GAS FIRED RECOVERY PLAN

The Australian Pipelines and Gas Association (APGA) welcomes the opportunity to comment on the Gas Fired Recovery Plan.

 APGA is the industry body representing the owners, operators, designers, constructors and service providers of Australia’s high-pressure gas transmission infrastructure. Australia has around 41,000km of high-pressure pipelines, with a replacement value of over $50 billion.

APGA welcomes the government’s initiative to help drive the economic recovery through a private investment-led effort to deliver more gas where it is needed at an internationally competitive price. The main focus of our submission will be the National Gas Infrastructure Plan (NGIP) and efforts to boost the gas transportation network.

Merits of gas infrastructure

 Natural gas is a critical part of Australia’s energy and manufacturing prosperity mix, providing more end-use energy to the Australian economy than electricity, with 979 PJ gas delivered to Australian end-users vs. 846 PJ electricity in 2018-19 (Australian Energy Update 2020). However, the role of gas is much deeper than that.

The investment made by pipeline companies supports gas supply, electricity generation, industrial manufacturing and residential use for all Australians. Gaseous energy is used as high-quality heat across all economic activities. Pipeline investment is critical to securing new and competitive sources of gas supply and bringing it to domestic markets efficiently.

A key attribute of gas as an energy source is its reliability – pipeline delivered gas can be supplied to Australian users on a long-term basis without interruption.

Natural gas is a low-emission fuel. The carbon intensity of direct burn natural gas is 51.4 kg CO² equivalent per GJ^([1]) (185 kg per MW/h), whereas the average carbon intensity of the NEM in 2020 was around 197.5 kg CO² equivalent GJ^([2]) (711 kg per MWh).

Table 1: CO₂ Equivalent Intensity – Direct Combustion Natural Gas vs Electricity Grid (NEM)

Data Source: AEMO

Further, its suitability to provide cost-effective low-emission grid firming electricity supports increasing levels of variable renewable power generation and therefore electricity’s decarbonisation pathway.

Natural gas transmission and distribution infrastructure also has its own decarbonisation pathway – with the potential to deliver even lower (or zero) carbon energy through hydrogen, biomethane and other future fuels.

In terms of pricing, direct burn gas is priced more competitively than electricity – with the delivered price of gas for C&I users standing at just over one-quarter the equivalent electricity price. For example, the delivered price for gas supplied to C&I users in Victoria is around $11 per GJ[3] - equivalent (in terms of units of energy delivered) to an electricity price of around $39 per MW/h. However, the delivered price of grid sourced electricity in Victoria is closer to $137 per MW/h[4].

Gas infrastructure is highly cost-effective, with an estimated 4-to-10 times more energy delivered for equivalent capital spend. The gas transmission and distribution pipeline networks are also a substantial store of energy.

Finally, gas infrastructure is extremely safe – companies in the Australian natural gas business have an excellent track record when it comes to safety. This is illustrated by the fact there has never been a fatality due to loss of containment on a gas pipeline in Australia. In fact, Australian gas infrastructure has far better safety outcomes than many of its international counterparts, but this is not well known as recent reviews have only focused on comparing prices.

The combination of competitive pricing, reliability of supply, unique ability to meet specific technical requirements of some manufacturing processes and ability to contribute to the transition to a lower carbon energy system, means that gas will continue to play a pivotal role over the long-term.

National Gas Infrastructure Plan

APGA is happy to contribute to the development of the NGIP and we share the government’s stated preference for a private sector-led investment approach to gas infrastructure delivery in Australia.

The Australian gas infrastructure market has a demonstrable track-record in delivering new pipeline capacity when and where it is needed. Forecasts of potential gas supply shortfalls in particular regions, such as we see in the 2020 GSOO[5], will only be realised if insufficient infrastructure investment takes place in the intervening years

APGA estimates that over $2.6 billion has been invested in expanding the major pipelines of the East Coast in the last decade. An estimated further $4 billion was invested in the pipelines for the Gladstone LNG projects in the period 2011-2014, and around $3 billion has in greenfield projects focussed on East Coast supply, such as the Northern Gas Pipeline, over the last 5 years. We are not aware of any pipeline constraint that has restricted gas flows or prevented the delivery of contracted gas supply during this period.

