacity trading platform will include a listing service. In contrast to the exchange, the listing service will allow shippers to specify any service they wish to buy or sell as well as the price at which they are willing to do so and to enter into trades through bilateral negotiations.

The remainder of this chapter sets out the GMRG’s final recommendations on the design of the listing service and the obligations sellers will have when entering into bilateral trades.

Background

The GSH currently includes a capacity listing service that enables market participants to list transportation services, storage services, gas and swaps that they have an interest in buying or selling. Feedback was sought from the Capacity Trading Platform project team on whether they thought any changes to the design of the listing service were required. In short, the project team thought the current listing service was working as intended and that no changes were required.

While changes to the design of the listing service may not be required, some changes to the governance arrangements may be required to give effect to the AEMC’s recommendation that sellers entering into bilateral capacity trades be required to offer the buyer the option of using an operational transfer to give effect to the trade. This recommendation was classified by the AEMC as a required outcome because it had concerns that the use of a bare transfer may result in secondary shippers having to submit nominations to potential competitors.88 Rather than banning bare transfers, the AEMC recommended that the seller be required to always offer prospective buyers the option to use an operational transfer.


In the consultation paper, the GMRG agreed with the project team’s view that no changes need to be made to the existing listing service. The GMRG also agreed with the AEMC’s recommendation that sellers in bilateral trades should be required to offer buyers the option of utilising an operational transfer.


Stakeholders were generally supportive of the GMRG’s preliminary view, although some stakeholders questioned whether the requirement to offer an operational transfer should be mandatory. Some of the stakeholder views expressed on this issue are summarised below:

§ APLNG agreed with the preliminary view and noted that requiring shippers to offer an operational transfer through the NGR would provide sellers an incentive to abide by this requirement.

88 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, p. 98.

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§ AGL noted its support for operational transfers and stated that in its view bare transfers should only be used by mutual agreement and not from a unilateral decision by either the buyer or seller.

§ APA thought that given that operational transfers would be in place for exchange-traded capacity it would be appropriate for this option to be offered, but noted that other options such as bare transfer or assignment may also suit some buyers.

§ Shell expressed a similar view, noting that while it did not have any specific concerns with the requirement for operational transfers to be offered, it was keen to ensure the option of bare transfers are maintained if agreed to by the transacting parties.

§ Stanwell suggested the requirement to offer an operational transfer would add to the cost of trading if shippers had to produce two sets of legal documentation and determine two sets of prices for bare and operational transfers. Stanwell also noted that buyers did not have to accept bare transfers because they would have the option to source capacity from the exchange, through the auction or from the service provider.


The GMRG has considered the issues raised by stakeholders and it would appear from some submissions that there may be some confusion about how the operational transfer option would work.

As outlined in Chapter 2, if a secondary shipper wanted to give effect to a trade through an operational transfer rather than a bare transfer then it would need to have the necessary arrangements in place with the service provider. Importantly, this would not require any additional work on the part of the seller. The only contractual difference from the seller’s perspective is that the Capacity Trading Agreement with the secondary shipper will only contain the financial terms of the transaction and not all of the other operational terms that would be required if a bare transfer was entered into. If anything, this should reduce the seller’s transaction costs, because it would not have to negotiate all the other terms.

The other benefit that an operational transfer offers sellers is that they will not have to make nominations on behalf of the secondary shipper, manage the secondary shipper’s allocations or monitor the secondary shipper’s imbalances, overruns and compliance with other aspects of the contract. The use of an operational transfer should therefore lower the seller’s administrative and monitoring costs (see Box 2.1 for further detail). From the secondary shipper’s perspective, they can also enhance commercial confidentiality, because nominations are made directly to the service provider.

As this brief summary highlights, the operational transfer mechanism offers a range of benefits to both buyers and sellers, which is why the AEMC recommended that sellers offer this option to buyers in bilateral trades. The GMRG agrees with the position the AEMC reached on this issue and is therefore recommending that if a seller enters into a bilateral capacity trade, that it offer the buyer the option of using an operational transfer to give effect to the trade. In the GMRG’s view, this recommendation will make it easier for buyers and sellers to conduct bilateral trades and can be expected to facilitate more secondary trading.

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In a similar manner to the AEMC, the GMRG is of the view that this approach is preferable to banning bare transfers and other capacity transfer mechanisms (e.g. assignments), which some stakeholders clearly value. The GMRG understands, however, the concerns that AGL has raised and notes that the requirement for a seller to offer an operational transfer does not extend to having to offer a bare transfer. If a seller does not want to use a bare transfer mechanism, it can therefore just offer the operational transfer option.

To implement this recommendation, amendments will need to be made to the NGL and the NGR to require shippers that sell secondary capacity on a bilateral basis to offer buyers the option of using an operational transfer to give effect to the trade. The GMRG recommends that this obligation be classified as a civil penalty and conduct provision in the regulations made under the NGL and the AER be accorded responsibility for monitoring compliance with this obligation. Compliance monitoring is expected to occur on a reactive basis in response to complaints from secondary shippers that have not been offered the option of an operational transfer.

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11. Governance Arrangements for the Capacity Trading Platform

The governance framework that currently applies to the GSH is set out in the NGL, Part 22 of the NGR, the Exchange Agreement and a range of procedures that AEMO has developed (see Table E.22). While the same governance framework is expected to apply to the capacity trading component of the GSH, some changes to the NGR, the Exchange Agreement and procedures will be required to implement the capacity trading platform and the design options discussed in Chapters 6-10.

Table 11.19 summarises the changes to the governance arrangements that the GMRG expects will be required to implement the capacity trading platform.

Table 11.19: Governance arrangementsInstrument Summary

NGL Section 91BRK of the NGL provides for AEMO to establish, operate and administer ‘gas trading exchanges’, which is defined as a facility through which persons may elect to buy and sell natural gas or related goods or services, including pipeline capacity. Given this section of the NGL already provides for the GSH to extend to pipeline capacity products, the GMRG does not expect any changes will be required to the NGL to implement the capacity trading platform.Changes to the NGL will, however, be required for the standardisation of operational GTAs and the reporting framework. These changes are outlined in Parts A and C of this paper.

NGR GSH rules (Part 22): As currently drafted, the rules in Part 22 appear to be sufficiently broad to accommodate capacity trading. The GMRG does not therefore envisage material changes to the scope of this part of the NGR. Changes may, however, be required to allow for differences between the treatment of gas and capacity products in the Exchange Agreement (including in relation to short-selling or the treatment of default by the primary shipper). STTM rules (Part 20): The STTM rules currently only provide for trading rights to be transferred using a bare transfer. The GMRG therefore anticipates some changes to the rules in Part 20 may be required to enable STTM trading rights to be transferred using an operational transfer. DWGM rules (Part 19): The GMRG does not anticipate any changes will be required to the DWGM rules.New rules: New rules will also be required to: § impose an obligation on shippers that sell secondary capacity on a bilateral basis to

offer prospective buyers the option of using an operational transfer to give effect to the trade; and

§ impose an obligation on service providers to keep secondary trades on foot for a period of two weeks if the primary shipper defaults under a primary GTA.

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Instrument Summary

Exchange Agreement

Exchange Agreement: A number of amendments to the body of the Exchange Agreement and the product specification schedules will be required before capacity products can be added to the exchange. The Exchange Agreement will, for example, need to specify the standardised products that will be available for sale on the exchange and changes will also need to be made to the delivery, credit risk management and default arrangements. The Exchange Agreement will also need to be amended to set out how short-selling and default by a primary capacity holder will be dealt with (if necessary, AEMO could also provide further detail on how this will occur in the Secondary Capacity and Auction Procedures as suggested by AGL).GSH subsidiary documents: Some changes to the existing GSH settlement and prudential methodology, reallocation and fees procedures are likely to be required. Changes to the Exchange Agreement and subsidiary documents are expected to be made by AEMO using the process set out in rule 540 of the NGR.

AEMO Procedures

Secondary Capacity and Auction Procedures: New procedures will be required to implement capacity products and the transfer of capacity.STTM procedures: Changes to STTM Procedures around the transfer of trading rights are also likely to be required.DWGM procedures: Some changes to the Wholesale Market Accreditation Procedures and Wholesale Market AMDQ Procedures may be required.

While not shown in this table, the AER is expected to have the same functions and powers in relation to the capacity trading platform that it currently has for the GSH. It will therefore be responsible for monitoring compliance and investigating and enforcing breaches under its general powers. It will also have a specific duty under Part 22 of the NGR to monitor compliance with the market conduct rules. In this capacity, the AER will be able to analyse the prevalence of short-selling to determine if there are systematic issues that need to be addressed, as suggested by Shell. The AEMC could also examine this issue when it carries out its biennial reviews on the liquidity of wholesale gas and pipeline capacity trading markets.

