The Australian Pipelines and Gas Association (APGA) represents the owners, operators, designers, constructors and service providers of Australia’s pipeline infrastructure, connecting natural and renewable gas production to demand centres in cities and other locations across Australia. Offering a wide range of services to gas users, retailers and producers, APGA members ensure safe and reliable delivery of over 1,600 PJpa of gas consumed in Australia alongside over 4,500 PJpa of gas for export.[1] We are at the forefront of Australia’s renewable gas industry, helping achieve net-zero more quickly and affordably.
APGA welcomes the opportunity to provide a submission to the Select Committee Inquiry into Energy Planning and Regulation in Australia. Australia’s energy systems and markets are complex and evolving. This makes planning for the energy transition while maintaining system stability a Herculean task. This task has been hampered by decades of intervention in energy markets, particularly into gas markets, which is misaligned with the current priorities of Australia’s energy markets.
APGA supports a net zero emission future for Australia by 2050[2]. Renewable gases represent a real, technically viable approach to lowest-cost energy decarbonisation in Australia. APGA sees renewable gases such as hydrogen and biomethane playing a critical role in decarbonising gas use for both wholesale and retail customers[3]. APGA is the largest industry contributor to the Future Fuels CRC[4], which has over 80 research projects dedicated to leveraging the value of Australia’s gas infrastructure to deliver decarbonised energy to homes, businesses, and industry throughout Australia.
Today’s National Gas Law has been designed to restrict the risk of market power across a mature, stable gas market. While the National Electricity Law has been evolving to address the challenges of the energy transition, the National Gas Law has all but been left at the starting gate. Amendments to expand coverage of renewable gases aside, the National Gas Law has been left addressing the perceived problems of the past despite a drastic need to address the challenges of the present.
The Australian Energy Market Operator (AEMO), Australian Competition and Consumer Commission (ACCC) and the Federal Government through its Future Gas Strategy have all identified that the changing energy market of today needs more gas investment. Yet the current National Gas Laws are not sufficient to address two looming challenges:
Addressing both of these challenges is critical to enabling a successful and efficient energy transition.
These challenges are analogous to challenges faced by the National Energy Market (NEM). At any one time, the NEM not only needs investment to ensure sufficient energy production (generation) over a year, but it needs investment in sufficient energy supply capacity (batteries, pumped hydro, GPG) to get energy to customers when they need it. Failing to do so results in high prices or, at worst, blackouts. At the same time, decarbonisation requires an increase in new renewable energy production (solar, wind) inconsistent with current market design.
The same challenge exists in the gas supply chain. The East Coast Gas Market not only needs investment to ensure sufficient energy (gas) production over a year, but it needs investment in sufficient energy supply capacity (pipelines, gas storage) to get energy to customers when they need it. Failing to do so results in high prices or, at worst, gas shortfalls. At the same time, decarbonisation requires an increase in new renewable energy production (biomethane, hydrogen) inconsistent with current market design.
The National Gas Law disincentivises investment in both gas production and gas supply capacity, across both natural and renewable gas alike. The economic regulation of gas infrastructure under the Law increases the risks and costs of investment in both supply and capacity, and risks returns on existing infrastructure. This does not create an environment conducive to enabling the significant investment required to meet current and future gas supply and capacity shortfalls.
Market interventions and reforms over the last few decades have facilitated the current shortfalls of investment in gas supplies and infrastructure. While each intervention to date may have had some positive short to medium term impacts for customers, each of the factors seen in the table below introduced long term supply adequacy and price risk, compounding across each successive intervention. It is this multi-intervention disregard for the long-term market impacts which contributed to the circumstances of the 2022 gas crisis and the need for further intervention to avoid future gas shortfalls.
Key to reversing this trend will be intervention which promotes investment in both gas volume supply and gas supply capacity.
