Russell Pendlebury, Senior Economist
Meredith Mayes, Director
Daniela Moraes, Senior Adviser
Ryan Esplin, Economist
“The 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.”
(COAG Energy Council, Australian Gas Market Vision, December 2014, p.1.)
This vision for the gas market as set out by then Council of Australian Governments Energy Council in 2014 is still as important as ever, following a period of significant market change and significant reform in the east coast gas market.
The market has improved since 2018, which is evident in increased wholesale market liquidity, high seasonal volumes of capacity traded through the day-ahead auction for pipeline capacity and a more transparent market than ever through changes to the Bulletin Board.
The market is seeing encouraging trends such as industrial and retail customers registering as market participants individually or through collective buyer groups, with the Australian Energy Regulator (AER) recently noting there are more registrations in the market by industrial gas customers since 2018 than any other participant type. In addition, exporters of gas, gas producers and gas traders are playing a greater role in the market, increasing the breadth of participation and changing the traditional role played by large gentailer participants.
Plans by the Australian Securities Exchange (ASX) to refine the Wallumbilla hub futures product in order to promote liquidity and consideration by the Australian Government to establish an Australian Gas Hub at Wallumbilla and enhance the role of the hub, will help to move the east coast gas market closer to the vision.
Spot, ASX and contract price trends through 2020 were seen to moderate largely with falling LNG prices. This downward trend in LNG prices has recently reversed and prices are expected to be firmer over 2021. LNG spot prices in the first two months of the year have seen unprecedented levels driven by cold winter weather and a tight supply demand balance in the north Asia LNG market. The balance of the year sees an expected return of LNG spot prices more in tune with forward expectations for oil prices.
However, it should be noted that the absolute level of prices themselves should not necessarily be taken as an indicator of whether the market is functioning effectively. Nevertheless, the relative relationship between different price metrics can provide an indication of the competitiveness of the market and its ability to deliver efficient outcomes to consumers. Over the long term, where most gas is consumed by end users through a long term gas contract, this metric and its relationship to other metrics is key, including the relationship of contract prices to spot market prices, LNG netback benchmarks and measures relating to the forward or replacement cost of production.
The Australian Competition and Consumer Commission (ACCC), as part of its ongoing gas inquiry, has recently commented that contract prices, while falling in recent months, are still above short term spot price levels, and LNG netback and production cost measures. The ACCC has also commented that while competition has improved between suppliers, the constraint competition is posing on the market and market prices, is still limited. The ACCC is undertaking further investigation of the relationship between these different metrics and the pricing strategies of gas sellers on the east coast, including an examination of the concentration of upstream tenements and the competitiveness of gas supply across the east coast gas market.
Transparency measures endorsed by the National Cabinet in March 2020 are expected to be implemented during 2021. Once made, these reforms will introduce new ongoing reporting requirements for market participants to report price and short and long term gas supply arrangements, information on gas swaps and information on LNG export prices including the prices under short and longer term LNG contracts.
The reform program for the east coast and northern gas markets has been significant in recent years to address the functioning of the markets, particularly in relation to pipeline access, wholesale market liquidity and transparency across the whole sector. Future work, including the Gas Supply Guarantee Review to be carried out by the AEMC in 2021 and the next AEMC biennial liquidity review in 2022, are intended to build on these market developments while continuously assessing the need for further reform. Further reform, where required, can play an integral part in enhancing market operation and the outcomes for participants and end users.
In September 2020 the Australian Government announced a series of measures in relation to the gas market to help re-establish a strong economy as part of its JobMaker plan, developed as part of a number of recovery measures in response to the COVID-19 pandemic.
The government’s policy has prompted analysis by several think tanks and market observers, including the Grattan Institute, the Menzies Research Centre, the Australia Institute and Energy Quest in its latest quarterly report on the industry. There has been wider discussion in the media of the policy and the role of the gas market in the wider economy.
The aim of this Spotlight article is to address the current state of the east coast gas market, whether the market is functioning well, and what is being done, and has been done to improve its functioning, including the work program of the AEMC.