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Part C: Reporting Framework for Secondary TradesIn the East Coast Review, the AEMC noted that shippers currently have no way to determine whether secondary capacity is being provided on a non-discriminatory basis, or if the prices they are offered are reasonable because the prices and other terms on which secondary capacity trades are struck are currently confidential.89 To address this information gap, the AEMC recommended that information on the prices struck in all secondary trades be published, along with information on the key terms and conditions that may have affected the prices in those trades at the time the trade is entered into, or shortly thereafter.90 The AEMC also recommended that trades conducted outside the trading platform should be advertised ahead of time through the listing service

Table C.1 provides a summary of the AEMC’s recommendations, which were all classified as required outcomes.

Table C.1: AEMC’s Recommendations: Reporting framework for secondary tradesRequired Outcomes

§ Publication of information on all secondary trades of pipeline capacity and hub services. § The information to be published is the price of the trade and any other information that might

reasonably influence that price, taking into account measures to protect anonymity. § Publication should occur at or shortly after the time the transaction is entered into.

Preferred outcomes§ Trades conducted outside the capacity trading platform to be advertised ahead of time on

the capacity trading platform listing service.

Elaborating further on these recommendations, the AEMC noted that there is a clear trade-off between the benefits of wide information provision and the direct and indirect cost of providing the information (which includes any adverse effects that the revelation of counterparties’ commercial-in-confidence information may have on market participants). The AEMC therefore recommended that the GMRG have regard to these trade-offs when developing its final recommendations on the reporting framework for secondary capacity.

The GMRG has worked with the Standardisation project team on this element of the reform package and on 10 October 2017 published a consultation paper that set out a number of options for the form the reporting framework could take, as well as the GMRG’s preliminary view on these options. Stakeholders were given four weeks to provide written feedback on the options presented in this consultation paper and were also invited to attend a public forum in Melbourne on 31 October 2017. The consultation period for this paper ended on 6 November 2017.

The stakeholders that provided written submissions on this element of the reform package included the ACCC, AEMO, AGL, Alinta, APLNG, Engie, ERM, Jemena, Origin, Senex, Shell and Stanwell. Stakeholder submissions can be accessed on the GMRG website.91 These stakeholders were generally supportive of this element of the capacity trading reform package, although some concerns were raised about:

89 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, p.105.90 ibid, p.106.91 http://gmrg.coagenergycouncil.gov.au/publications/day-ahead-auction-contracted-un-nominated-

capacity-and-reporting-framework

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http://gmrg.coagenergycouncil.gov.au/publications/day-ahead-auction-contracted-un-nominated-capacity-and-reporting-framework

http://gmrg.coagenergycouncil.gov.au/publications/day-ahead-auction-contracted-un-nominated-capacity-and-reporting-framework

§ the AEMC’s recommendation that bilateral trades be subject to the reporting framework and advertised ahead of time on the listing service;

§ the level of information to be reported and how confidentiality will be protected; and§ the amount of time sellers will have to report on any trades they have entered into.

The GMRG has therefore further considered these issues in developing its final recommendations.

Table C.2 provides a high-level summary of the GMRG’s final recommendations on this element of the reform package, which have been developed having regard to the feedback provided by stakeholders and the assessment framework set out in Chapter 3. In the GMRG’s view, the reporting framework set out in this table is fit for purpose, targeted and proportionate to the issues it is intended to address and strikes the right balance between:

providing the market with sufficient information to understand the value of capacity and to make informed decisions about the allocation and use of capacity; and

the direct and indirect costs associated with information provision.

Consistent with the objectives outlined by the AEMC, the reporting framework can also be expected to:

§ aid the price discovery process for secondary capacity trades (i.e. by providing for the publication of information on all forms of secondary capacity trades shortly after they are entered into), which will, in turn: o reduce search costs; o enable shippers to engage in more effective negotiations (i.e. by improving the

relative bargaining positions of parties); and o improve the efficiency with which capacity is allocated and used (i.e. because

shippers will be able to readily assess the value of capacity); and

§ instil a greater level of confidence in the robustness and non-discriminatory nature of this market, thereby promoting the development of a liquid secondary capacity market.

These attributes are consistent with the broader objectives of the capacity trading reform package and the Energy Council’s Vision of the direction gas market development should take and, in particular, outcome 2(a) (see ). The GMRG is therefore satisfied that the reporting framework will contribute to the achievement of the NGO.

This view was supported by the ACCC, who noted in its submission that it “supports the scope of the proposed reporting framework for secondary trades because it will improve transparency and the relative bargaining position of parties”.92

The remainder of this Part focuses on the reporting requirements that will apply to secondary capacity trades and the governance arrangements required to give effect to the reporting framework. In keeping with the AEMC’s recommendations, this Part focuses on the reporting of secondary capacity trades conducted through the exchange and bilateral trades. The reporting framework that will apply to the day-ahead auction will be set out in the GMRG’s final recommendations to be provided to the Energy Council out-of-session in December.

92 ACCC, Submission on Day-Ahead Auction of Contracted but Un-Nominated Capacity & Reporting Framework, 6 November 2017.

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Table C.2: Summary of the GMRG’s final recommendations on the reporting framework for secondary capacity tradesDesign Element RecommendationTrades subject to reporting

The GMRG recommends that the reporting framework apply to: § all screen and pre-matched trades carried out through the capacity trading platform; and § bilateral trades of capacity involving forward haul, backhaul, park, park and loan and/or compression services.Capacity purchased through the auction will also need to be reported but the reporting framework will be slightly different. The GMRG’s recommendations on the day-ahead auction reporting framework will be made to the Energy Council out-of-session in December.

Information to be reported

The GMRG recommends that the reporting framework require the following information to be reported:§ the date of the trade and the start and end dates for the trade;§ the type of trade (e.g. exchange traded or bilateral) and how it is given effect (e.g. operational GTA, primary GTA or bare transfer);§ the type of service procured (i.e. forward haul, backhaul, park, park and loan, compression), the firmness of the service and service priority; § the pipeline or compression facility the trade relates to and, in the case of pipeline services, the direction of the service and zones between which gas is

transported (zones will be used to, the extent practicable, protect the anonymity of counterparties);§ the amount of capacity procured (expressed on a maximum daily quantity (MDQ) and maximum hourly quantity (MHQ) basis); and§ the price paid for the capacity (including, where relevant, details of the price structure and price escalation mechanism for bilateral trades).

Responsibility for reporting

The GMRG recommends that: § AEMO be accorded responsibility for reporting trades carried out through the capacity trading platform; and § sellers be accorded responsibility for reporting bilateral trades.

Where and when information is to be reported and published

The GMRG recommends that trades carried out: § through the capacity trading platform be reported on the GSH by AEMO as soon as practicable after the trade occurs (consistent with what currently applies

for commodity) and published on the BB website by the end of the gas day; and§ bilaterally be reported to AEMO by the earlier of one day after the trade is executed, and the day prior to the trade commencing D-1 and published on the BB

website by AEMO by the end of the gas day.

Requirement to advertise bilateral trades

The GMRG has some concerns about the workability of the proposal to require bilateral trades be advertised on the listing service ahead of time. As an alternative, the GMRG is recommending that these trades be subject to the reporting framework, with the prices and other key terms struck in these trades published on an ex post basis. The publication of this information is intended to discourage parties from engaging in any form of discriminatory behaviour, but if the reported information reveals this type of behaviour is occurring, the AEMC could recommend further changes as part of its biennial review of liquidity in the wholesale gas and pipeline capacity trading markets.


A number of changes will need to be made to the NGL and NGR to give effect to this reporting framework.Changes to the NGL will be required to impose an obligation on sellers to provide AEMO with information about bilateral trades and permit AEMO to publish information on these trades and trades carried out through the capacity trading platform, in accordance with the NGR and applicable procedures. Changes will also need to be made to the NGR to set out the specific obligations that: § sellers have to report information to AEMO, including the types of trades to be reported, the information that must be reported and the timing for reporting; and§ AEMO has to report the trade information on the GSH and BB website. Secondary trading reporting procedures will also need to be developed by AEMO.The AER will be responsible for monitoring and enforcing compliance with these obligations using its existing powers in the NGL.

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Design Element Recommendation

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12. Reporting Requirements for Secondary TradesTo increase the transparency surrounding secondary capacity trades and enhance the market’s confidence in the secondary market, the AEMC recommended that information on the prices and other key terms struck in all secondary trades of pipeline and compression capacity be published at the time the trade is entered into, or shortly thereafter.