In the next five years APGA estimates there is potential for $2 billion to be invested in existing assets and a further $8 billion in competitive greenfield projects.

Upstream investment decisions are key

Accordingly, the timing of gas pipeline infrastructure investment decisions is necessarily dictated by upstream investment in new supply. As has always been the case in the past, future gas pipeline capacity needs will be closely aligned with the development of new resource basins as well as import terminals and emerging sources of renewable gases.

Ability of market to continue to meet demand

When additional gas is made available, the gas infrastructure market has a multitude of solutions to bring more gas to particular markets.

In the short-to-medium term, East Coast transmission grid capacity can be expanded relatively quickly by modifications to existing pipelines such as additional compression. Pipeline extensions and bi-directional capacity are also relatively straightforward ways to address potential short-to medium term supply shortfalls. As long as there are producers, shippers and users willing to sign gas supply and transportation agreements, experience shows that new (greenfield) pipelines and major extensions to existing pipelines can also be approved and constructed relatively quickly.

Also belonging in this category are LNG import terminals, as they can reduce the load on other parts of the network and possibly offset the need for specific pipeline capacity expansions in some places.   APGA is neutral on the idea of LNG import terminals, with the view that these should stand on their own commercial merits. In effect, their implications for transmission pipelines are little different to new gas production facilities.

Projects already committed that will improve gas transmission pipeline capacity and flexibility in the near term (within the GSOO 2023-24 southern supply concerns timeframe) include:

• Expansion of compression capacity at Wallumbilla and Young to add 130 TJ/d of compression capacity at Wallumbilla and a 25TJ/d increase in capacity from the Moomba to Sydney Pipeline into Victoria – to be completed by winter 2021 (APA Group).
• Construction of the $167m, 55km Western Outer Ring Main to strengthen the Victorian Transmission System (APA Group)
• New Northern Goldfields Interconnect – $460m, 580km pipeline connecting the Goldfields Gas Pipeline to APA Group’s Eastern Goldfields network to be operational by mid-2022 (APA Group).

Projects currently under consideration that, if sanctioned, would also improve gas transmission pipeline capacity and flexibility in the near term (within the GSOO 2023-24 southern supply concerns timeframe) include:

• Amadeus to Moomba Gas Pipeline (AGIG).
• New 460km Western Slopes Pipeline to connect the Narrabri Gas Project to the Moomba to Sydney Pipeline (APA Group).
• New Crib Point to Pakenham Pipeline to connect proposed LNG import terminal to the Victorian Transmission System (APA Group).
• 210 TJ/d expansion of pipeline capacity from Wallumbilla to Wilton – FEED for stages 1 and 2 of the planned 3 stage project underway (APA Group).
• Construction of bi-directional capacity and a connection to the proposed LNG import terminal at Port Kembla to the Eastern Gas Pipeline to support over 200TJ of gas from NSW into the Victorian market, while being able to supply up to 485TJ of gas per day to NSW – a 25 percent increase on its current capacity (Jemena).
• Extension of the Eastern Gas Pipeline 185km from Sydney to Newcastle connecting the Hunter Valley to new and emerging sources of gas including import terminals (Jemena).

In the longer term, other proposed projects in the public domain include:

• West East Transcontinental Pipeline connecting Western Australia to the East Coast Gas Grid (APA Group).
• Northern Gas Pipeline extension from the Beetaloo Basin to Wallumbilla (Jemena).
• Galilee and North Bowen Basin pipeline connecting to the Wallumbilla Gas Pipeline at Gladstone (APA Group).

There are many factors that will influence which solutions deliver gas to market. APGA does not believe the NGIP should attempt to identify a priority list for infrastructure. This will simply distort market signals and undermine private sector capacity to advance business development planning to final investment decisions. The NGIP should build on the work of the GSOO to identify potential supply and/or transportation capacity shortfalls and then enable the market to select the most efficient solution to address it. For example, the north-south transportation capacity bottleneck projected in the 2020 GSOO could be addressed by any of the solutions identified in the first two groupings above.

As stated above, APGA’s strong preference is for the market to deliver the gas infrastructure investment needed. This aligns with the government’s stated preference.

Strong competition to invest in gas infrastructure

It is a well-recognised fact that competition to build new pipelines in Australia is fierce. For example, the Northern Gas Pipeline (NGP) process involved 14 expressions of interest, nine initial proposals and four final proposals being considered during the tender process.