The article will show that wholesale market trends, particularly in relation to liquidity, have been improving in recent years. Recent reforms, especially to capacity markets and transparency, are paying off by improving market access to capacity and improving the visibility of market operations for all participants. Additionally, further work by the AEMC is designed to improve the operation of the market, with a view to enduring benefits for end users of gas. Issues in relation to the longer term supply of natural gas, including investment in supply and infrastructure, are dealt with at length by the ACCC in their latest report, and are not addressed here.
We will also discuss recent spot and contract prices for gas.
State of the market
Spot prices (DWGM, STTMs, GSH)
Spot prices moderated over 2020 largely with falling LNG prices. In 2021, prices are expected to be firmer, driven by expectations for LNG spot prices over the balance of the year.
Domestic gas spot prices have trended towards the LNG netback price (the price received for exported gas, net of liquefaction and delivery) over time. This is to be expected as the opportunity cost of selling gas into the Australian market, at least for producers in Queensland, is the price that can be received from export.
From late 2018 and through 2019, the global LNG spot price fell markedly with increased production from the United States and a mild winter in the northern hemisphere. Domestic spot prices followed, falling from around $10/GJ in the beginning of 2019 to around $6/GJ at the beginning of 2020, prior to the full impacts of the COVID-19 pandemic.
Economic shutdowns, first in China then across the globe, led to a softening of demand for LNG and further price falls with spot prices reaching a trough around $3-5/GJ. These levels had not been seen since 2015, the first year of LNG exports from Gladstone.
Figure 1: Domestic spot prices for natural gas and LNG netback prices (Jan 2018 – Jan 2021)
Source: AEMO, ACCC
In late 2020 LNG prices recovered as economic growth returned for several major LNG importers.
In early 2021, prices for spot LNG cargoes in January and February have risen to unprecedented levels driven by record winter temperatures boosting demand, transportation bottlenecks and supply outages in the north Asia and global LNG market.
Forward LNG prices for the balance of 2021 are trading at levels more reflective of expectations for forward oil prices.
Domestic gas prices have risen, reflecting high LNG export levels in October and November 2020, as well as recent increases in LNG spot prices, as seen in Figure 2.
Figure 2: LNG export flows (Oct 2018 – Nov 2020)
Source: AER gas weekly report 29 Nov – 5 Dec 2020.
The longer term trajectory for domestic spot gas prices will depend upon the future of the global LNG market, the tightening of offshore Victorian production and upon the decisions on LNG import terminal projects being considered in New South Wales, Victoria and South Australia.
Contract prices have also moderated with falling LNG prices. Differentials remain between contract prices and other price benchmarks, including spot prices, LNG netbacks and estimates of forward domestic gas production costs.
Ultimately, contract prices rather than spot prices will have greater relevance for most gas consumers. It is contract prices struck between producers and retailers for small customers, or between producers and large customers which determine the prices most consumers pay for natural gas.
Most of these contracts are negotiated bilaterally over-the-counter (OTC) with a relatively small volume traded on exchanges like the Victorian gas product on the ASX. Due to the confidential nature of the OTC contracts there is little publicly available information on contract prices.
However, in its ongoing inquiry into gas supply, the ACCC publishes a summary of the state of the east coast market every six months including the pricing of longer term contracts.
The latest interim report in February 2021 shows that while contract prices have fallen in recent months, they have not fallen as far as spot prices. There is a gap between long term gas prices struck for contracts in Queensland for domestic delivery and both the LNG netback price equivalent and the estimated forward cost of production, shown in Figure 3. Such a gap can be a concern given that in a competitive market, the prices agreed for gas sales might be expected to more closely reflect the cost of production or the opportunity cost of not selling the gas into the international market for LNG.
The ACCC has indicated a focus over the next 12-18 months on further analysis of the "pricing strategies of gas suppliers and a better understanding of the divergence between domestic prices and LNG netback prices" and an examination of the concentration of upstream tenements and the competitiveness of gas supply across the east coast gas market.