The GMRG has worked with the Standardisation project team, its legal advisor, JWS, and other stakeholders on these recommendations. In doing so, the GMRG has considered:

§ the types of trades to be reported;

§ the information to be reported;

§ who should have the obligation to report trades and when this information should be reported;

§ where the information is to be published; and

§ whether trades conducted outside the exchange should be advertised prior to the transaction.

These issues are discussed, in turn, below.

12.1 Types of trades to be reported

Background

In the East Coast Review, the AEMC recommended that information on all secondary trades of capacity be published, irrespective of how the trade is executed (i.e. bilaterally or through the capacity trading platform) and whether it involves a standardised or bespoke product. While some stakeholders questioned the value of reporting bilateral and bespoke trades, the AEMC was of the view that excluding these trades from the reporting framework could distort trading decisions and undermine the development of the capacity trading platform (i.e. because it would encourage parties to enter into trades outside the trading platform). This recommendation was therefore classified as a required outcome.93

This recommendation was discussed in some detail by the Standardisation project team, which noted that there are a number of ways that a primary capacity holder’s capacity can be used (directly or indirectly) by other market participants that do not necessarily involve a secondary capacity trade, including:

(a) delivered gas supply agreements (including retail contracts);

(b) gas purchases from an STTM;

(c) locational swaps; and

(d) novations of primary capacity.

While the project team agreed that reporting these types of trade went beyond the scope of what the AEMC intended, they noted that if market bodies or policy makers wanted to

93 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 108-109.

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determine the extent to which secondary capacity is being released, focusing purely on secondary capacity trades would underestimate the true level of trade.

Having agreed that the reporting framework should only apply to secondary trades of capacity, the project team noted that from a compliance perspective it would be important to clearly define the types of trades to be subject to the reporting framework. The trades that the project team thought should be reported included all exchange-based capacity traded products (screen and pre-matched products) available for sale on the capacity trading platform and the following bilaterally traded products (conducted using either a bare transfer or an operational transfer (see section 2.2):

§ forward haul services;

§ backhaul services;

§ park services;

§ loan services; and

§ compression services.


In the consultation paper, the GMRG agreed with the project team that the reporting framework should apply to secondary capacity trades but not to the following types of trades:

(a) delivered gas supply agreements (including retail contracts);

(b) gas purchases from an STTM;

(c) locational swaps; and

(d) novations of primary capacity.

The GMRG also agreed with the project team that there would be merit in defining the types of trades that are to be reported to avoid any unnecessary confusion about the nature of the reporting obligation. The types of trades that the GMRG indicated should be reported, included:

§ all exchange-based trades (screen and pre-matched) carried out through the capacity trading platform; and

§ bilateral trades of capacity involving forward haul, backhaul, park, loan and/or compression services.


The majority of stakeholders that commented on this issue, agreed that the trades that should be subject to the reporting framework should include exchange-based trades and bilateral trades of forward haul, backhaul, park, loan and compression services and exclude the types of trades listed in (a)-(d) above. There were, however, some exceptions to this general view, with:

§ Origin, Engie and AGL expressing some concerns about the proposal to report bilateral trades. Origin, for example, was of the view that if these trades were to be

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published then additional measures may be required to ensure commercial-in-confidence information is protected. Engie and AGL, on the other hand, thought that these trades should not be subject to the reporting framework. Elaborating on this further, Engie claimed the publication of information on these trades would be “useless” and could expose transacting parties to other unintended commercial risks. Engie also noted the consultation paper did not identify sufficient benefits to overcome the cost or potential detriment to the parties involved in such trades to warrant these measures.

§ Stanwell expressed some concern about the proposal to report trades involving backhaul, park or loan services and claimed it went beyond what the AEMC intended when requiring all secondary capacity trades be reported. Stanwell added that these products are minor compared to forward haul and compression products and that requiring them to be reported would add costs and regulatory burden for little gain.


Having regard to the AEMC’s recommendations, the assessment framework set out in Chapter 3 and the feedback provided by stakeholders, the GMRG recommends that the following types of trades be subject to the reporting framework:

1. all exchange-based trades (screen and pre-matched) of transportation services carried out through the capacity trading platform; and

2. any bilateral trades of capacity conducted using either a bare transfer or an operational transfer and involving forward haul (in both directions on bi-directional pipelines), backhaul, park, loan and/or compression services.

In the GMRG’s view, applying the reporting framework to the trades listed in (1)-(2) will promote the NGO because it will aid the price discovery process and instil a greater level of confidence in the robustness of the market. Greater transparency in this area will also enable liquidity in this market to be assessed and policy makers to understand whether further reform may be required. Although as some stakeholders noted, some care will need to be taken in assessing the reported information, because capacity can be released by shippers to other parties through other means (e.g. swaps and delivered gas supply agreements) and the reporting framework will not therefore represent a complete picture.

In relation to the concerns that Engie, AGL and Origin raised about the publication of bilateral trades, it is worth noting that this is a required outcome of the AEMC’s recommendations. As noted previously, the AEMC included this recommendation because it was concerned that exempting bilateral trades could distort trading decisions and undermine the development of the capacity trading platform. The position the AEMC reached on this issue was supported by both the ACCC and AEMO. The GMRG also agrees with this position and believes that the publication of this information will complement the platform data and provide a more comprehensive picture of the market value of capacity, which will aid the price discovery process and provide for more efficient capacity allocation and utilisation decisions. The GMRG understands that some of the reluctance to report this information stems from the concern stakeholders have about the identity of trading parties being revealed. This issue is discussed further in section 12.2.

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As to Stanwell’s suggestion that the reporting framework not extend to ancillary services (e.g. park or loan services), the GMRG believes there is value, from a price discovery perspective, in reporting these types of trades, particularly given some of these products will be available on the capacity trading platform.

There are a number of other ways that a primary capacity holder’s capacity can be released that do not involve a secondary capacity trade, such as delivered gas supply agreements and locational swaps. In the GMRG’s view requiring these types of trades to be reported would go beyond the scope of what the AEMC intended. The GMRG is not therefore recommending that these types of trades be subject to the reporting framework. It is worth noting, however, that, in keeping with the Prime Minister’s direction on 20 March 2017,94 the GMRG intends to work with the ACCC in early 2018 to consider whether there is value in publishing other types of information to reduce the opaqueness in the gas market. It is possible therefore that these types of trades could be subject to reporting requirements in the future.

12.2 Information to be reported

Background

The AEMC recommended that the reporting framework for secondary capacity trades require information on the prices struck in secondary trades to be reported along with the following contract terms:95 (a) when the contract was entered into and the duration of the contract; (b) the pipeline or compressor facility that will be used to provide the service; (c) the type of service and the firmness and priority of that service; (d) the MDQ and MHQ the shipper can nominate; (e) the direction of the service and the receipt and delivery points between which gas will

be transported, aggregated to a level sufficient to protect the anonymity of parties; (f) any additional flexibility the shipper may have, or restrictions it may be subject to; and

(g) where relevant, any variations from standardised operational, prudential and other contractual terms that could affect the price.

The AEMC also recommended that the GMRG consider whether any further measures are required to protect the anonymity of counterparties and, in doing so, to consider the relative benefits of information provision and anonymity.96

When this issue was discussed with the Standardisation project team, questions were raised about the value of reporting the final two categories of information ((f) and (g)). The team were of the view that reporting this information would give rise to additional costs for little value and noted that it would be difficult to comply with this requirement in a consistent manner. The project team did, however, note that information on the type of trade and how it has been given effect could provide market participants with some

94 Prime Minister of Australia Hon. Malcom Turnbull, Measures Agreed for Cheaper, More Reliable Gas, 20 March 2017.

95 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, pp. 107-108.96 ibid, p.108.

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indication of whether or not there may be other bespoke contract terms that may have affected the price struck in that trade. For example, if a bilateral trade is identified as involving a bare transfer and the price is higher than equivalent exchange trades, this could indicate that the buyer has greater flexibility and/or the operational, prudential and other terms associated with the trade are more favourable than those in the standardised operational GTA.

As to whether any additional measures are required to protect anonymity, the project team noted that while reporting trades on a zonal basis rather than a point-to-point basis would provide some protection, it would be difficult to completely protect the anonymity of parties (particularly if there are only two shippers using a pipeline or zone). The project team did, however, acknowledge that the AEMC did not recommend that anonymity should be protected at all costs. Rather, the AEMC recognised that there is a trade-off between the benefits of information provision and the potential concerns surrounding the revelation of commercial-in-confidence information that must be balanced. It was against this backdrop that the project team concluded no additional confidentiality measures were required.


