12 May 2023

Submission: Mandatory Gas Code of Conduct

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 the safe and reliable delivery of 28 per cent of the end-use energy consumed in Australia and are at the forefront of Australia’s renewable gas industry, helping achieve net-zero as quickly and affordably as possible.

APGA welcomes the opportunity to provide comments on the proposed Mandatory Gas Code of Conduct (the Code). The amended Code proposed in this consultation improves upon the original proposal by stepping back from a regulated rate of return. However, it still increases revenue risk for gas producers, in turn increasing supply risk for gas customers.

APGA highlights the following in its submission:

• The Code exposes customers to increased gas supply risk and risk of higher gas prices in the long-term; and
• Retrospective analysis shows the basis of the Code may not align with the cause of the 2020 gas price crisis, indicating a need to reconsider design in light of new data.

To address these concerns, APGA recommends:

• Introduction of an automatic greenfield exemption;
• Introduction of a materiality threshold for reporting requirements; and
• Increase certainty around how the Code will change in the future; and
• Pause Code development until a study into the 2022 gas price crisis can be pursued; and
• A Regulatory Impact Statement should be pursued prior to implementation of the Code.

To discuss any of the above feedback further, please contact me on +61 422 057 856 or jmccollum@apga.org.au.

Yours Sincerely,

JORDAN MCCOLLUM

National Policy Manager

Australian Pipelines and Gas Association

Gas customers require affordable gas and availability of supply

APGA is pleased to see that the Government recognises the importance of ensuring affordable gas is available to customers over the long term. This recognition is demonstrated in the introduction of an automatic exemption for small producers supplying domestic market, which acknowledges that price capping can negatively impact revenue certainty, and in turn investment in new supply. Negatively impacting new gas supply puts domestic gas customers at greater risk of the supply shortfalls projected by the ACCC and AEMO.

This risk is not without solution, however. Lessons learned in addressing revenue risk for new gas infrastructure under the National Gas Law (NGL) being applicable to economic regulation of the gas as a commodity. Both the revenue risk created by the Code, and the potential to learn lessons from the NGL, are explored in the remainder of this section.

The proposed Code will impede access to gas supply

The most recent Gas Statement of Opportunities has acknowledged that gas-powered generation will continue to play an important role in reducing emissions and bolstering electricity reliability as the power system transitions from coal to intermittent renewable generation. Domestic gas consumption is forecast to increase over the short term, requiring additional gas supply so that customers may avoid gas shortages.

Across the medium-term horizon, this new supply will come from a combination of small producers on fringes of current production acreage, and larger producers with new greenfield acreage (such as in the Beetaloo Basin).

While the proposed Code largely avoids direct negative impacts on small producers, particularly those which are operating in existing basins, it would still risk impeding producers seeking to develop greenfield basins. These supply developments are likely to involve complex, multi-stage developments and investment decisions, and as such are likely to be large scale developments, well over the 100PJ/year threshold for conditional exemptions to the price cap.

How does the Code impact investment?

There are several aspects to the proposed Code that will act independently to either increase revenue risk and regulatory burden or increase gas prices accessible by customers.

Asymmetric truncation of returns

Gas producers contract gas at different points in time over the life of a field, rarely all in one big deal. Long-term price caps effectively carve off the top of the price cycle while leaving investors exposed to the bottom of the price cycle. This means that new gas production investment will need to secure higher average prices in the long term to achieve the same rate of return.

This will either lead to higher average gas price to achieve investment hurdle rates in the long term, or the inability to achieve the required rate of return to secure final investment decision (FID), preventing investment in new supply.

Revenue uncertainty

The Code contemplates price caps will continue with no certainty beyond 1 July 2025. This provides certainty that there will be price caps, not what the value of the cap will be. This reduces revenue certainty over the life of an investment, in turn increasing hurdle rates required to achieve FID. Price uncertainty leads again to higher gas prices in the medium term or impeded revenue certainty.

Exemption uncertainty

The proposed Code introduces broad a broad Ministerial exemption process. While this is appropriate given the nature of the industry and complexity of investments, it does introduce uncertainty whereby there are no specific criteria for exemptions other than satisfying the administering Minister, the Industry Minister and the ACCC that the exemption is warranted. This also introduces a ‘many Ministers’ problem, where this agreement relies on the disposition of those Ministers and indeed on the disposition of the government of the day.

