Future Gas Strategy: consultation paper

Our ref:
Contact name:
Direct telephone:
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Address: PO Box 21, Emerald QLD 4720
13 November 2023

Future Gas Strategy Taskforce
Department of Industry, Science and Resources
GPO Box 2013
CANBERRA ACT 2601

Email: GasOptions@industry.gov.au

Dear Taskforce

Future Gas Strategy Consultation Paper - Central Highlands Regional Council
Submission

Central Highlands Regional Council (Council) welcomes the release of the Future Gas
Strategy Consultation Paper (Consultation Paper) and thanks the Taskforce for the opportunity to provide input in relation to the Consultation Paper at this early juncture.

Council has outlined its feedback below and trusts that such feedback will be of assistance to the Department in the preparation of the Future Gas Strategy:

1. THE CENTRAL HIGHLANDS

1.1 Context

The Central Highlands Regional Council local government area is located in the heart of the
Bowen Basin and is the gateway to the Galilee Basin.

The Bowen Basin is one of Australia’s largest thermal and metallurgical coal and gas reserves, and is home to 12 operating mines as well as 20 petroleum leases largely within the Bowen Basin Mahalo and Denison Trough gas fields, all in the early phases of development. The Consultation Paper recognises that behind the Northern
Carnarvon/Roebuck natural gas resources, the Bowen and Surat Basin are the next most significant reserves, with the Surat Basin at progressed levels of production and the Bowen
Basin the next natural progression. Indeed, this month the Queensland Government released a new $21 million Frontier Gas Exploration Program to unlock new reserves in the
Bowen and Galilee basins to bring Queensland gas to market sooner in anticipation of the need for Queensland production to increase as southern reserves decline.

1.2 The need for regional transformation

The mining sector currently makes the greatest contribution to the economic output of the region, which at $9.4 billion accounts for 73.67% of total output – the mining sector is also the largest employer within the region, supporting:
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 6,079 jobs which represents 35.72% of total employment within the region (not
including employment within supply chains); and
 Spend of over $790 million on local goods and services (REMPLAN, 2022).

Based on average coal production over the previous seven years, 31% of coal produced in the region is thermal coal and 69% of coal produced in the region is metallurgical (or steel- making) coal (Queensland Government, 2022).

As a result, the Central Highlands region will encounter some economic decline associated with the energy transition related to the phase out of thermal coal fired power stations, however anticipates a much more significant medium to longer term structural change related to a shift from metallurgical coal (due to domestic/international decarbonisation policy or the commercialisation of green steel) and seeks to smooth that impact with transformational opportunities – one such opportunity is the construction of the Bowen Basin
Gas Pipeline, connecting the Bowen Basin gas fields to the Curtis Island LNG facilities, and enabling longer term gas production and export from this region. The Bowen Basin Gas
Pipeline offers a number of opportunities for the Central Highlands, Queensland and national economies and energy mix more broadly:

 Opportunity to support the achievement of Safeguard Mechanism emissions
reduction requirements for metallurgical coal mining: The development of the Bowen
Basin Gas Pipeline in accordance with the recommendation made within the KPMG
Bowen Basin Concept Study will result in the provision of key export infrastructure to
capture coal mine methane (CMM), which includes pre-drainage of SIS gas, open cut
mine operational emissions, ventilation air methane and goaf gas. Delivery of the
infrastructure will help to capture emissions from coal mines, which have a
substantial greenhouse footprint through fugitive emissions, which represent 11-15%
of Queensland’s total emissions – this said in the context of a continued need for
metallurgical coal nationally and internationally. The dual purpose that could be
played by the Bowen Basin Gas Pipeline will be essential in the transition to net zero
and ensuring the viability of the metallurgical coal export industry.

 Provision of a longer-term transformation opportunity: Following exhaustion of the
gas fields (or otherwise cessation of extraction), the Bowen Basin Gas Pipeline
infrastructure could be repurposed for the transport of hydrogen produced in inland
locations to be exported or used for domestic power supply, including through
repurposing coal-fired power station infrastructure in Gladstone to become a
hydrogen power plant. Hydrogen produced inland could potentially utilise coal seam
gas by-product water. Therefore, the infrastructure could support a whole lifecycle,
beyond not only natural gas and set Queensland up with infrastructure to support the
transition to a net-zero emissions economy well into the future.