In the consultation paper, the GMRG agreed with the views expressed by the project team, including that:

§ the information to be reported should be limited to the items listed in (a)-(e) above; and

§ apart from reporting trades on a zonal basis, no further measures were required to protect the anonymity of trading parties.


The majority of stakeholders supported requiring the information listed in (a)-(e) to be reported, with some stakeholders noting it would be difficult to report the information in (f) and (g) on a consistent and meaningful basis and that the value of its disclosure was unclear. AEMO and APLNG, on the other hand, thought this information should be reported. As an alternative, AEMO suggested that a standard list of terms be developed and that where a trade deviates from these terms by a material amount it is flagged in the trade reporting. AEMO noted that this would at least enable users of the data to understand whether a bilateral trade is standard or non-standard without necessarily revealing the minutiae of every term.

ERM raised some concerns in its submission about the potential for the identities of shippers to be deduced from volume and zonal information, given the small number of players in the market. AGL indicated that the use of zones would provide shippers with some anonymity, but noted that the reporting framework should not “inadvertently give away the future position of gas powered generators”. Alinta also thought the use of zones would provide shippers with some anonymity, but noted the potential for the identity of parties to be revealed on single shipper pipelines. It therefore suggested that single shipper pipelines be aggregated with other pipelines and reported on a zonal basis. Origin indicated that additional measures may be required to protect the anonymity of parties in bilateral trades and noted the potential for some information to undermine a shipper’s position in a related market, such as electricity.

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Table 12.20 sets out the GMRG’s final recommendations on the information to be reported for exchanged related products and bilateral trades, which in the GMRG’s view strikes the right balance between:

providing the market with sufficient information to understand the value of capacity and to make informed decisions about the allocation and use of capacity; and

the direct and indirect costs associated with information provision.

Table 12.20: Final recommendations on information to be reportedInformation Exchange traded products Bilateral tradesDate of trade and duration of contract

Pipeline or compression facility

Service type (i.e. forward haul, backhaul, park and loan, compression), firmness, service priority

Direction of service and zones between which gas is transported

Pipeline zones to be used for reporting

Pipeline zones to be used

for reporting

Price (ex GST)

Including details of price

structure and price escalation mechanism**

MDQ and MHQ

Type of trade and how it is given effect

Distinguish between screen and pre-matched trades and potentially between trades where the buyer uses an operational or primary GTA97

Distinguish between trades where the buyer will utilise an operational GTA or a bare transfer*

Any additional flexibility provided to the shipper, or restrictions it is subject to

Variations from standardised operational, prudential and other terms that affect price

* It was noted that information on whether the buyer is utilising an operational or a primary GTA may be difficult to collect unless it is a standing entry for trading participants on the capacity trading platform, which is an option that is being considered in the design of the capacity trading platform. ** Note that the provision of this type of information could be more complex than the other information types and may need to be split into multiple reporting lines.

As this table highlights, the GMRG agrees with the advice of the project team and the majority of stakeholders that it would be difficult to report information on the final two categories on a consistent and meaningful basis. Further, if shippers were required to report more granular information on the flexibility or restrictions in trades and variations between standard and bespoke terms, this would substantially add to the costs of the reporting arrangements for what appears to be limited benefit.

In relation to AEMO’s suggestion, the GMRG notes that the operational GTA will set out the standard terms and conditions for secondary trades. As discussed in Part A, parties will have the option of using their primary GTA as an alternative and it is GMRG’s intention that the published information will also report on which GTA was being used. This will help to inform whether there are non-standard terms related to a trade that could affect the price, without requiring the specific differences to be reported. In the GMRG’s view this level of information is sufficient at this stage, although it is noted that if, over

97 Note that in allowing trades to be given effect under the terms of a primary GTA it has been assumed that these terms will not drive the value disproportionately.

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time, it becomes clear that the market would benefit from having more granular terms being reported, then a rule change could be submitted to the AEMC.

As to the concerns that have been raised about the potential for the identity of trading parties to be deduced from the reported information, it is worth reiterating that the AEMC did not say that anonymity should be protected at all costs. Rather, protection of anonymity must be weighed up against the benefits of greater transparency. On the basis of the stakeholder feedback, it is not clear how the publication of information on trade details will affect their commercial position if, notwithstanding the fact that the names of the trading parties will not be published and trades will be reported at a zonal basis, this information is deduced. While information on the amount of capacity purchased will be published, the reporting framework will not require information on the actual use of the capacity to be published. Nor will it require the publication of information on the primary capacity held by the shipper. It would be difficult therefore for market participants to infer anything from the release of the proposed information, other than the fact that some additional capacity has been acquired.98 The GMRG is not therefore convinced that any additional measures are required to protect the anonymity of parties.

12.3 Reporting obligations

Background

Exchange-based capacity trades carried out through the capacity trading platform will be subject to a reporting framework under the Exchange Agreement. Similar to the arrangements that currently apply to commodity products traded through the GSH, reporting will be the responsibility of AEMO. AEMO will collect the information at the time the trade occurs and publish it on the GSH shortly thereafter.99

The requirement for bilateral trades to be reported, on the other hand, will require new obligations to be imposed on one or more of the trading parties. This issue was not discussed in any detail in the AEMC’s East Coast Review. It was, however, considered by the Standardisation project team, which identified the following potential candidates for the reporting obligation:

§ the seller;

§ the buyer; and

§ the seller and buyer.

While there was some discussion about the latter of these options, it became clear that requiring both the buyer and seller to report the trade would require additional work by trading parties and AEMO and could give rise to a range of other issues. Of the remaining two options, the project team thought sellers were the more natural candidate for the reporting obligation. 98 Note that the situation here is quite different from what was adopted in the recent BB rule change

where the AEMC agreed that the nominations of gas fired generators should not be published ahead of the gas day because it may affect their competitive position in the NEM. In that case it is quite clear that nominations will be a sign of the amount a generator intends to generate the next day. The same cannot be said though for secondary capacity purchases.

99 The type of information that is published may differ from what is currently published for commodity trades.

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The project team also considered how much time the selling party should have to report the bilateral trade once it is executed. In short, project team members were of the view that the seller should be required to report the trade by the earlier of:

§ three business days after the trade is executed; and

§ the day prior to the use of the capacity commencing (D-1).


In the consultation paper, the GMRG recommended that:

§ AEMO be responsible for reporting trades carried out through the capacity trading exchange; and

§ sellers be responsible for reporting information on bilateral trades and required to report this information by the earlier of:

o one business day after the trade is executed; and

o the day prior to the use of the capacity commencing (D-1).100


Generally, stakeholders supported one party to the transaction being required to report bilateral trades and that the obligation should fall on the seller, with the only exception to this being AGL who thought the obligation should fall on both parties. A number of stakeholders also suggested that provision should be made to enable the buyer or another party to report the trade if agreed to by both parties.

In terms of the reporting timeframes, most stakeholders agreed with the proposed timeframes and recognised that delaying reporting would reduce the relevance of the information to the market. The three exceptions to this were Stanwell, Shell and ERM. Stanwell, for example, indicated that a one day period would be too short and likely increase the risk of inadvertent breaches of the obligation. It therefore suggested a three-business day window. Stanwell was also of the view that a delay might be necessary to protect the anonymity of counterparties and afford the shipper time to make complementary arrangements in other markets before their identity is revealed through the reporting mechanism. Shell expressed a similar view and suggested a longer period be allowed when the trade does not have an immediate start.

ERM also raised some concerns about the timing and suggested that information should not be disclosed if trades are still live or cover a forward period, because it believes this information is commercially sensitive and could be particularly damaging to gas fired generators in the NEM. ERM therefore suggested that trades only be reported if the delivery period under a trade has concluded. ERM also noted that it did not support the proposal to require reporting of trade information on a trade by trade basis because it believed it would be administratively cumbersome. It instead suggested that reporting should occur on a monthly basis.

100 The inclusion of the second limb of this reporting window means that if a trade is entered into and will commence the next day, it will need to be reported on the day the trade is executed.

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Having considered the views expressed by stakeholders on this issue and the overarching objectives of the reporting framework, the GMRG’s final recommendation is that:

§ AEMO be accorded responsibility for reporting trades carried out through the trading platform; and

§ sellers be accorded responsibility for reporting bilateral trades and required to report this information by the earlier of:

o one business day after the trade is executed; and

o the day prior to the use of the capacity commencing (D-1).101

In relation to the latter of these recommendations, the GMRG agrees with stakeholders that there may be value in providing parties the option to appoint the buyer as the reporting entity in some cases, although as APLNG noted from a compliance perspective the obligation will need to remain with the seller. This option will be considered further during the development of the changes to the NGR.