Once there is clarity around which basins will be developed and what quantities of new gas will be available for domestic supply, the competition to build connecting pipelines and ship the gas to demand centres will be highly competitive – with a focus on delivering the gas to market at least cost to the consumer.

Connectivity

Another aspect of the transmission grid that should be considered in the NGIP is connectivity. Extensions of existing pipelines and/or interconnectors to other pipelines can improve the flexibility of gas supply around the country and to specific regions as needed.

It is important to include the connectivity aspect of pipeline infrastructure in the NGIP. Although greater connectivity doesn’t necessarily increase overall transportation capacity, the additional flexibility creates more options for gas users and may improve network efficiencies.

The regulatory framework must encourage and support increased investment

A key factor that should not be overlooked when developing the NGIP is that a pro-investment regulatory framework is required to maximise private investment. If the gas-led recovery is to be driven by private investment it is essential that market signals and regulatory settings are right. It is therefore vital that government recognises the role it plays in ensuring a stable policy environment that encourages rather than hinders investment.

Gas transmission pipelines are capital intensive assets with commercial operating lives measured in decades. They are permanently committed to specific geographical locations to connect gas supply and user demand centres and rely on consistent long-term demand for pipeline-delivered gas from customers who, in many cases, have a choice of energy sources and suppliers. Gas infrastructure investors are therefore highly sensitive to long-term risks, including perceived regulatory risks.

A key reform highly relevant to this point is the Strengthening Pipeline Regulation RIS. The RIS includes a range of policy proposals, some of which – if adopted – could lead to heavier-handed regulation and a consequent loss of market flexibility, and a less favourable investment climate resulting in pipelines that are smaller, delayed or simply uneconomic. The importance of avoiding such counter-productive outcomes and retaining strong incentives for pipeline infrastructure investment and maintaining the flexibility and speed of the commercial investment process cannot be over-stated.

APGA’s greenfield exemption proposal – under consideration as part of the Strengthening Pipeline Regulation RIS deliberations – is a key example of how the market can be improved to facilitate new investment.

APGA commissioned a report from Synergies Economic Consulting on Proposed Modified Greenfield Exemption Provisions in the National Gas Law for consideration during the pipeline regulation RIS deliberations. However, it is equally relevant to the NGIP.

The report sets out the economic arguments in support of a modified greenfield exemption to be incorporated in the National Gas Law (NGL) as well as presenting the key design features of such an exemption. This includes a statutory process whereby the regulator must confirm an exemption if certain eligibility criteria are met.

The core feature of APGA’s proposal is a ‘statutory’ greenfield exemption, whereby if a proposed pipeline meets certain eligibility criteria (subject to verification), it will receive the exemption. The role of the regulator in this process will be to facilitate the application of the law; it will have no discretion not to grant the exemption if the eligibility criteria are met.

A copy of the Synergies report on Proposed Modified Greenfield Exemption Provisions in the National Gas Law is attached [ANNEX A].

Other examples of policy areas critical to the investment climate include that Australia’s economic regulatory framework should recognise the distinction between regulated gas pipeline businesses and regulated electricity network businesses. Electricity infrastructure derives revenue from regulator-set market carriage tariffs from all electricity users, whereas pipeline infrastructure operators negotiate bespoke contracts directly with customers using reference tariffs and services as a guide. The systematic risk, investment drivers, financial leverage and market position of regulated gas pipeline businesses are therefore substantially different to their electricity network counterparts – but the regulatory system treats them as if they are the same. It is vital the methodology for estimating the binding rate of return for gas pipeline businesses takes these quantifiable material differences into account.

Gas and electricity face completely different investment environments, commercial markets and operational environments. Gas is a physical commodity whereas electricity is not. Gas can take multiple days to be transported from supply source to the end user while electricity is distributed almost instantaneously from generator to end user. The myriad of differences must be better recognised in Australia’s energy policy and market settings.

It is equally critical to recognise the regulated rates of return are not highly relevant to the returns that are required for unregulated infrastructure investment. Decades-scale timeframe also brings pipeline infrastructure into territory where competition from renewables (e.g., mines opting to use solar) and/or mandatory renewables or carbon reduction targets may challenge viability of natural gas.