Figure 3: Gas commodity prices offered by QLD producers for 2021 supply
Source: ACCC Gas Inquiry, February 2021
In spite of this emerging gap, price offers by gas producers and retailers both fell as LNG prices fell over this period. Prices offered for 2021 supply by both producers and retailers, under gas supply agreements (GSAs) have declined from $8-14/GJ over the second half of 2019 to $6-8/GJ by mid-2020. The ACCC report finds that, similarly, average prices in GSAs entered into between commercial and industrial (C&I) users and gas suppliers (both producers and retailers) have gone from just under $10/GJ to slightly under $8/GJ, the lowest level since 2016.
This downward trend is observed in the ACCC’s summary of producer and retailer offers for 2021 supply:
Figure 4: Gas commodity prices offered for 2021
Source: ACCC Gas Inquiry, February 2021.
This chart reflects the narrowing and decline in the price offered for 2021 supply as LNG prices have declined. However, prices were still above LNG netback prices and measures of forward production costs.
When comparing long term contract outcomes to spot prices it is worth considering retail market changes where end users of gas are increasingly looking at wholesale spot markets to meet their contractual requirements for gas. This evolution in the market may help to see end user prices more closely reflect the wholesale value of the commodity.
Forward LNG prices
Downward trends in LNG prices are expected to reverse with prices recovering in 2021.
Forward Asian LNG spot prices and the LNG netback at Gladstone play an integral role in influencing gas prices in the east coast market, as was shown in Figure 1 above. The ACCC publishes the LNG netback price series regularly as part of its ongoing gas inquiry and is currently in the process of reviewing the LNG netback price series and methodology, with an issues paper to be released in March 2021.
The ACCC netback price series is presented in Figure 5, updated on 1 February 2021, showing relatively flat expectations for forward LNG prices to December 2022.
Figure 5: ACCC LNG netback series
Source: ACCC LNG netback price series, 1 February 2021
The series has strengthened at the end of 2020 and forward into 2021. The price spike shown in January and February 2021 is driven by cold winter temperatures and a tight supply demand balance in the north Asian spot LNG market. In spite of reported netback prices of $19.45/GJ in February, the annual average netback price for the balance of 2021 is $7.57/GJ and $7.10/GJ in 2022.
LNG spot prices have linkages to oil through the large volumes of LNG that are sold under long term contracts with indexation to oil on 3 to 6 month time lags. This is particularly relevant in the Asian LNG market, where oil indexation is principally to the Japanese customs cleared crude oil price (JCC).
LNG spot prices diverge from these longer term contract prices according to the fundamentals prevailing in the spot market, including seasonal factors and the overall supply demand balance, as has been observed in recent spot price movements. Nevertheless, a broad linkage can be observed over time, with a time lag response to changes in oil prices.
Forward Production Costs
Estimates of forward production costs reflect the widespread view that it is unlikely that domestic gas contract prices will settle below $6/GJ irrespective of the LNG netback prices or spot price benchmarks.
Estimates of forward production costs can provide an indicative level below which long term domestic contract prices are unlikely to go, even while LNG spot prices could feasibly be lower for periods of time.
The recent ACCC gas inquiry report refers to a cost floor of A$5.55/GJ in Queensland. This assumes the forward cost of production from the Middle Surat and Roma Shelf. This is not the full lifecycle cost, or replacement cost, of production from these fields. However, it serves as a useful indicator of a price level below which domestic prices are unlikely to go, in particular for longer duration contracts.
The ACCC report also provided an estimated forward production cost of $5.60/GJ in Victoria, using the Sole field as the cost benchmark. This is also a forward looking cost only.
Liquidity in wholesale gas markets
Outcomes of the AEMC’s 2020 biennial liquidity review
The AEMC carried out its second biennial gas liquidity review in 2020 to report on insights into the effectiveness of the gas markets and the recent developments in the sector across Australia. The AEMC found that liquidity is growing in Australia’s wholesale gas and pipeline capacity trading markets. The market participant survey results also reflected that stakeholders were optimistic this trend would either continue or liquidity would be maintained in each of the facilitated markets over the next two years.