As to the reporting timeframes for bilateral trades, the GMRG understands that it may be difficult to report these trades as soon as they are executed. However, it has a number of concerns with the proposals made by Stanwell (three business days) and ERM (monthly reporting), the most significant of which is that the information could be published too late to be of any benefit to the price discovery perspective, undermining the main objective of this reform.102 There is also a risk with longer reporting windows that parties will fail to report the information. It is for this reason that the GMRG has recommended the timings outlined above, which is consistent with the AEMC’s recommendation that trades be reported at the time they are executed, or shortly thereafter. It is also consistent with the reporting time frames in Part 18 (Natural Gas Services BB) of the NGR for information that is of a similar level of importance to the market.

12.4 Where the information should be published

Background

The AEMC’s recommendations regarding the reporting framework did not specify where the information on secondary trades should be published. Apart from indicating that it would be preferable to obtain all the secondary trade information from one location, the Standardisation project team did not provide a view on this issue.


In the consultation paper, the GMRG suggested that information on exchange-based capacity trades be published on the GSH and that AEMO should be required to publish information about exchange-based capacity trades and bilateral trades on the BB website.

101 The inclusion of the second limb of this reporting window means that if a trade is entered into and will commence the

next day, it will need to be reported on the day the trade is executed. 102 Even if a trade was entered into that was not due to commence for another month, the price struck

in that trade will be informative to others considering entering into trades at a similar time.

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The GMRG also noted that there would be value in the AER publishing a key data series for secondary capacity markets.


Stakeholders did not raise any specific concerns with the GMRG’s preliminary view. AEMO did, however, note that there was unlikely to be a need for a near real-time reporting system (or a ticker) outside of the GSH in the early stages and therefore suggested that exchange-based trades be published on the BB at the end of the gas day. AEMO added that this could be reconsidered once the platform has launched and there is a better indication of market activity and participant interest.


In keeping with the position that was reached in the consultation paper, the GMRG recommends that:

§ Information on exchange-based capacity trades should be published on the GSH (as it currently is for commodity trades) so that trading participants can readily access this information when they are trading.

§ AEMO be required to publish information about exchange-based capacity trades and bilateral trades on the BB website at the end of the gas day, so that a person wishing to access the information does not need to become a GSH participant.103 AEMO could also be given the discretion in the Exchange Agreement to publish information about bilateral trades on the GSH, so that users of the trading platform can readily access this information.

§ The AER publish key data series for secondary capacity markets, the form and frequency of which will be a matter for the AER to determine.

In relation to the issue AEMO raised, the GMRG agrees that there is unlikely to be demand for a real-time reporting system on the BB in the initial stages of the capacity trading platform’s life, particularly given this information will be available on the GSH. The final recommendation therefore assumes that this information will be published on the BB at the end of the gas day.

12.5 Advertising trades in advance

Background

In the East Coast Review, the AEMC recommended that trades conducted outside the exchange be advertised ahead of time on the capacity trading platform listing service (preferred outcome). This recommendation was made in response to concerns that allowing trades to occur outside the exchange would not guarantee non-discriminatory access to capacity. Specifically, the AEMC was concerned that counterparties could discriminate against one another, by choosing not to enter into a bilateral trade, or pricing the trade differently than would otherwise be the case.104

103 This is akin to what AEMO currently does for GSH trades, which are published on the BB website. 104 AEMC, Stage 2 Final Report: East Coast Review, 23 May 2016, p. 104.

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This recommendation was discussed with the project team. In short, the project team were of the view that the recommendation would be difficult to implement and monitor because trading parties are unlikely to have an incentive to inform the AER. The project team also noted that discriminatory access was not as significant an issue as it was in the United States where this approach has been employed and added that this type of obligation could adversely affect trade. The views expressed by the project team in this context are similar to the feedback that the AEMC received from stakeholders in the East Coast Review.105


In the consultation paper, the GMRG noted that while it appreciated the concerns that project team members and stakeholders in the East Coast Review had raised about this recommendation it was yet to form a final view on this issue. The GMRG therefore sought further feedback from stakeholders on the workability of this proposal and whether the AEMC’s concerns about discriminatory access should be addressed by the reporting framework.


The majority of stakeholders that responded to this issue agreed with the project team that requiring bilateral trades to be advertised ahead of time on the listing service was unnecessary, would be difficult to implement, and could discourage trading. A number of stakeholders also noted that shippers should have a strong incentive to use the capacity trading platform to maximise the likelihood of finding the participant who places the highest value on their capacity (unless the deal includes some unusual features).

The one exception to this general view was APLNG who indicated that if these trades were not advertised it may result in information not being made available to the market and could result in discriminatory access. APLNG did, however, note that this issue could be revisited in the future.


The GMRG has considered the feedback provided by stakeholders on this issue and agrees that requiring shippers to advertise bilateral trades on the listing service could:

§ be difficult to implement and enforce because trading parties are unlikely to have an incentive to inform the AER;

§ impede the ability of participants to conduct trades in a timely manner; and

§ discourage trades where capacity is a small component of the overall trade.

Given the risks associated with this requirement, the GMRG is of the view that rather than requiring bilateral trades to be listed ahead of time, these trades should be subject to the reporting framework, with the prices and other key terms struck in these trades published on an ex post basis by the earlier of:

§ one business day after the trade is executed; and

105 ibid, pp. 104-105.

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§ the day prior to the trade commencing (D-1).

In the GMRG’s view, the publication of this information on an ex post basis should discourage parties from engaging in any form of discriminatory behaviour. However, if this does not occur and the reported information reveals that some form of discrimination is occurring then the AEMC could recommend further changes as part of its biennial review of liquidity in the wholesale gas and pipeline capacity trading markets.

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13. Governance Arrangements for the Reporting Framework for Secondary Trades

To give effect to the reporting framework for secondary capacity trades outlined in the preceding chapter, a number of changes will need to be made to the NGL, NGR and Exchange Agreement. Table 13.21 provides a summary of the changes that will be required to give effect to the reporting framework.

Table 13.21: Governance arrangements for reporting frameworkInstrument Summary

NGL To the extent not already covered by the NGL, the NGL will require shippers to give secondary trade information to AEMO and will permit AEMO to publish it, in each case in accordance with the NGR and applicable procedures.

The NGL will provide that a shipper does not incur any civil monetary liability for complying with its reporting obligations.106

The AER will be responsible for monitoring and enforcing compliance using its existing powers in the NGL.

NGR The NGR will provide a framework for shippers to gain access to the reporting system, for example through a registration process.

The NGR will set out the obligation of shippers to report information about bilateral secondary capacity trades to AEMO, including the categories of information that must be reported and timing. This will be a civil penalty provision.

The NGR will require AEMO to report information about secondary trades covering exchange-based trading and reported bilateral trades on the BB website and will also be permitted to publish it on the GSH.

Exchange Agreement

The Exchange Agreement will specify the information to be reported by AEMO about secondary trades both on the platform and the BB website, which should be consistent with the categories set out in the NGR.

Procedures The GMRG proposes that AEMO be given the power to publish procedures relevant to secondary trade reporting, including details about the form in which information is to be reported to AEMO.

106 A civil monetary liability means a liability for damages, compensation or any other monetary amount that can be recovered by a party that incurs loss or damage by way of civil proceedings. This is different from a civil penalty provision, which allows the AER to issue infringement notices and seek an order that a penalty be paid if the civil penalty provision has been breached.

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Appendix A Summary of AEMC Recommendations The table below contains a summary of the recommendations contained in the AEMC’s Stage 2 Final Report which have been categorised by the AEMC as follows:§ required outcomes – these recommendations were described by the AEMC as outcomes that must be progressed by the GMRG and

are necessary to the implementation of the reforms;§ preferred outcomes – these recommendations were described by the AEMC as outcomes that should be pursued by the GMRG unless

it is clear there are greater benefits in alternative approaches; and§ suggested outcomes – these recommendations were described by the AEMC as outcomes that have in-principle benefits but need to

be considered further by the GMRG.

AEMC RecommendationsRecommendation Required outcomes Preferred outcomes Suggested outcomes Standardisation of key primary and secondary capacity contractual terms

§ Standardisation of key primary and secondary capacity contractual terms for pipeline and for hub (compression) services.

§ Where possible and appropriate apply across the eastern Australian gas market.

§ Standards to be developed are for key operational, prudential and other contractual provisions in GTAs, CTAs and operational GTAs, and provisions in contracts used for exchange-based trading on the capacity trading platform.