 Opportunity for the Bowen Basin to play a transformed role in underpinning the
reliability of the electricity market both in Queensland and nationally: The
Queensland Government has recognised that “Gas will continue to play an important
role in underpinning the reliability of the electricity market as Queensland works
towards a 70 per cent renewable energy target by 2032.”

Council recently submitted a project proposal to the Queensland Government Regional
Economic Futures Fund for the construction of the Bowen Basin Gas Pipeline. A copy of that submission together with the KPMG Bowen Basin Study Final Report prepared for the
Queensland Government is attached to this submission.

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1.3 Consultation Paper Question 31: What changes should be made to the
transmission and distribution network to prepare for the changing profile of
gas demand in Australia? What risks and opportunities would this entail?

Council considers that the Bowen Basin Gas Pipeline construction is a significant change required to the transmission and distribution network – the risks and opportunities are well identified in the KPMG Bowen Basin Study Final Report attached above. In addition to those risks and opportunities, it is suggested that there is a need to plan for strategic corridors which maximize economic and community benefit, reduce fragmentation of prime agricultural land and reduce biosecurity risk by co-locating water infrastructure, high voltage transmission infrastructure and telecommunications infrastructure in the same corridor.

1.4 Consultation Paper Question 38. [In relation to the Gas Industry] what actions
will assist workforce retention, upskilling and mobility in your community as
the economy transitions to net zero emissions?

The Central Highlands Region is a highly skilled region in terms of trade qualified workers and has an existing supply chain which can adapt to the increase in gas exploration, and during the operational and construction phases. An expanded TAFE vocational education and training offering within Emerald would ideally position the region as a key regional training centre for gasfields expansion.

In terms of accommodation, the township of Tieri which was originally established as a town to service the Glencore Oaky Creek mine which due to close over the next five years. Tieri is located in close proximity to two proposed alignments for the Bowen Basin Gas Pipeline-
(the recommended and least cost alignments) and has the ability to transition to become a town home to the gas pipeline construction workforce and their families.

2. CONSULTATION QUESTION 26: WHAT OPPORTUNITIES EXIST TO IMPROVE
ENGAGEMENT AND CONSULTATION PROCESSES WITH INDUSTRY?

The Central Highlands has been home to mining operations for some time, however is not a referral agency for petroleum lease applications, and social impact and infrastructure impacts of such leases have a significant impact upon communities. A motion submitted by
Isaac Regional Council to the Local Government Association of Queensland Conference made sensible recommendations in relation to the conditioning and enforcement of social impact assessments and conditions in resource projects which apply equally to the gas sector. Notwithstanding, Council has thus far experienced positive interactions with petroleum companies entering the region, with sound compliance with the notifiable road- use regulatory requirements.

Queensland has been on a long journey in relation to gas exploration, extraction and production, with many learnings out of the Surat Basin. The Gasfields Commission has adapted over time and is developing co-existence frameworks as well as having reviewed and implemented a new governance framework which Council is hopeful will avoid the same issues experienced in the Surat Basin occurring in the Bowen Basin as gas production moves northward.

3. CONSULTATION PAPER QUESTION 29: HOW CAN THE AUSTRALIAN
GOVERNMENT BETTER COMMUNICATE AND PROVIDE MORE
TRANSPARENCY TO LOCAL COMMUNITIES REGARDING CCS PROJECTS?

It is noted that the Consultation Paper identifies that much of the Central Highlands region is highly suitable for carbon capture and storage (CCS) and Council too has recognised this possibility. In addition to the Bowen Basin Gas Pipeline
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submission, Council also recently made a submission to the Queensland Government
Regional Economic Futures Fund for a feasibility study with respect to Carbon Capture and
Storage in the Central Highlands region, seeing this as a potential opportunity for economic diversification in the context of the region’s vulnerability due to its heavy coal reliance.

Council is aware of some concerns on behalf of community in relation to potential impacts of
CCS projects on the Great Artesian Basin which is relied upon as an essential water resource for domestic, agricultural, civic, and industrial use. In Council’s view, further geological and environmental investigation and education in relation to same are required to provide comfort to the community. While investigation is a standard component of environmental assessment processes, education is non-standard and must be considered in addition.