Recent reforms

It is worth noting that the gas pipeline sector has already been through a comprehensive series of reforms in recent years. Many of the market impacts are yet to be fully realised.

In response to rapidly changing gas markets and consumer needs, as well as to government reforms, pipeline service providers have already made substantial changes and become more flexible in the way they do business. In current market dynamics, customers are increasingly prioritising flexibility. The pipeline industry has delivered this through shorter-term contracts, tailored services, delivery and receipt point transferability and other modifications while also keeping prices relatively flat.

A critical reform in this regard was the implementation of the Part 23 information disclosure and arbitration framework. The implementation of the Part 23 information disclosure and arbitration framework has been a good news story, resulting in excellent progress improving the market experience for pipeline customers. The commercially-oriented negotiate-arbitrate framework under Part 23 is working well, with plenty of progress still to come.

A key point is that service providers can use the flexibility afforded by this structure to develop bespoke solutions to meet customer needs. There is no such thing as a standard pipeline customer; all have bespoke requirements and unique circumstances, making a flexible approach of utmost importance. This is especially true for customers whose businesses may be struggling to remain viable in current economic conditions and need every bit of flexibility possible throughout their supply chain. The flexibility shown by service providers under Part 23 would not be possible under a less flexible, more regulatory-oriented approach.

Decarbonisation

Another critical factor that should be considered in the NGIP is ‘future fuel’ infrastructure and the decarbonisation agenda. Often overlooked in discussions around energy investment and initiatives to decarbonise the energy system is that ‘electricity’ is not synonymous with ‘energy’.

Gas has a strong role to play in this regard both in terms of the flexibility of gas-fired generation and its capacity to support grid reliability in conjunction with high levels of wind and solar, and its own decarbonisation pathway through the development of future fuels like hydrogen and other ‘green gas’ technologies such as biomethane.

First, this is illustrated by the potential for decarbonised gases such as hydrogen to be transported in the pipeline networks in future – either blended with natural gas or fully replacing it over time. Decarbonisation outcomes will have major implications to how existing gas infrastructure is used and what new infrastructure will be required – and where.

Key to the future value of gas infrastructure is its optionality. Its current value can be leveraged to support decarbonisation at least cost to consumers – no matter what direction the market and electricity and gas innovation leads. There are already a range of demonstration studies underway, and the Future Fuels CRC is also facilitating a wide range of projects in this area. This shows that industry is already making progress – with more commercial options likely as the technology develops further.

A possible future project for the Future Fuels CRC or relevant government agencies could be to develop estimates of the cost of building new transmission pipelines that are ‘hydrogen ready’; plus estimate what retrofitting existing transmission pipelines to transport hydrogen might cost – and what modifications may be required. This type of information will be needed for any NGIP analysis of long-term gas infrastructure needs.

Gas Powered Generation

As Australia seeks to reduce emissions in the electricity sector, it is critical that GPG and gas-fuelled end-use energy receive proper consideration, with realistic forecasts and transparent assumptions; counter to the ISP 2020 forecasts.

APGA commissioned a report from Frontier Economics on the Potential for Gas-Powered Generation to Support Renewables to further advance the evidence-base in this area.

The report’s findings show that gas powered generation can support very high variable renewable electricity systems (those with over 90% renewables penetration) to function reliably at much lower system cost to consumers than they would otherwise. Modelling shows that total NEM system costs are reduced by as much as $7.5 billion per annum (around 36%) when gas powered generation is used to support a NEM sized renewable electricity system.

Gas powered generation provides effective energy storage over periods of weeks and months - much longer time periods than batteries and pumped hydro can provide. This makes gas-powered generation particularly well suited to managing energy requirements during sustained periods of low renewable generation, either due to seasonal weather patterns or prolonged renewable droughts.

Low VRE generation can persist for a long period of time. AEMO projections show renewable droughts can last from days to months. In high-VRE scenarios, investment is required in additional generation or storage capacity to ensure the lights can be kept on during these renewable droughts. The flexible nature of gas-powered generation means it is uniquely placed to provide support to renewable generation, protecting the security and reliability of the electricity system.