§ Counterparties to existing contracts should not be materially disadvantaged through the standardisation process

§ Shippers provided greater flexibility to change their receipt and delivery points

n.a.

Auction for contracted but un-nominated capacity

§ A daily, day-ahead capacity auction for contracted but un-nominated pipeline capacity and hub (compression) services.

§ Auction happens shortly after nomination cut-off time.

§ Reserve price of zero dollars, with compressor fuel provided by shippers in-kind.

§ At least all contracted but un-nominated capacity

§ Combinatorial auction where multiple buyers and sellers can simultaneously coordinate trades, managing the complementarities between different pipeline segments.

§ Single round auction to reduce complexity and opportunities for anti-competitive behaviour between participants.

§ Bidders pay the value of their winning bids ("first-

§ As available rights in current GTAs to be phased out to avoid them competing with rights allocated in the auction.

§ Exempting on a case-by-case basis pipelines that are not fully contracted from needing to conduct

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Recommendation Required outcomes Preferred outcomes Suggested outcomes placed for sale through auction.

§ Accommodate nominations or renominations by incumbent shippers after the auction is conducted.

price" rule) to reduce complexity. § Algorithm determines the winning combination of bids

by maximising profit (constrained by requirement that at least all contracted but un-nominated capacity is put on sale in auction).

§ Capacity purchased in the auction curtailed before (i.e., earlier than) firm capacity.

§ Single auction across the east coast market, in order to optimise allocation across as many products as possible.

§ Exemption from the auction for pipelines serving a single user.

the auction. § The auction to be run by

the same institution(s) which run the capacity trading platform.

Capacity trading platform(s)

§ Creation of capacity trading platform(s) which include electronic anonymous exchange-based trading for commonly traded products in addition to a capacity listing service typical on current capacity trading platforms.

§ Trades carried out through trading platform to be given effect through an operational transfer.

§ Bare transfers will be allowed but the seller will be required to offer the buyer the option to use an operational transfer.

§ Single capacity trading platform operating across the east coast.

§ As many services as possible capable of being traded on the platform (e.g., transportation services, hub (compression) services and pipeline storage services), recognising the need to avoid unnecessary complexities.

§ Trades conducted outside the capacity trading platform to be advertised ahead of time on the capacity trading platform listing service.

n.a.

Publication of information on secondary capacity trades

§ Publication of information on all secondary trades of pipeline capacity and hub (compression) services.

§ The information to be published is the price of the trade and any other information that might reasonably influence that price, taking into account measures to protect anonymity.

§ Publication should occur at or shortly after the time the transaction is entered into

n.a. n.a.

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Appendix B Comparison of the AEMC’s and GMRG’s recommendationsThe table below compares the AEMC’s recommendations with the GMRG’s final recommendations.

Table B.1: Comparison of recommendations AEMC Recommendations Consistency of GMRG’s Recommendations

StandardisationRequired Outcomes (Outcomes that must be progressed by the GMRG and are necessary to the implementation of the reforms)

Trades carried out through the capacity trading platform to be given effect through an operational transfer. Bare transfers will be allowed but the seller will be required to offer the buyer the option to use an operational transfer.

Standardisation of key primary and secondary capacity contractual terms for pipeline and hub (compression) services. Where possible and appropriate the standards should apply across the eastern Australian gas market.

Standards to be developed are for key operational, prudential and other contractual provisions in primary GTAs, secondary CTAs and operational GTAs. In response to stakeholder feedback, the AEMC also noted that it may be appropriate to prioritise the standardisation of operational GTAs and secondary capacity agreements (i.e. CTAs, the Exchange Agreement and Auction Agreement).

Standards developed for operational GTA, the Exchange Agreement and Auction Agreement but not primary GTAs or secondary CTAs:

Counterparties to existing contracts should not be materially disadvantaged through the standardisation process.

Capacity Trading PlatformRequired Outcomes (Outcomes that must be progressed by the GMRG and are necessary to the implementation of the reforms)

Creation of capacity trading platform(s) which include electronic anonymous exchange-based trading for commonly traded products in addition to a capacity listing service typical on current capacity trading platforms.

Trades carried out through trading platform to be given effect through an operational transfer.

Preferred outcomes (Outcomes that should be pursued by the GMRG unless it is clear there are greater benefits in alternative approaches)Single capacity trading platform operating across the east coast.

Shippers provided greater flexibility to change their receipt and delivery points.

As many services as possible capable of being traded on the platform (e.g., transportation, hub (compression) and pipeline storage services), recognising the need to avoid unnecessary complexities.

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Reporting FrameworkRequired Outcomes (Outcomes that must be progressed by the GMRG and are necessary to the implementation of the reforms)

Publication of information on all secondary trades of Pipeline capacity and hub services.

The information to be published is the price of the trade and any other information that might reasonably influence that price, taking into account measures to protect the anonymity of counterparties.

Publication should occur at or shortly after the time the transaction is entered into

Preferred outcomes (Outcomes that should be pursued by the GMRG unless it is clear there are greater benefits in alternative approaches)Trades conducted outside the capacity trading platform to be advertised ahead of time on the capacity trading platform listing service.

Having a mandatory requirement could impede trade and be difficult

to monitor/enforce

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Appendix C Members of the project teams and Advisory Panel

The tables below contain a list of the members of the Standardisation, Capacity Trading Platform and Day-Ahead Auction project teams and the Advisory Panel.

Table C.1: Membership of Project Teams and Advisory Panel

Project Team Members

Standardisation Project Team Capacity Trading Platform Project Team

Day-Ahead Auction Project Team

Sally Calder, AGL Kieran O’Leary, AGL John Jamieson, APA

Ainslie Lynch, APA Lino Fusco, CQ Partners Deidre McEntee, APLNG

Simon Taylor, DBP Trent Leach, DBP Leon Devaney, Central Petroleum

Peter Frost, EnergyAustralia Ishara De Silva, EnergyAustralia Andrew O’Farrell, Origin

Samantha Staunton, Epic Andrew Zancanaro, Jemena Matt Sherwell, Santos

Jan Peric, Jemena David Lawrence, Pacific Markets Consulting

Jeff Cooke, SEAGas

Michael Handley, Origin Jennifer Tarr, Stanwell Erin Bledsoe, Shell

Brad Mills, Shell Daniel Hamel, AEMO Kevin Ly, Snowy Hydro

Angelo Mantsio, AEMO Tom Walker, AEMC

Nicholas Pope, AEMO

Advisory Panel Members

Nevenka Codevelle, APA

Warwick King, APLNG

Graham Salmond, BHP

Mark Collette, EnergyAustralia

Rosemary Sinclair, Energy Consumers Australia

Paul Adams, Jemena

Chris Crozier, Orica

Greg Jarvis, Origin

Dr Stephen Bell, Qenos

Angus Jaffray, Santos

Tom Summers, Shell

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Appendix D Transportation services The box below provides an overview of the services that transmission pipelines typically provide.

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Box D.1: Services provided by transmission pipelines

Transportation servicesTransmission pipelines operating on a point-to-point basis usually offer:

Forward haul services, which provide for the transportation of gas from a receipt point to a delivery point in the direction of the predominant flow of gas.

Backhaul services, which involve the ‘virtual transportation’ of gas in the opposite direction to the predominant flow of gas. The term ‘virtual transportation’ is used in this context, because a backhaul service does not involve the physical transportation of gas. It instead involves a physical swap of gas at the point at which it is supplied into the pipeline for an equivalent amount of gas at the backhaul delivery point. To be able to provide this service, the volume of gas being backhauled must be less than, or equal to, the volume of gas to be transported on a forward haul basis, which is why it is offered on an as available or interruptible basis.

If a pipeline can physically flow in both directions across its full length (i.e. a bi-directional pipeline), then it will usually offer a single transportation service, which enables gas to be transported in either direction. Forward haul and bi-directional services can be provided on:

a firm basis – a firm service allows users to transport gas up to their maximum daily and hourly capacity reservation. The priority accorded to this service in terms of scheduling is higher than any other services and is the last service to be curtailed.

an as available basis – an as available service allows users to transport gas without reserving and having to pay for capacity on a daily basis, if there is spare capacity available. The priority accorded to this service is lower than that accorded to a firm transportation service in terms of scheduling and is curtailed before firm services.

an interruptible basis – an interruptible service also allows a buyer to transport gas without reserving and paying for capacity on a daily basis. However, the priority accorded to this service in terms of scheduling is lower than as available services and is usually curtailed ahead of both as available and firm services.