Table 1: Impacts of market interventions since 1990 and impacts on gas cost[5]
|
Intervention |
Positive market aspects/impacts |
Negative market aspects/impacts |
|
Modern market foundation (late 1990s) |
· Gas supply and transport markets both transacted via bilateral contracting (GSAs & GTAs). · Firm bilateral contracts were the foundation for supply & infrastructure investments. · Customers for which the cost of firm contracts was not the right business decision were able to access shorter term contracts for excess capacity where available. · Infrastructure regulated sparingly where use of market power observed by regulators. · Gas producers needed to be long in supply to guarantee foundation contracts. · Gas market long in supply provided supply security. |
|
|
Introduction of facilitated markets (1999–early 2010s) |
· Customers able to access increased price transparency in the short to medium term, increasing supply price transparency · More customers able to choose to accept risk of not securing supply or transport via firm bilateral contracts, increasing customer market liquidity. |
· Link between gas consumption and gas supply or infrastructure investments became more opaque. This increased the risk of underinvestment in supply and infrastructure, driving the market towards a shorter gas market in the long term. |
|
Introduction of LNG exporters (early 2010s) |
· Allowed for expansion of coal seam gas (CSG) supply at a scale which allowed for production costs below what would have been achievable through slower, staged development. |
· Introduced substantially more demand than supply into the market, transitioning the market from being long in supply to being short in supply · It is worth noting that while proactive reform to address this risk could have been put in place in the leadup to LNG export development, this was not done. |
|
Introduction of moratoria & long-term forecasting (mid 2010s) |
· Forecasting provided a level of foresight into medium- to long-term gas supply adequacy, allowing for future shortfalls to be identified. |
· Moratoria such as in Victoria impeded gas supply investment, further driving the market towards a shorter gas market in the long term · Forecasting consistently underrepresented shortfall risk due to under forecasting of GPG demand and unrealistic gas demand electrification assumptions. |
|
Tightening of gas infrastructure regulation (late 2010s to early 2020s) |
· Economic regulation of all pipelines sought to reduce likelihood of gas transport being priced above regulated asset pricing. · Introduction of Day Ahead Auction (DAA) provided opportunistic gas customers access to contracted but unnominated pipeline capacity from $0 starting price |
· Provided the Australian Energy Regulatory (AER) with self-initiation rights for pipeline Form of Regulation Review (FoRR), increasing regulatory risk for pipeline investors without requiring the AER to have a basis for threatening an asset’s revenue security via FoRR. · DAA gave firm transport capacity purchased by gas customers for security of supply and provided it at $0 starting price to their competitors, reducing shippers’ business case for investing in firm transport, in turn risking localised market shortages · Note that this reform occurred at a time when gas prices multiplied due to the market transitioning to a short supply market, rather than addressing this transition. |
|
Market ahead of 2022 gas crisis (Mid 2022) |
· As a result of all above reforms, wholesale gas customers save 10s of per cent on gas and transport costs and have accessed additional marginal volumes of gas otherwise only available via bilateral contracting |
· The market is short in supply, increasing gas prices by 100s of per cent from long market prices. · Long term investment in supply is disincentivised by moratoria, underestimated demand, and facilitated markets obscuring the connection between gas supply investment and gas consumption. · Investment in firm transport disincentivised as DAA transfers benefits of firm haulage investment to firm shippers’ competitors which do not invest. |
|
Market after East Coast Gas System Stage 1 Reliability and Supply Adequacy reforms, and other reforms (from 2023) |
· Wholesale gas customers which do not invest to ensure their own supply security can rely on AEMO to direct market participants if a market supply adequacy event arises. |
· Incentive for gas customers to contract firm gas supply or haulage further reduced by AEMO powers to direct supply in the event of a gas supply adequacy event, risking increased shortness of gas supply in the east coast gas system. · $12/GJ effectively set as a floor price, as this is what is considered by government to be ‘reasonable’ · The AER will determine which form of regulation should apply to a pipeline, by applying the form of regulation test · AER Form of Regulation Reviews mean the form of regulation applying to an existing pipeline may undergo review at any time |
|
The East Coast Gas Market today |
· Customers may act in the knowledge that pipeline tariffs, which account for around 1/10th of delivered gas costs, could face the threat of a FoRR in the short term. · Customers can access gas, when available, via facilitated markets without needing long term contracting. · Customers can access pipeline transport without firm contract when available and often at $0 cost. |
· The east coast gas market is chronically short in supply, meaning that customers must compete for supply. · As a result, prices are set based on the next highest paying customer, increasing gas prices by multiple dollars per gigajoule. · Revenue certainty for all investment in pipeline infrastructure is threatened by AER FoRR. · All investment for new gas production must be endorsed by Ministers (in the form of exemptions) to get around price caps. |
The Senate Committee must consider the context of all of these reforms when it comes to energy system planning as a whole.