This takes the gas market away from being a competitive market and towards being a market in which the producers with the best ability to lobby ministers win the right to produce gas. Without decision making frameworks, leaving exemptions at the discretion of Ministers leaves little regulatory certainty, and is counter to the Code’s stated focus on increasing liquidity in the gas market.

Cost burden of reporting obligations

Reporting obligations can be a considerable the cost burden for small producers. APGA has previously highlighted in our comments on the Gas Wholesale Market Monitoring and Reporting reform[1] and the Pipeline Information Disclosure reform[2] that the additional cost and compliance burdens risk impeding the development of new gas supply. This is also counter to the Code’s stated focus on increasing liquidity in the gas market.

APGA Recommendations

APGA raises three Recommendations to mitigate the above concerns based upon lessons learned from decades of economic regulatory impacts on the gas infrastructure industry:

• An automatic greenfield exemption;
• A materiality threshold for reporting requirements; and
• Increase certainty around how the Code will change in the future.

Recommendation 1 – Automatic greenfield exemption

The negative impacts of asymmetric truncation or returns and revenue uncertainty have been recognised and addressed within the NGL as it applies to gas pipelines. The Code introduces equivalent negative impacts upon gas producers. Taking the lesson learned through implementation of the Greenfield Incentive and Price Protection Mechanism for greenfield gas pipelines, APGA recommends the Code include greenfield gas production investments under its automatic exemption regime.

Under the Greenfield Incentive pipeline projects receive protection from the harsher forms of economic regulation for up to 15 years of the life of the asset. Further, the price protection mechanism protects foundation prices for pipelines developed via a workably competitive process. These legislated protections demonstrate that the negative impact on investment of asymmetric truncation or returns and revenue uncertainty are real and require mitigation.

Recommendation 2 - Materiality threshold for reporting requirement

The National Gas Rules (NGR) consistently applies a materiality threshold for a range of reporting obligations of 10TJ/day capacity for gas facilities, including production facilities. This approach is reflected in National Electricity Law and Rules and the AEMC’s recommendations for extending the existing regulatory frameworks to hydrogen and other renewable gases.[3]

APGA recommends introducing a consistent reporting materiality threshold of no less than 10TJ/day should apply to all recordkeeping and reporting obligations in Part 6 of the Code. This would address many of the concerns about the burden of reporting compliance and potential duplication raised within APGA’s submission.

Recommendation 3 – Provide certainty about key aspects of the Code

In order to minimise revenue and exemption uncertainty the Code must provide greater clarity around how the Code will change in the future. In particular, certainty around an end date and basis for ministerial approval of exemptions require specific attention.

APGA observes in comparison that the price cap on coal, implemented in December 2022 for 12 months, does not appear to be likely to be extended. It is unclear what difference there is between gas and coal prices, or the price of any commodity, that warrants different approaches to price caping considering current cost of living concerns.

Justification for the Code – benefit of hindsight

The Consultation Paper notes that the creation of the Code was intended to avert “the worst impacts of predicted energy price spikes caused by Russia’s illegal invasion of Ukraine and the consequent pressure on global energy markets”. The central objective is to facilitate “a well-functioning domestic east coast gas market with adequate supply at reasonable prices and on reasonable terms for both producers and consumers.”

This justification was derived during the 2022 gas price crisis at a time where not all facts were on the table. With the benefit of hindsight, APGA notes that the problem statement used to justify the code does not reflect what can be observed as having caused the 2022 gas price crisis. On this basis, APGA proposes that Energy Ministers reconsider whether the current design of the Code still reflects what gas customers need to avoid high gas prices and unavailability of gas supply in the medium term.

Correlation between gas, electricity, and LNG prices

Justification for the Code was founded upon the notion of local gas price spikes being the result of international gas prices. This is central to the design and introduction of the interim $12/GJ price cap and the Code. However, reviewing the data in hindsight demonstrates that this may not be entirely accurate.