Storage servicesTransmission pipelines may also be used to provide the following storage related services:

Park services, which allow users to inject more gas into a pipeline than they take out on a particular day, up to a specified level and to store that gas in the pipeline. The additional gas supplied into the pipeline may be withdrawn by users at a later point in time, subject to constraints in their transportation contracts.

Park and loan services, which in addition to allowing users to store gas on the pipeline, also allows users to inject less gas than it takes on any given day (a loan), up to a specified level.

Ancillary services

Transmission pipelines can be used to provide a range of ancillary services, including:

Renomination services, which enable users to amend their nominations after the nomination cut-off time, which is typically the afternoon before the gas day.

In-pipe trade services, which enable gas to be traded between users at a notional point on the pipeline and allow users to manage their imbalances.

Capacity trading services, which enables capacity traded between users to be managed by the service provider rather than by the users (e.g. the user purchasing the capacity can make nominations directly to the pipeline rather than through the user selling the capacity).

Source: AER, Draft Decision Roma to Brisbane Gas Pipeline AA 2017-22, July 2017, Attachment 1, Appendix A.

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Appendix E Overview of the GSHThe GSH is a centralised trading, settlement and clearing facility that is operated by AEMO and can currently be used by market participants in the east coast to:

§ trade gas and Wallumbilla hub (compression) services through the exchange; or

§ advertise transportation products through the pipeline capacity listing service.

The remainder of this chapter provides a brief overview of the exchange and capacity listing service elements of the GSH, the steps that market participants have to take to be able to use the GSH and the governance framework that underpins the GSH. Further detail on the GSH can be found in the Gas Supply Hub Industry Guide that AEMO has published.107

E.1 Exchange

The exchange component of the GSH is operated using the Trayport Exchange Trading System (ETS), which is integrated with the market registration, settlement, prudential management and reporting systems that have been established for the GSH. The ETS includes:

§ a screen trading service (see Figure E.6), which allows participants to place anonymous bids and offers for standardised products, which are automatically matched by the exchange (see Box E.1); or

§ a pre-matched trade service, which allows participants to bring a bilateral trade in one of the GSH products to the exchange for settlement.

Box E.1: Exchange trading process

Trades conducted through the exchange involve the following steps:

1. Trading participants select the product they would like to trade and then complete the required information.

2. The order is validated by the trading systems.3. Confirmation of order submission is provided on screen and through a market report.

The trading system validates orders on submission to ensure:§ the order contains all of the required order components in the correct format;§ the order quantity and price adheres to minimum, maximum and parcel size rules; and§ Trading participants have adequate trading margin available to effect the transaction.

107 See: https://www.aemo.com.au/Gas/Gas-Supply-Hubs/Market-operations

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https://www.aemo.com.au/Gas/Gas-Supply-Hubs/Market-operations

Figure E.6: GSH screen trading screenshot

The screen trading service operates on a continuous basis, with bids and offers matched on price throughout the trading day using the following rules:108

§ orders are in the first instance matched based on price, with new offers matched against the highest price bid, and new bids matched against the lowest price offer; and

§ where two or more orders share the same price and are capable of being executed, the order with the earlier submission time is matched first.

While the screen trading service provides participants a number of trading options, it does not currently enable participants to make an order to buy or sell conditional on other orders being matched as well. A buyer or seller may wish to do this if, for example, they want to transport gas from Wallumbilla to Adelaide, which requires the use of two pipelines. AEMO is currently discussing this functionality with Trayport and expect that conditional bidding could be implemented.

Trades carried out using the screen trading or pre-matched service are settled by AEMO, with settlement amounts calculated on a daily basis and statements issued to participants on a monthly basis. The prudential arrangements in the GSH require participants to post collateral to cover their potential settlement exposure. Prudential assessments are conducted each business day to determine whether sufficient collateral has been provided or if further collateral is required. Further detail on how the settlement and prudential arrangements are expected to be applied to capacity products is provided in Chapter 8.

To deter trading participants from defaulting on their financial109 or delivery obligations and to deal with any default that does occur, the following arrangements have been put in place:

§ Market conduct rules have been included in Part 22 of the NGR (rule 543), which include requirements that trading participants must not:

108 AEMO, Gas Supply Hub Industry Guide, October 2016, p. 39.109 Financial default includes the failure by the trading participant to pay an invoice or to make a

margin call.

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o submit offers to buy or sell if they know, or ought to know, they will not be able to perform their obligations under a resulting transaction, or with the intention of defaulting in its performance; and

o intentionally or recklessly default in the performance of its obligations under any transaction arising on the exchange.

These rules are classified as both civil penalty and conduct provisions, which means that if a trading participant breaches these rules, then:

o the AER can institute civil proceedings in the Federal Court and seek an injunction or an order that the trading participant cease or remedy the conduct, and/or an order that a penalty be paid;110,111 or

o the counterparty that suffers loss or damage as a result of the default may institute court proceedings to recover the amount of the loss or damage.

§ If the trading participant does default on their financial or delivery obligations,112 AEMO may suspend or terminate the participant’s membership and use the Close Out and Offset Procedures (see Box E.6) to cancel any transactions that are on foot. If this occurs, the counterparty to the trade will be compensated 25% of the face value of the transaction, which is paid using the collateral collected from the trading participant.

110 The civil penalty provisions are set out in section 3 of the NGL. The maximum civil penalty is currently $100,000 for body corporates (or $20,000 for individuals) plus $10,000 ($2,000 for individuals) for every day it continues.

111 The AER may also issue an infringement notice if the AER has reason to a trading participant has breached a civil penalty provision. The maximum infringement notice is $20,000 for body corporates and $4,000 for individuals.

112 If, rather than defaulting on their delivery obligation, the trading participant breaches its gas delivery obligation and the variance is outside a 5% tolerance level then compensation must be paid to the counterparty (the compensation is based on the delivery variance quantity and the delivery price). If the delivery variance quantity is outside this tolerance then the party at fault must compensate the counterpart 25% of the value of the variation quantity.

See AEMO, Gas Supply Hub Industry Guide, October 2016, p. 74 for more detail.

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Box E.6: Close Out and Offset Procedure

The Close Out and Offset Procedure, within the Exchange Agreement, set out the instructions for the termination of transactions covering future Gas Days. The objectives of this procedure are to:

§ crystallise the loss so that creditors can take action to recover amounts owed by a defaulting party;

§ provide for an orderly termination process that minimises the impact on the operation of the gas market; and

§ allow exposure to be measured and collateralised with a clear designation of roles and responsibilities.

Under the procedures, the defaulting participant’s position is separated into a net quantity and an offsetting quantity. Transactions associated with the net position (buy or sell) are terminated leaving the defaulting participant without any future gas delivery obligations (zero net position). The defaulting participant is removed from transactions associated with the offset position so that the non-defaulting parties can be paired together to minimise the disruption to market. The netting process means the impact of default may need to be shared across all related parties to the defaulting party. This is currently done on a pro rata basis.

The way in which a transaction will be closed out will depend on the nature of the transactions:

§ Net zero: If a participant has a net position of 0 (i.e. bought 10 TJ and sold 10 TJ) the defaulting party is removed from the transaction and the counterparties to the defaulting party are matched together.

§ Net short: If a participant has a net short position (i.e. bought 5 TJ and sold 10 TJ) then 5 TJ of transactions will be offset. The net short position of 5 TJ will be cancelled and compensation paid to the buyer(s) involved in the transaction(s).

§ Net long: If a participant has a net long position (i.e. bought 10TJ and sold 5 TJ) then 5 TJ of transactions will be offset. The net long position will be cancelled and compensation paid to the seller(s) involved in the transaction(s).

If the defaulting party has made a loss on the transactions (i.e. bought for $8 and sold for $7) then AEMO collateralises the loss ($1) when the trade takes place so in the event of close out the seller is kept whole. If they have made a gain, then this money goes to paying any compensation owed to the impacted parties.

The close-out settlement amount is compensation payable by the defaulting participant to any of their counterparts (via AEMO) affected by the close-out of forward transactions, which is paid from the defaulting party’s collateral. Offset settlement amounts are determined for the defaulting participant, in aggregate they represent the gain or loss on any offsetting buy and sell transactions.

Note that compensation in the GSH is currently set at 25% of the face value of the transactions. The collateral requirement for buyers and sellers is therefore also set at 25%. The trade-off of higher compensation/penalty is higher collateral, which increases the cost of participating in the market.

Source: AEMO, Gas Supply Hub Industry Guide, October 2016, p. 84.