In addition to the comments on the National Gas Laws above, APGA makes the following comments specific to the bodies identified in the Terms of Reference.
There has been considerable change to the National Energy Laws over the past few years, including the amendments to the National Energy Objectives (NEOs). These have not all been positive and, in some cases, represent significant missed opportunity.
Other issues relating to the development of AEMO’s Integrated Systems Plan, which is specified in the National Electricity Laws, are explored in the AEMO section below.
In late 2022 the Department of Climate Change, Energy, Environment and Water (DCCEEW) commenced consultation on changes to the National Energy Objectives to include an emissions reduction objective.[6] One of the proposed amendments in the package was to acknowledge interactions between electricity and gas markets and enable management of transition impacts – effectively by collapsing the separate electricity, retail electricity, and gas objectives into the energy objectives.
As noted in the December 2022 consultation paper,[7]
The NEL and NGL were drafted to manage the two energy markets and systems separately, however, the gas and electricity markets are increasingly intertwined and interdependent. This was evident over recent months with the international impacts on our export-linked gas market flowing through to prices in the electricity market. The laws do not currently acknowledge gas as a transition fuel. To ensure the peaking and firming capacity role of gas-powered generation is taken into account in the regulatory approaches, particularly in the context of the decarbonisation of the NEM, it will likely be necessary for market bodies to consider how decisions in one market (gas) affect outcomes in another (electricity), and vice versa.
[…]
To address these issues, Officials therefore propose replacing current references to ‘consumers of electricity’ in the NEO and ‘consumers of natural gas’ in the NGO, with ‘consumers of energy’.
This proposed amendment and draft Bill was not carried forward into the subsequent Laws, citing stakeholder concern with the risk of unintended consequences.[8] Unfortunately, the failure to pursue this change has its own unintended consequence – the best interests of energy customers as a whole are not considered under each law. This means that the best interests of gas and electricity customers must be considered separately under each individual law.
AEMO currently cannot consider gas adequately and the decarbonisation of gas use in the ISP.[9] Because of this, it may recommend inappropriate and unnecessary overinvestment in electricity infrastructure (see AEMO section following).
APGA also notes that simply including an emissions reduction objective does not extend fairness in application to infrastructure investments for emissions. Expenditure for biomethane and hydrogen should be, but is not always, the same as electricity-related emissions reduction infrastructure, such as EV charging facilities.
On 28 October 2022, Energy Ministers proposed amendments to the National Gas Law and Regulations to bring hydrogen, biomethane and other renewable gases under the national gas regulatory framework.[10]
APGA supported these amendments in principle, with proposed amendments specific to how class orders, class order exemptions, and information disclosures would be handled for renewable gas infrastructure. At the time, the further amendments in 2023 and 2024 to gas regulatory frameworks were yet to be introduced, and hence the potential impacts of these amendments on renewable gas infrastructure not specifically considered.
Ultimately what this amendment has achieved is imposing the full suite of regulations that apply to the mature natural gas industry onto the new renewable gases industry. While this does come with some relief in the form of the Greenfield Incentive and Price Protection, this is not automatic. Further, the Greenfield Incentive does not address the negative impacts of ringfencing obligations, which have shut out a critical source of investment needed to develop these markets.