The AEMC found significant liquidity growth at the Wallumbilla GSH, high levels of liquidity in the compulsory Victorian declared wholesale gas market and short term trading markets (STTM) and substantial positive impacts from the introduction of the day ahead auction of pipeline capacity (DAA), discussed later in the section on pipeline capacity trading liquidity. Stakeholders also reported increasing liquidity in bilateral physical contracts and financial markets.
Stakeholders noted a lack of confidence in hub pricing for forward products for the Wallumbilla and Moomba GSH due to the low number of trades and concerns about upstream market concentration.
In contrast to the facilitated markets, there was no liquidity in the ASX product linked to the Wallumbilla GSH price. This lack of liquidity was considered to limit the value of Wallumbilla as a price benchmark for the east coast gas market.
However, there is currently a new financial-physical delivery product proposed by the ASX for the Wallumbilla GSH and a new futures product proposed for the Sydney STTM. As a result, stakeholders were optimistic for future liquidity and the role of these new products in promoting liquidity.
There are a number of drivers behind increasing liquidity. Stakeholders noted that the AEMC’s 2017 improvements to information available on the Gas Bulletin Board have reduced the perceived risk of trading in some ASX futures products and helped to increase liquidity.
While improvements in liquidity may reflect the low starting point in facilitated markets on the east coast, the signs are encouraging and further product innovation should support these trends.
Spot trade liquidity through Q3 2020, according to the AER
The AER provides updates on the gas market through its Wholesale Markets Quarterly report. It notes in its latest report that while trade in these markets has been 73.1 PJ over the last year, accounting for 11-12% of east coast demand (typically between 600-650 PJ per year), there is a clear trend of increasing trade in spot markets that offer an alternative to contractual transactions where prices are not published. Figure 6 below shows liquidity improving with record trade quantities for a second consecutive quarter.
Figure 6: Spot trade liquidity
Source: AER Wholesale Markets Quarterly, Q3 2020
From this data, the AER has noted there has been greater participation by producers (including LNG producers) and traders. According to the AER, this development may in part be related to greater excess production available in Queensland; extensive outages across all LNG export projects; and lower LNG exports more generally. In addition, Esso and BHP stopped joint marketing of gas in 2019, while Shell and Arrow Energy also registered as STTM and day-ahead auction (DAA) participants in 2019 and 2020 respectively.
This helps to contribute to the diversity of large suppliers participating in the market, which acts as a competitive constraint on prices. Exporters and producers such as Shell, Santos, Esso and BHP, and many new industrial customers are scheduling more gas into the market. The AER's report stated that this has had the effect of these parties winning market share away from the historically dominant gentailer participants (that is, AGL, Origin Energy and EnergyAustralia). The AER has commented that since 2019 and the introduction of the DAA for pipeline capacity, the market share trend has accelerated. As a result, the emerging exporters and producers are beginning to set market prices a greater proportion of the time rather than the gentailers. For example, between 40-50% in Victoria and Sydney in Q3 2020 and 37% of the time in Brisbane.
Traders have also emerged as a participant group and have been actively engaged in arbitrage between locations by securing cheap transportation services through the DAA, the report noted, The AER noted that since the auction commenced in Q1 2019, traders have consistently held net sell positions in the spot market, reaching a record 1 PJ in Q3 2020. They have set the price 17% of the time in Sydney in Q3 2020. Notable traders include Strategic Gas Market Trading, Macquarie Bank and PetroChina.
On the buy side, there has also been increasing interest from participants that are not gentailers. The AER noted that his may in part be driven by the development of new retail models that link offers to wholesale gas spot market prices. Collective buyer groups have emerged to source cheaper gas from spot gas markets as an alternative to buying gas through long term bilateral contracts. According to the AER, there are more registrations in the market by industrial gas customers since 2018 than any other participant type. Industrial and retail participants have been setting the spot price for gas more often as their participation has grown.