Questions about this foundation are raised through analysis of time series data for the Japan Korea Market LNG Price Assessment (JKM) netback to the Wallumbilla Gas Supply Hub (WGSH), the WGSH volume weighted average (VWA) price, Sydney and Brisbane short-term trading market (STTM) gas prices, and NSW and QLD National Electricity Market average prices (Figure 1).

Analysis of this data found that domestic gas prices demonstrate significantly greater correlation with NEM prices than with JKM netback (Figure 1). The domestic gas price spike which triggered government intervention directly correlates with a spike in NEM prices and a drop in JKM netback price. Further, increased JKM netback price does not align with the start of the war in Ukraine, and domestic gas price reductions correlate with reductions in NEM price rather than introduction of the price cap.

Analysis by EnergyQuest[4] has identified a strong statistical correlation between domestic gas prices and their respective NEM average prices – R=0.93 in NSW and R=0.94 in Queensland – compared to a weaker R=0.53 correlation between the JKM and WGSH.

Also shown in Figure 1 is a window of substantial unplanned coal-fired generation outages where nearly 25 per cent of coal generation was offline in the NEM. Price increases in the NEM correlate strongly with this period in which four of the NEM’s five largest coal fired power generators were unable to operate at capacity as seen in Figure 2.[5] During this period, gas power generation was leveraged to keep the lights on, explaining the correlation between high gas prices and this window of coal-fired generation outages.

Figure 1: International LNG, domestic spot gas and electricity prices, December 2018-March 2023

Sources: ACCC LNG netback price series; AEMO STTM quarterly prices (smoothed); AER WGSH VWA prices; AEMO NEM averages; APGA analysis

Figure 2: Coal fired power outages analysis by the Australian Financial Review

Conclusion and recommendations

APGA proposes the Code be paused until a study and a Regulatory Impact Statement be undertaken to ensure that the Code will adequately address the causes of the 2022 gas price crisis and deliver a positive impact to Australia.

Recommendation 4 – Study

Considering this analysis, the justification for the Code may not be aligned with the cause of the 2022 gas price crisis. This warrants investigation prior to implementing the Code noting the additional risk of gas supply shortfall which the Code introduces for gas customers.

APGA recommends Energy Ministers commission a study into the events surrounding the 2022 gas crisis prior to implementing the Code. Code implementation should be paused to allow for analysis to ensure that Code delivers the best possible outcome for customers reflecting the causes of the 2022 crisis.

Consideration of lessons learned in this context may also be of benefit for the coming decade as coal-power generation withdraws from the NEM.

Recommendation 5 – Regulatory Impact Statement

APGA also notes that there has not been a Regulatory Impact Statement performed for the Code. The Federal Government has not prepared a Regulatory Impact Statement for other recent gas market reforms as well, including the Gas Wholesale Market Monitoring and Reporting framework and the East Coast Gas System reforms. This is a concerning pattern.

We urge that Regulatory Impact Statements or Policy Impact Analyses be undertaken for any future reforms.

Consultation questions

[1] APGA, 2023, Submission: Gas Wholesale Market Monitoring and Reporting reform, https://www.apga.org.au/sites/default/files/uploaded-content/field_f_content_file/230504_apga_submission_-_aer_gas_wholesale_mmr.pdf

[2] APGA, 2023, Submission: Pipeline Information Disclosure reforms, https://www.apga.org.au/sites/default/files/uploaded-content/field_f_content_file/230509_apga_submission_-_aer_pipeline_disclosure.pdf

[3] AEMC, 2022, Review into extending the regulatory frameworks to hydrogen and renewable gases, https://www.aemc.gov.au/sites/default/files/2022-11/Hydrogen%20and%20Renewable%20Gas%20Review%20-%20Final%20Rules%20Report.pdf

[4] EnergyQuest, 2023, Projecting the long and short-term domestic price outlook: presentation to the 2023 Australian Domestic Gas Outlook Conference, https://www.energyquest.com.au/energyquest-presentation-to-2023-adgo/

[5] Packham et al, 2022, ‘Nearly 25pc of coal capacity remains offline despite energy crunch’, Australian Financial Review, available at https://www.afr.com/companies/energy/nearly-25pc-of-coal-capacity-remains-offline-despite-energy-crunch-20220606-p5argd