There is a realistic scenario where a newly commissioned hydrogen pipeline will be immediately subject to access, transparency and ring fencing requirements, and may not have the benefit of the Greenfield Incentive extended to it, opening to AER FoRR. While appropriate for a mature market, this impedes renewable gas market development.
This acts as a considerable disincentive to investment and impedes the development of these markets.
The AER is to be commended to its general commitment to limiting the burden of regulation and compliance in the exercise of new regulation applying to gas pipeline service providers – particularly the Wholesale Market Monitoring and Reporting framework. The AER has engaged in open and genuine ongoing consultation on this and other new reforms.
However, this does not extend to the Form of Regulation Review (FoRR) powers, which arose through amendments to the National Gas Laws. The manner in which the AER chooses to exercise these powers is within its discretion, and in the case of the FoRR process, are problematic.[11]
APGA understands the AER will sequentially review the form of regulation of all transmission pipelines currently operating in Australia, at a rate of approximately two per year. The process, timelines and intended order of pipelines for review has not been made transparent. However, the initial selection of the South West Queensland Pipeline suggests strategic importance is a factor.
AER does not require evidence of exercise of market power before commencing a review. The AER also does not intend to use existing monitoring, or its new Part 10 or Part 28 information gathering powers, to determine use of market power and does not consider it necessary to undertake separate monitoring to determine use of market power.
The threat of a change in regulation at any time will disincentivise investment[12] as any new transmission asset will necessarily need to account for its form of regulation to be subject to this change. This may have material impacts on final investment decisions of other assets which rely on pipeline connections, such as new supply in the Beetaloo Basin. This process will ultimately asymmetrically truncate returns of gas infrastructure at a time when that investment in gas is needed, potentially undermining incentives for such investment.
APGA recommended to the AER that they develop a transparent framework to provide guidance to on the conditions that would prompt an AER-initiated Form of Regulation Review. The ability to threaten revenue certainty of investments in a contract carriage market is a drastic disincentive to invest at a time when investment is needed the most.
Following the draft determination on the South West Queensland Pipeline, which did not recommend a change in form of regulation, APGA reiterates this recommendation. Despite this decision, the AER still has the ability to commence FoRR on any pipeline, threatening revenue certainty without basis.
AEMO, Australia’s energy market operator, operates the East Coast Gas Market, the Declared Transmission System and Wholesale Gas Market in Victoria, the Gas Supply Hub and Short Term Trading Market, gas retail markets and the Gas Bulletin Boards.
Despite these gas market functions, for a long time AEMO forecasting has operated with a focus on electricity markets. This is due to its function under the National Electricity Laws to undertake the biennial Integrated Systems Plan (ISP) process, which requires it to establish a plan for “the long term interests of the consumers of electricity” – not consumers of gas or, indeed, for energy consumers as a whole.
The electricity focus of the ISP is legislated, and AEMO has been prevented from including its broader gas market insights in the ISP. This is in spite of the close interaction of gas and electricity markets, and the fact that operation of gas markets ultimately impacts electricity networks and hence the quality of long term forecasting.
Recent proposed changes to the energy laws[13] to better integrate gas into the ISP will enable and require AEMO to consider gas markets in its forecasting for the ISP, which is a positive step. But there is also a risk that this will set up AEMO as a kingmaker for gas investments, in the same way it is for electricity markets. This would be inappropriate for the contract carriage gas supply and infrastructure markets.
More appropriately, AEMO should be required to consider the best interests of gas customers in delivering the ISP. As identified under the NGL section above, this could be achieved by simply expanding the NEO to consider the best interests of energy customers, rather than the best interests of electricity customers. To reiterate, this was the original drafting of the most recent NEO amendments but was changed between drafting and implementation.