Trade at the Wallumbilla hub over the 12 months ending Q3 2020 totalled 22.5 PJ, while a total of 50 PJ was traded in the Victorian, Sydney, Adelaide and Brisbane spot markets. The AER concluded that these traded amounts suggest that large volumes of gas are being traded off market, and consequently are not reflected in the Wallumbilla market price. This conclusion was consistent with the ACCC Gas Inquiry report in which it was noted that trade at Wallumbilla represented a fraction of bilateral trade in Queensland.
Liquidity in ASX products and new products being developed
Since 2015 and 2018 respectively, the ASX has offered forward hedging contracts at the Wallumbilla gas supply hub and the Victorian DWGM. These products are cash settled contracts for difference (CFDs) against the relevant wholesale reference gas prices.
Current products offered on the ASX:
ASX Wallumbilla Wholesale Gas Calendar Month Futures
4 to 6 months ahead
ASX Wallumbilla Wholesale Gas Calendar Quarters Futures
4 years ahead (4 calendar years or financial years)
ASX Victoria Wholesale Gas Futures: Gas Quarterly Futures
2 calendar and 2 financial years ahead
ASX Victorian Wholesale Gas Futures: Gas Strip Product
2 calendar and 2 financial years ahead
In addition to the existing products, the creation of a potential financial-physical product at Wallumbilla is under consideration by the ASX and AEMO as well as a monthly Victorian gas product and a Sydney STTM product. There has also been interest in a spark spread (the difference between the wholesale electricity price and the wholesale gas price) product for Victoria. Spark spread products provide market participants with another tool that can help to manage the risks of offering electricity capacity in the contract market. The introduction of such a product in the Victorian market could help to enhance trade and liquidity in forward electricity markets and spot and forward gas markets in Victoria.
The AEMC’s biennial liquidity review noted that although these financial markets are at an early stage in their development, liquidity has been improving and this is expected to continue as participation grows.
In addition, liquidity is expected to grow in the future as the limited diversity of products is addressed with the introduction of new products such as the Victorian monthly product.
Nevertheless, some barriers will remain in place. Notably, the requirement for an Australian Financial Services License to trade gas derivatives, something not all market participants are willing to obtain.
Liquidity in the ASX Victorian futures product is shown in figure 7 below.
Figure 7: ASX Victorian futures trade
Source: AER Wholesale data
While the AEMC found that overall liquidity in the east coast gas market has improved, it did observe that there is no liquidity in the Wallumbilla GSH ASX futures product. This lack of liquidity has been attributed to a lack of confidence in pricing at Wallumbilla arising from the limited underlying market liquidity combined with concerns about high levels of upstream market concentration. The financial-physical product under development by the ASX noted above is intended to remedy this lack of liquidity.
In addition, AEMO and market participants are considering a number of changes to the gas supply hub, including:
Improving off-market transparency (reporting the delivery point of a trade where this is at locations distant to Wallumbilla but traded on the Wallumbilla GSH).
- ASX gas futures proposal. AEMO is considering how to achieve the ASX’s proposal for a Wallumbilla gas futures product with the conversion of the financial product prior to delivery date into a GSH monthly physical product.
On 28 January, two new NSW trading locations, Wilton and Culcairn which are at the borders of the Sydney STTM and the DWGM, were added to the Gas Supply Hub Exchange Agreement. The new products are now available for trade.
Liquidity in pipeline capacity trading in markets administered by AEMO
The capacity trading reform package introduced to east coast and northern gas markets was recommended by the AEMC as part of its Eastern Australian Wholesale Gas Market and Pipelines Framework Review (East Coast Review), endorsed by the COAG Energy Council.
The reforms were passed into law in November 2018, with the capacity trading platform and day ahead auction commencing on 1 March 2019.