E.2 Capacity listing service

The capacity listing service is also operated using Trayport’s ETS. The listing service enables participants to advertise an interest to buy or sell transportation, compression and storage services through a bilateral trade. When listing these services, participants must provide information on the service and capacity being offered or sought, the term of the trade, the receipt and delivery points between which the service can be provided and the listing party’s name and contact details. This information is then published on the GSH and the BB (see Figure E.7). If another party decides that it wants to enter into a trade

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with the listing party, then it can contact the listing party directly and negotiate the terms of that trade bilaterally.113

Figure E.7: GSH listing service screenshot

Source: AEMO, Gas Supply Hub Industry Guide, October 2016, p. 45.

E.3 Use of the GSH

To utilise the GSH, market participants must be registered as GSH members and agree to be bound by the Exchange Agreement, which sets out the terms of participation in the GSH and the terms governing transactions entered into through the exchange. They must also pay a fixed participation fee and depending on the membership class, a variable transaction fee.

There are three classes of GSH members:§ Trading Participants are members that have access to the trading system to the

extent required to participate in exchange trading. Trading participants are currently required to pay a fixed annual fee of $14,500 for a single licence and variable transaction fees of $0.01-$0.03/GJ depending on the tenor of the product purchased. AEMO is, however, considering whether to reduce the fixed fee to $12,000 p.a. and to offer a rebate if, within a billing period, variable transaction fees are $7,000 or more. 114

§ Viewing Participants are members that have access to the trading system to the extent required to view information about product trading. Viewing Participants are currently required to pay a fixed annual fee of $5,500 per licence, but AEMO is currently considering whether to reduce this to an annual fee of $3,600.115

§ Reallocation Participants are members that have access to the Trading System to the extent required to participate in reallocations.116 Reallocation Participants are currently required to pay a fixed annual fee of $9,000.

Market participants that want to trade transportation capacity products using the exchange will need to be registered as a trading participant , while participants that only want to use the listing service can just be registered as a Viewing Participant. If a market participant is

113 ibid, pp. 44-45.114 AEMO, Impact and Implementation Report: GSH Exchange Agreement, 25 August 2017.115 ibid116 Reallocations are a transfer of a settlement amount from one party to another.

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an existing GSH trading participant , then it will not need to complete another registration to trade these products. If, however, a market participant is not already registered, it will need to register to become a trading participant and provide AEMO with organisational and financial information, pay the fixed participation fee (on a monthly basis) and post collateral with AEMO to be granted a financial trading limit on the exchange.117 As outlined in Table 2.5, shippers wishing to procure capacity from the exchange will also need to enter into an operational GTA with the relevant service provider(s).118

The Exchange Agreement provides trading participants with two types of access to products: automatic or requested. Participants currently have access to all trading products on the GSH when they become a trading participant , but they can ask AEMO to limit their access to particular products.119

Under the terms of the Exchange Agreement, AEMO may restrict a participant from access to, or use of, the GSH in whole or part if a suspension event occurs. A suspension event includes:§ the failure of the participant to meet a margin call;§ AEMO having reasonable grounds to believe the participant is no longer eligible to

trade in a product and the participant not providing sufficient evidence to verify its eligibility; or

§ the trading participant ’s delivery variance quantity (i.e. the difference between the quantity it was obligated to deliver and the actual quantity it delivered) is greater than 25% of the delivery quantity on three or more occasions in a rolling six-month period without a reasonable explanation.

AEMO may also suspend a trading participant from trading at the request of the AER in connection with an investigation of breaches of the market conduct provisions in Part 22 of the NGR. Under the terms of the Exchange Agreement, the suspension can only be lifted if AEMO is satisfied that the reason for the suspension no longer applies, or the act giving rise to the suspension no longer warrants continued suspension. If a participant fails to respond to a default notice AEMO can suspend the participant’s membership and close out any net long or net short transactions using the GSH Close Out and Offset Procedure (see Box E.6).

The Exchange Agreement also allows AEMO to terminate a participant’s membership if a default event occurs. A default event includes:§ the failure of the participant to pay an amount due;§ the participant breaches the market conduct rules in the NGR (see Box E.); or§ the participant no longer meets the criteria for registration in the relevant category.

117 The registration process takes up to 15 business days from receiving a complete application and associated documents. All the information required to register in the GSH, including the GSH Member Registration Guide can be found on AEMO’s website. See: https://www.aemo.com.au/Gas/Gas-Supply-Hubs/Participant-information/How-to-register


119 For example, a participant may ask AEMO to restrict access to the South East Queensland (SEQ) product because it does not have agreements in place on the Roma to Brisbane Pipeline (RBP).

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https://www.aemo.com.au/Gas/Gas-Supply-Hubs/Participant-information/How-to-register

E.4 Current governance framework

The governance framework for the GSH is set out in the NGL, Part 22 of the NGR, the Exchange Agreement and a number of procedures. Table E.22 provides an overview of the key elements of this framework, while Box E. sets out the GSH market conduct rules, which are a key element of the GSH governance framework that is overseen by the AER.

Table E.22: Current GSH governance framework Instrument Description

NGL AEMO operates the GSH as one of its statutory functions under section 91BRK of the NGL. This section of the NGL provides for AEMO to establish, operate and administer ‘gas trading exchanges’, which are defined as a facility through which persons may elect to buy and sell natural gas or related goods or services, including pipeline capacity. This section of the NGL also allows AEMO to make and administer a gas trading Exchange Agreement for the purposes of the exchange. AEMO’s gas trading exchange functions and the operation of the gas trading exchange are included as subjects for the NGR (section 74(1)(aaa)).

NGR Part 22 of the NGR contains rules applicable to the GSH. Matters covered in Part 22 include: § high level design parameters for the exchange;§ arrangements for the determination of charges for delivery failures;§ arrangements for becoming a member; § AEMO’s power to suspend a member;§ the subject matter for the exchange agreement; and § the market conduct rules (see Box E.). Part 22 can be amended by the AEMC through the usual rule change process. The AER monitors compliance and can investigate and enforce breaches under its general powers. It also has a specific duty in Part 22 to monitor compliance with the market conduct rules.

Exchange Agreement

The Exchange Agreement that has been developed by AEMO in accordance with the NGR and NGL, is a multilateral contract. It covers admission to the exchange, prudential requirements, operation of the exchange, product definition, delivery obligations and settlement. Some provisions (such as the Settlements and Prudential Methodology) are set out in subsidiary documents. The Exchange Agreement can be amended by AEMO over time to, for example, add new products, remove redundant products, or make refinements to existing products. Specifically, rule 540 allows any person to propose an amendment to the Exchange Agreement and states that AEMO can approve the amendment if it is satisfied: (a) the amendment is consistent with the NGL and the NGR; and (b) the amendment is appropriate having regard to the NGO and the compliance costs likely to be incurred by AEMO and participants. Before making a change, AEMO must consult with gas trading exchange members and any other persons AEMO thinks would be affected by the proposed amendment.

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Instrument Description

GSH Subsidiary Documents

AEMO has the power to make procedures in accordance with the Exchange Agreement. The procedures that AEMO has published to date include procedures on:§ reallocation (the Reallocation Procedure);§ the interface between systems (the Interface Protocol); § exchange fees; and§ security deposits.

Box E.2: Market Conduct Rules

The market conduct rules are set out in rules 542-544 of Part 22 of the NGR.

Rule 542 states that a GSH member must, in relation to its activities in connection with the GSH or the products it trades on the GSH:

(a) comply with all applicable laws relevant to the performance of its obligations; and

(b) not act fraudulently, dishonestly or in bad faith; and

(c) not engage in any conduct with the intent of distorting or manipulating prices (including reported prices) or misleading any person.

Rule 543 sets out a number of specific conduct rules relating to the trade of products on the GSH and states that:

(1) A GSH member must not submit offers to buy or sell products on the GSH:

(a) if the member knows, or ought to know, that it will not be able to perform its obligations under a resulting transaction;

(b) with the intention of defaulting in its performance;

(c) with the intention of causing a transaction with itself; or

(d) with the intention of causing a transaction with an associate, in circumstances where the terms of that transaction may be varied on terms that would not reasonably be agreed with a separate unrelated party.

(2) A GSH member must not intentionally or recklessly default in the performance of its obligations under any transaction arising on the GSH.

(3) A GSH member must not manipulate or attempt to manipulate the price of products traded on the gas trading exchange.

Rule 544 sets out a number of specific conduct rules relating to the provision of information and states that:

(1) A GSH member must take all reasonable steps to ensure that all data and information given to AEMO or another member in accordance with the Exchange Agreement is correct.

(2) A GSH member must comply with its obligations under the Exchange Agreement to keep information confidential.

These rules are all classified as conduct and civil penalty provisions and compliance with the rules is overseen by the AER.

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