4. THE NEED FOR A FUTURE METALLURGICAL COAL CONSULTATION
STRATEGY

Council commends the Federal Government for beginning this longer term planning process for gas in Australia. Metallurgical coal requires similar planning to help understand future demand and the timeframes for the structural change resulting from changed supply and demand, including as a result of decarbonisation policy both domestically and internationally as well as the commercialisation of green steel. We recommend that the Department, through the Mining Branch & Minerals and Resources Division, in consultation with the
National Transformation Authority, develop a Future Metallurgical Coal strategy.

On behalf of Council, I would like to take this opportunity to thank you for consideration of this submission.

Should you have any queries in relation to this submission, please do not hesitate to contact

Yours faithfully

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Bowen Basin
Concept Study
Final Report

Queensland Government – Department of Resources

2 December 2021
KPMG.com.au
Disclaimer

This report has been prepared as outlined with the Queensland Department of Resources in the
Scope Section of the engagement contract dated 14 June 2021. The services provided in connection with this engagement comprise an advisory engagement, which is not subject to assurance or other standards issued by the Australian Auditing and Assurance Standards Board and, consequently no opinions or conclusions intended to convey assurance have been expressed.

No warranty of completeness, accuracy or reliability is given in relation to the statements and representations made by, and the information and documentation provided by, stakeholders consulted as part of the process.

KPMG have indicated within this report the sources of the information provided. We have not sought to independently verify those sources unless otherwise noted within the report.

KPMG is under no obligation in any circumstance to update this report, in either oral or written form, for events occurring after the report has been issued in final form.

This report is solely for the purpose set out in the Scope Section and for the Queensland
Department of Resources’ information and is not to be used for any purpose not contemplated in the engagement contract or to be distributed to any third party without KPMG’s prior written consent.

This report has been prepared at the request of the Queensland Department of Resources in accordance with the terms of KPMG’s engagement contract dated 14 June 2021. Other than our responsibility to the Queensland Department of Resources, neither KPMG nor any member or employee of KPMG undertakes responsibility arising in any way from reliance placed by a third party on this report. Any reliance placed is that party’s sole responsibility.

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Contents
Executive summary 1
1. Introduction 22
2. Scope of the study 24
3. Australia’s gas resources 29
4. Global & domestic gas price forecasts 31
5. Domestic energy market 44
6. The Bowen Basin 66
7. Bowen Basin production scenarios 90
8. Coal mine methane capture 109
9. Infrastructure options 136
10. Approval requirements 158
11. The most likely scenario 168
12. The role of Government 178
13. Next Steps 185
Appendix A : Glossary 186
Appendix B : Planning and Policy 190
Appendix C : Approval Options 198
Appendix D : CMM treatment for utilisation 202
Appendix E : Socio-demographic baseline 206
Appendix F : Recent Policy Reform 215

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Executive summary
It is anticipated that new upstream sources of gas supply are required from as early as the mid-2020s, to avoid long-term shortfalls in the East Coast Gas and export markets. The Bowen Basin is one of five
‘strategic gas basins’ identified by the Commonwealth Government as part of its Gas Fired Recovery
Plan that may have a key role to play in bridging this supply-demand gap.

Developing the Bowen Basin has the potential to bring more gas to Queensland’s domestic and export markets in addition to making a valuable contribution to Queensland’s transition to a low carbon economy through the more productive use of incidental coal mine gas. If it can be brought to market economically, meaning that its cost of production and transport enables a comparable sale price to competing gas sources, and fulfil supply requirements effectively, it has the potential to help drive
Queensland’s economic prosperity. As such, the Queensland Government’s Department of Resources
(DoR) is investigating the feasibility of further unlocking the Bowen Basin to:

• Help drive Queensland’s community and economic recovery;

• Future proof Queensland’s energy supplies;

• Transition to a low carbon, clean growth economy; and

• Make meaningful progress towards the Government’s targets of 30% reduction in 2005 emissions
by 2030 and zero net emissions by 2050 through Green House Gas (GHG) reduction in the supply
chain.

The investigation into unlocking of the Bowen Basin will occur in stages. The Bowen Basin Concept
Study (Concept Study, the Study) presents the critical first step in understanding the current and future opportunities the Bowen Basin may present in improving the delivery of gas to the domestic and export markets. It has explored options directed at the following objectives:

• Improving surface economic viability of gas production and providing gas to market to deliver shared
benefits for the region and the State as a whole;

• Delivering efficient, multi-user gas transport infrastructure that will unlock gas resources;

• Enhanced commerciality of gas field developments in the Basin;

• Future-proofing gas supplies in Queensland; and

• Better management of incidental coal mine gas.