They were expected to foster the development of a more liquid secondary capacity market, thus improving the broader operation of the market. The reforms included four key elements:
A DAA of contracted but un-nominated pipeline capacity on designated facilities across the east coast gas market
A capacity trading platform to facilitate sales by capacity holders ahead of the auction and provide for exchange-based trading
Standardised provisions in capacity agreements to make capacity more fungible
A reporting framework for secondary trades of pipeline capacity and hub services.
Figure 7 shows the capacity secured on the DAA auction from market start until September 2020. It shows a significant amount of capacity has been secured on the South West Queensland Pipeline (SWQP), and the MSP during the winter months. Significant capacity has also been secured on the Roma Brisbane Pipeline (RBP) and the Eastern Gas Pipeline (EGP) throughout the year. The AER reported a total of 13.7 PJ in unused pipeline capacity was auctioned across eight facilities in the quarter with July 2020 recording the highest monthly volume of capacity and auction won.
On the MSP an average of 57-90 TJ per day was secured in the winter months of July and August over the first two years operation of the DAA. This is between 12-17% of the operational capacity of the pipeline through these winter months. Given this capacity would have otherwise been contracted but not used, this is a significant improvement in the ability of users to move gas around the system efficiently in periods. To date, most of the pipeline capacity on the DAA has been secured at zero, or close to zero prices.
However, where demand for contracted but unused pipeline capacity in the auction is high — reflecting peak demand conditions in some markets — clearing prices have trended well above zero. On 7 August 2020 for example, record clearing prices of $1.49/GJ occurred on the MSP. The AER reported that auction pricing in these circumstances appeared consistent with the high value placed on gas during peak pricing conditions in southern markets.
More generally regarding the operation of the DAA, the AER noted in its Q3 2019 Wholesale markets quarterly report that the DAA has resulted in lower prices in NSW and Victoria as participants have acquired pipeline capacity to take advantage of price differences between Queensland and the southern states.
The ACCC has also observed that the DAA appears to have resulted in greater volumes of gas being traded at Wallumbilla and Moomba, and there has been an increase in trade in the Wallumbilla-Moomba spread product and a greater level of liquidity in the Sydney STTM and Victorian DWGM. Thus, the ability of the capacity trading reforms to connect markets, and market prices, across the east coast more closely is to the benefit of end users in the short and longer term.
Figure 7: Capacity won at Day Ahead Auction (TJ/month)
Source: AER wholesale statistics
As well as significant volumes of capacity secured through the DAA, there has been a steady increase in the number of active participants using the auction with 12 participants trading in September 2020. In Q3 2020, the AER reported that the number of participants who have won capacity since the commencement of the auction is now 17.
Figure 8: Active participants on the Day Ahead Auction
While there was only one trade on the capacity trading platform (CTP) in the same period, in February 2020, a number of longer-term products can be traded including firm forward and bi-directional services, firm compression services and firm park (storage) services. In spite of this scant trade to date, a number of stakeholders, in the course of the AEMC’s biennial liquidity review, noted their support for the mechanism in the longer term.
Forward work program of the AEMC
The forward work program of the AEMC will be responsive to the needs of market participants and wider stakeholders as opportunities to enhance the operation of the gas sector are identified and the benefits to end users assessed.
In the near term, the AEMC is commencing a Review into the Gas Supply Guarantee early in 2021. This review was requested by Energy Ministers and will involve extensive engagement with stakeholder groups across all segments of the market, market bodies and state and territory governments.
The Gas Supply Guarantee
The Gas Supply Guarantee (GSG) was initiated by the Australian Government in March 2017 in a package of measures, that also included the Australian Domestic Gas Supply Mechanism (ADGSM), intended to ensure both the adequate supply of gas to the Australian market but also, as in the case of the GSG, to ensure adequate gas supply to peaking gas generators at times of high electricity demand.
Under the GSG, gas producers and pipeline service providers made voluntary commitments to the government to supply gas-fired generators with gas in regions under system stress, such as during demand spikes or heat waves.
While the mechanism has not been called on to date, and guidelines developed by AEMO are still in operation until March 2023, the AEMC has been tasked by the Energy Ministers to independently assess the GSG mechanism and its operation across the NEM and whether it should be embedded in the national regulatory framework. This work forms part of the government’s focus on the affordability, reliability and security of gas supply.