Industry is also concerned about the capacity of AEMO genuinely act in the interests of gas consumers. AEMO was recently given additional powers to direct gas, following the 2022 gas crisis. The stakeholder consultation on these powers was ‘expedited’ and overlapping, with industry required to consider and respond to considerable and complex changes in the operation of the market in a very short timeframe. For example, industry was unable to review the implementation of East Coast Gas System Guidelines in advance of providing feedback on the East Coast Gas System Procedures, and was given just 15 business days to respond to both. This may have hampered the quality of responses to that consultation process, even though it is clear that these will have been produced in tandem.[14]
The effect of this rushed consultation is clear in the fact that the AEMC rule change requests for the final items in this package of reforms are still pending. APGA understands that AEMO is still trying to find ways to make these proposals workable, following – or in spite of – industry feedback.
This is not entirely AEMO’s fault. Energy Ministers requested that these changes be in place prior to the winter season of 2023. But the result of limited engagement with industry, and the limited fashion in which industry feedback has been taken into account, does not spell well for the ability of AEMO to produce an ISP that genuinely represents energy markets as a whole – including gas markets.
ECA notionally represents residential and small business energy consumers, and champions agency for those consumers in making decisions about their energy use.[15] This includes gas customers. However, the national focus on electrification as the sole solution to gas decarbonisation appears to have influenced the way ECA approaches the issue of the energy transition, and all matters in fact, when it comes to gas customers.
This is exemplified in CSIRO analysis commissioned by ECA in which alternatives to electrification are ruled out of scope.[16] This analysis is referenced as proof that electrification is the best pathway for gas customers to decarbonise despite not genuinely analysing alternatives. APGA has engaged with ECA on analysis showing that renewable gases are a lower cost decarbonisation alternative to electrification for a majority of residential customers.[17]
This electrification only focus appears to have turned ECA away from supporting the best interests of gas customers. This includes silence on the following encroachments on gas customer rights:
Not investigating all gas decarbonisation options has led to ECA providing insufficient support for current residential and small business gas customers. APGA does not believe that this is aligned with ECA’s remit. APGA has been engaging with ECA on these topics.
State regulators are responsible for safety regulations applying to the gas industry, and APGA generally applauds their approach to open and collaborative consultation.
State governments when designing policy can occasionally be nonresponsive to industry feedback. APGA provides three examples where this can lead to suboptimal outcomes:
The national focus on electrification in the energy transition has led to a lack of cross supply chain consideration. The only answer is, apparently, high voltage electricity transmission lines where it may be in the better interests of landholders to have pipelines rather than powerlines across their land. Pipeline constructors and operates have demonstrated excellent working relationships with landholders and best-practice stakeholder engagement, which may mitigate some of the issues facing consumer sentiment of the energy transition. Pipelines have several advantages over above- and below-ground electricity transmission infrastructure.[21]
DCCEEW is omitted from consideration in the terms of reference. This is an oversight given the Department have driven much of the problematic reform in the gas space, including those which have gone through the Energy and Climate Ministers Council. DCCEEW therefore ultimately has a significant impact on energy planning and regulation in Australia.
APGA’s observations for other areas above can equally be applied to DCCEEW. This includes its clear electrification focus which clouds the possibility of a dual pathway in the energy transition, and failure to adequately consider stakeholder feedback on proposals.