The purpose of the Concept Study is to ensure that the Queensland Government has the appropriate information to support future decisions on the development of the Bowen Basin. This Concept Study will inform assessment of the economic and technical viability of the development of the Bowen Basin as well as the next steps required to support the development of the Basin.

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The Bowen Basin
The Bowen Basin occupies approximately 60,000 km2, extending from Collinsville in the north to beyond the New South Wales border in the south; it is also overlapped in the southern region by the Surat
Basin. The Basin is home to several types of coal seams which have varying potential for gas. It contains three main Permian coal measures – the Rangal Coal Measures (RCM), the Fort Cooper Coal Measures
(FCM) and the Moranbah Coal Measures (MCM). The RCM are the shallowest seams in the Basin and have been extensively mined for coal along the eastern and western flanks where, typically, the coal miners target coals that are less than 400m in depth. With four major coal measures of economic importance for coal mining, the Bowen Basin contains the State's most significant Permian coals.

Currently, the Bowen Basin has over 40 active coal mines, two gold mines, producing gas fields and a range of gas and coal exploration and appraisal activities. As a result of this activity, the Basin contains a diverse range of key stakeholders from resource companies, government organisations, utilities providers and gas-intensive manufacturing and power generation assets.

Due to the large extents of the Basin and the significant development occurring in the Surat, the focus of this Study was the northern section of the Bowen Basin, from Collinsville in the north to Emerald in the south (Figure 1). This study area is referred to as the Bowen Basin (or the Basin) throughout the
Concept Study.

Figure 1 – Bowen Basin study area
(Source: Department of Resources, Queensland)

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Approach to the Concept Study
Due to the complex dynamics of the Australian East Coast Gas Market (ECGM), and an increasing public focus on security of supply and prices, this Study used a demand-led approach to determining the economic need for a new gas basin development. The Concept Study was founded on eight key focus areas, resulting in outcomes that are supported by evidence, and tested with industry:

1. Understanding future global and local energy markets: An assessment of global energy
demand, in parallel with an understanding of the ECGM supply and its ability to meet demand. This
enabled the development of wholesale gas price scenarios for the ECGM over a 10-year time
horizon, considering a range of demand, supply, and transport scenarios. This assessment informed
the series of potential scenarios for a Bowen Basin development against which the infrastructure
requirements have been assessed.

2. Confirming the need: An assessment of Australia’s gas reserves and alternate sources of supply
to confirm the need and priority of further unlocking of the Bowen Basin.

3. Understanding the resource potential: An assessment of potential gas production volumes from
the Bowen Basin, taking into consideration the level of confidence in available data and uncertainty
levels related to the various individual coal measures in the Bowen Basin to produce gas at
commercial rates.

4. Developing production scenarios: The development of production scenarios determining the
readiness of gas resources in the Bowen Basin to produce in the Study period; a 10-year outlook
and characterising the key challenge areas to be addressed to develop the Basin.

5. Understanding the role of Coal Mine Methane: The quantification of incidental coal mine
methane and identification of potential methods of capture and viability to be utilised.

6. Developing solutions: Identification of the infrastructure required to bring the Bowen Basin
resources to market, focusing primarily on pipelines, as well as considering other options for gas
use. The options analysis also included additional supporting infrastructure (e.g. roads and utilities).
Access to existing infrastructure and enabling utilities will be critical to the relative economic viability
of projects.

7. Identifying impact: An understanding of key contextual factors influencing the activation of the
Bowen Basin, the possible role of government in facilitating the development of the Basin and the
potential impact the development of the Bowen Basin may have on the continued prosperity of the
regions.

8. Defining next steps: Summarising the necessary roles of government, industry and stakeholders,
and defining the logical sequence of next steps to progress the unlocking of the Bowen Basin.

Key findings
The analysis undertaken as part of this Study demonstrates a clear need for the development of additional gas production capacity to supplement the predicted shortfall of gas in the ECGM by the mid-2020s.

Whilst other prospective basins exist and could also be developed to provide gas into the ECGM, based on analysis undertaken as part of this Study, the Bowen Basin is potentially in a prime position to supply the additional gas requirements due to the level of existing infrastructure, existing production and extensive exploration and appraisal activity within the Basin.