The Frontier Economics report models total system costs for two VRE output years (2030 and 2035) indexed against the system costs of a 100% renewable power system each year. The 2030 model doesn’t contain any particularly long periods of low wind output; whereas 2035 features a prolonged wind drought. The models for both years include four scenarios:

• 100% renewables;
• 99% renewables;
• 95% renewables; and
• an optimised high VRE system where the level of gas-powered generation is not stipulated (93% renewables in this model).

In 2030 the inclusion of a small proportion of peaking gas-powered generation reduced system costs by approximately 28% (equating to around $5 billion per annum in cost savings in a NEM sized electricity system). In 2035, the inclusion of a small proportion of gas-powered generation reduced system costs by approximately 36% (equating to around $7.5 billion per annum in cost savings).

This reduction in total resource costs reflects the report’s conclusion that investment in some gas-powered generation enables the system to avoid costly and wasteful overbuilding of renewable generation required to deliver system security to manage renewable drought.

The key point in the context of the GenCost 2020-21 Consultation and the AEMO Draft 2021 Inputs, Assumptions and Scenarios Report is that while gas-powered generation is uniquely placed to provide support to renewable generation, long-term investment modelling will often under-value this insurance role for gas-powered generation. Long-term investment modelling of the type undertaken by AEMO for the ISP tends to model outcomes for typical conditions expected in the electricity market, or average conditions. It is not well-suited to modelling investment decisions for generation or storage assets that earn a return during atypical conditions, such as periods of unexpectedly low VRE output. Modelling these investment decisions typically takes additional modelling and analysis.

A copy of the Frontier Economics report on the Potential for Gas-Powered Generation to Support Renewables is attached [ANNEX B].

Wallumbilla as Australia’s Gas Hub

APGA supports the government’s objective “to deliver an open, transparent and liquid gas trading system to improve gas consumers’ ability to purchase gas at a fair price, and improve investment across the gas market”. However, after comparing existing arrangements at Wallumbilla with the Henry Hub in the United States, we think the development of an Australian Gas Hub is a longer-term goal that will realistically require an incremental approach.

Although Henry Hub and Wallumbilla GSH have some physical similarities, they also have some major differences. See table below for comparison.

Table 2: Henry Hub v. Wallumbilla GSH

Key requirements to create a Henry Hub-style gas trading hub at Wallumbilla are increased liquidity (in terms of number of individual customers) and a fully functioning futures market.

Supporting requirements include: increased gas price transparency and certainty; volume churn’ - where the same molecule is traded – to provide price disclosure; a low-price differential between gas in different pipelines. A standardised, liquid and price transparent physical gas market will in turn lay the foundations for a functioning separate futures market.

Achieving this – and therefore a fully functioning Australian gas hub – will be achieved via a demand led increase in investment across the gas market over time.

If you would like to discuss any of these issues further, please contact me on (02) 6273 0577 or at sdavies@apga.org.au.

Yours sincerely

STEVE DAVIES

Chief Executive Officer

[1] National Greenhouse and Energy Reporting (Measurement) Determination 2008 (Schedule 1)

[2] Calculated using the AEMO Carbon Dioxide Equivalent Intensity Index; Summary Results File 2020. See: https://aemo.com.au/en/energy-systems/electricity/national-electricity-market-nem/market-operations/settlements-and-payments/settlements/carbon-dioxide-equivalent-intensity-index

[3] ACCC Gas Inquiry Report 2017-2025 Interim report, July 2019, Chart 4.5 ‘Cost stacks for Victoria, mass market and C&I’, p.99

[4] ACCC Retail Pricing Inquiry – Final Report, July 2019, Table 18.1 Summary of residential, SME and C&I cost stacks c/kWh for the NEM 2017-18. Wholesale price component updated using volume-weighted average price in Victoria NEM region in Winter 2020 ($62.74 per MW/h). See NEM Regional Volatility and Price tables on AEMO website for average wholesale price information: https://aemo.com.au/en/energy-systems/electricity/national-electricity-market-nem/market-operations/settlements-and-payments/prudentials-and-payments/maximum-credit-limit/nem-regional-volatility-and-price .

[5] “Unless additional southern supply sources are developed, LNG import terminals are progressed, or pipeline limitations are addressed, gas supply restrictions and curtailment of gas-powered generation (GPG) for the National Electricity Market (NEM) may be necessary on peak winter days in southern states from 2024” [2020 Gas Statement of Opportunities, p.3].