[1] DCCEEW, 2024, Australian Energy Update 2024, Figure 3, https://www.energy.gov.au/sites/default/files/2024-08/australian_energy_update_2024.pdf
[2] APGA, Climate Statement, available at: https://apga.org.au/apga-climate-statement
[3] ACIL Allen, 2024, Renewable Gas Target – Delivering lower cost decarbonisation for gas customers and the Australian economy, https://apga.org.au/renewable-gas-target
[4] Future Fuels CRC: https://www.futurefuelscrc.com/
[5] These are described in further detail in Appendix 1 of APGA, 2023, Submission: Reliability and Supply Adequacy Framework for the East Coast Gas Market, https://apga.org.au/submissions/reliability-and-supply-adequacy-framework-for-the-east-coast-gas-market
[6] DCCEEW, 2023, Incorporating an emissions reduction objective into the national energy objectives, https://www.energy.gov.au/energy-and-climate-change-ministerial-council/working-groups/energy-governance-working-group/incorporating-emissions-reduction-objective-national-energy-objectives
[7] DCCEEW, 2022, Incorporating an emissions reduction objective into the national energy objectives: Consultation Paper, https://www.energy.gov.au/sites/default/files/2022-12/ESOM%20OOS%20Nov%2022%20ATT%20B%28a%29%20-%20Consultation%20paper%20-%20incorporating%20an%20emissions%20reduction%20objective%20in%20the%20national%20energy%20objectives.pdf
[8] DCCEEW, 2023, Incorporating an emissions reduction objective into the national energy objectives: Information paper, https://www.energy.gov.au/sites/default/files/2023-06/Incorporating%20an%20emissions%20reduction%20objective%20into%20the%20national%20energy%20objectives%20-%20Information%20Paper.pdf
[9] Although may be partly addressed in a rule change request currently before the AEMC - see AEMC, 2024, Better integrating gas and community sentiment into the ISP, https://www.aemc.gov.au/rule-changes/better-integrating-gas-and-community-sentiment-isp
[10] DCCEEW, 2023, Extending the national gas regulatory framework to hydrogen and renewable gases, https://www.energy.gov.au/energy-and-climate-change-ministerial-council/working-groups/gas-working-group/gas/extending-national-gas-regulatory-framework-hydrogen-and-renewable-gases
[11] APGA, 2024, Submission: Form of Regulation Review for the South West Queensland Pipeline, https://apga.org.au/submissions/form-of-regulation-review-for-the-south-west-queensland-pipeline
[12] Williams P, 2024, ‘Pipeline review puts APA Queensland gas expansion on hold’, The Australian, https://www.theaustralian.com.au/business/mining-energy/pipeline-review-puts-apa-queensland-gas-expansion-on-hold/news-story/89df761e57df23a4d6bbadf50bc82d1c
[13] AEMC, 2024, Better integrating gas and community sentiment into the ISP, https://www.aemc.gov.au/rule-changes/better-integrating-gas-and-community-sentiment-isp
[14] APGA, 2023, Submission: Reliability and Supply Adequacy Framework for the East Coast Gas Market, https://apga.org.au/submissions/reliability-and-supply-adequacy-framework-for-the-east-coast-gas-market
[15]Energy Consumers Australia, 2024, 3 Year Plan, https://energyconsumersaustralia.com.au/wp-content/uploads/website-doc-3-year-plan-eca-lores.pdf
[16] Energy Consumers Australia, 2023, Stepping Up: A smoother pathway to decarbonising homes, https://energyconsumersaustralia.com.au/publications/stepping-up
[17] ACIL Allen, 2024, Renewable Gas Target: Delivering lower cost decarbonisation for gas customers and the Australian economy, https://apga.org.au/renewable-gas-target
[18] ACT Government, 2023, Preventing new gas network connections, https://www.climatechoices.act.gov.au/energy/canberras-electrification-pathway/preventing-new-gas-network-connections
[19] ACT Government, 2024, Regulation to prevent new fossil fuel gas network connections fact sheet, https://www.climatechoices.act.gov.au/__data/assets/pdf_file/0010/2334358/FACTSHEET_General_Regulation-to-prevent-new-fossil-fuel-gas-network-connections_WEB.pdf
[20] Most recently APGA, 2024, NSW Renewable Fuels Strategy, https://apga.org.au/submissions/nsw-renewable-fuels-strategy
[21] APGA, 2023, Submission: Inquiry into the feasibility of undergrounding electricity transmission infrastructure for renewable energy projects, https://apga.org.au/submissions/inquiry-into-the-feasibility-of-undergrounding-transmission-infrastructure-for-renewable-energy-projects