The AEMC will be commencing the review early in 2021 and reporting back to ministers by the first quarter of 2022. The AEMC will be working closely with AEMO, the AER, ACCC, industry and state and territory governments in the course of the review.
Biennial Liquidity Review
The AEMC will be conducting the biennial liquidity review again in 2022. It will provide an opportunity to consider the areas for improvement that were suggested by stakeholders during the 2020 biennial liquidity review. These included:
A review of the structure of facilitated markets. Some stakeholders suggested that the differing operational structures in each market could be a barrier to entry. It was suggested that there was potential to enhance the structure of the Brisbane STTM and Wallumbilla GSH together to improve liquidity.
Additional trading points. For example, Culcairn and Wilton and whether additional trading points on more pipelines could facilitate greater liquidity across the east coast gas market.
Prudential arrangements. It was suggested that an alignment of the various market prudential requirements or the development of a single requirement across the markets, would reduce cost and complexity for participants of these markets and may support greater numbers of participants.
A review of the utilisation of the capacity trading platform.
The AEMC anticipates that by 2022 additional data and trading information will enable an assessment of these particular issues as well as whether liquidity is improving across the gas wholesale markets. Where trends are not improving, and this is seen to be a problem, the review will provide an opportunity for all stakeholders, including end users, to identify future possible market reforms.
Additional measures in relation to reviews of the capacity trading reforms and further transparency measures endorsed by National Cabinet but yet to be implemented, may have direct or indirect implications for the forward work program of the AEMC.
Review of capacity trading reforms:
The Senior Council of Officials (SCO) is expected to undertake a review of the capacity trading reforms two years following its implementation, in 2021. As part of this process, SCO is expected to assess whether the reforms are working as intended or if further reforms or refinements are required.
In February 2021, the ACCC noted its support for the 2021 post implementation review of the capacity trading reforms, considering recommendations made to address concerns around charges associated with the new reforms.
Additional transparency measures endorsed by National Cabinet:
In recent years the AEMC has played a key role in improving the transparency of the east coast gas market, including in 2017 through the Improvements to the Natural Gas Bulletin Board rule change.
The AEMO-operated bulletin board provides up-to-date gas flow information on all major gas production fields, major demand centres and natural gas transmission pipelines across all jurisdictions apart from Western Australia. Prior to the introduction of the bulletin Board transparency measures, the day-to-day operations of the market were considerably more opaque.
Further transparency measures, arising from the AEMC’s East coast gas review and the subsequent ACCC-Gas Market Reform Group’s report on gas market transparency, are currently under development. New reporting obligations are expected to be established in 2021 following the required law and rule changes.
Table: Overview of measures to improve transparency in gas markets, from the AEMC Biennial liquidity review, 2020
|Information area||Key changes agreed by the COAG Energy Council|
|Gas, LNG and infrastructure prices||New reporting requirements for sellers, LNG exporters and owners of storage and compression facilities to report price and short- term contract information (GSAs and gas swaps) for publication on the Gas Bulletin Board.|
|Supply and availability of gas||Producers to report on reserves and resources broken down by field including annual drilling activities, volumes of gas they intend to produce, and contracted production levels. LNG importers to report on supply balance and contracting levels. Info to be reported through GBB or GSOO.|
|Demand for gas||Large gas users (>10TJ/d) to report on connection point and facility capacity and daily gas consumption. LNG exporters to report capacity outlook, daily gas consumption and shipment volumes. Info to be reported on GBB.|
|Infrastructure||Entities developing new infrastructure (>10TJ/d) are required to report facility information including capacity, type, stage of development and expected commissioning date. Info to be reported on GBB.|
|AEMO Gas Statement of Opportunities||Make the AEMO’s survey mandatory and extend the GSOO to the Northern Territory.|
Source: COAG Energy Council, Measures to improve transparency in the gas market, regulation impact statement for decision, March 2020.