The following sections provide an overview of the key findings of this Study.

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1. Understanding future global and local energy markets
Forming a robust view about how the global energy market is expected to evolve over a long-term horizon and identifying a plausible range for the global price of natural gas over the next 30 years is an important requirement when assessing the economic viability of further unlocking the Bowen Basin.
The global energy market analysis guides Australia’s domestic gas price forecasts by providing an anchor price on which a price specific to the Australian local market can be determined.

KPMG-Macro, a global macro-econometric model, has been used to support the analysis. In general, growth in economic activity depends on, among other things, energy prices, which in turn depend on growth in economic activity. In this framework, faster economic growth tends to push up energy prices, which has a dampening effect on growth. In standard applications of KPMG-Macro, the supply side of the energy market is assumed to accommodate demand.

Over a longer horizon, the key drivers of gas demand will be:

• The price of gas relative to the price of substitute fuels (ranging from close substitutes through to
not-so-close substitutes);

• Growth in economic activity, including the regional and industrial composition of growth;

• Technological change driving improvements in energy efficiency. This may be partially driven by
policy settings; and

• Environmental and other policies designed to increase energy efficiency and change the energy
mix.

Over a longer horizon, the key drivers of gas supply will be:

• The anticipated market price of gas; and

• Availability of reserves and the cost of extracting, processing and delivering the fuel to users relative
to other fuel sources.

Central global demand scenario
The central demand scenario is based on KPMG’s current global macroeconomic forecasts for 2021 to
2050. Figure 2 shows KPMG’s projections for real Gross World Product (GWP) to 2050. The main feature of these forecasts is that global growth over the next 30 years is expected to be lower than that recorded in the previous 30 years.

10.0%

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Figure 2 – KPMG-MACRO real Gross World Product forecast, 2021-2050
(Source: KPMG analysis)
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Energy price shocks have disrupted economic activity over history, in some cases leading to recession and major dislocation. However, such shocks are, by their nature, largely unpredictable and temporary in nature. In developing the central demand scenario, KPMG has incorporated key assumptions about the (i) industrial composition of the global economy; (ii) energy intensity of the economy; and (iii) share of fossil fuels in the energy mix. These specific energy market assumptions, together with other assumptions embodied in KPMG’s global macroeconomic forecasts, yield a central case projection for global energy demand. Figure 3 shows an expected increase in global energy demand from
13,295 Mtoe in 2020 to 18,960 Mtoe in 2045 (a 42% increase in aggregate energy demand).

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Figure 3 – Global demand for energy, 1990-2050
(Source: BP & KPMG analysis)

Long run JKM LNG price forecasts
Figure 4 below shows the long run projections for a reference to the real (2020 dollars) Japan Korea
Marker (JKM) price of Liquified Natural Gas (LNG). In the central case, the real JKM price for LNG recovers from USD$4.40 per Mbtu in 2020 to around USD$8.80 per Mbtu in 2022. The price then declines to around USD$5.20 in 2026 before gradually rising to around USD$6.20 in 2050.

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Figure 4 – Projections for the real price of LNG (Japan Korea Marker)
(Source: KPMG analysis)

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Linking global and local energy prices
The linking of the domestic gas market with the international LNG market has altered the market and pricing dynamics affecting the ECGM. Connecting Australian market supply to international buyers of
LNG (which often commands much higher prices) has enabled the economic development of substantial volumes of high-cost Coal Seam Gas (CSG). It has created opportunities for gas producers to sell gas for export, and for gas buyers to purchase gas that would otherwise be exported during periods of lower LNG prices which reduces risk. As a result, the ECGM has become closely linked with the dynamics of Asian LNG markets and their pricing instruments. This expansion of development to unconventional CSG resources incentivised by the prospect of higher prices has also improved the supply horizon for Australian gas which was previously anticipated to deplete faster due to the lower estimates of economically recoverable gas prior to CSG development.

In theory, the LNG netback price is the price at which LNG exporters are indifferent between exporting
LNG and supplying the domestic market as this is the price at which both markets are at parity. An LNG netback price is a measure of an export parity price that a gas supplier can expect to receive for exporting its gas. It is calculated by taking the price that could be received for LNG and subtracting or
‘netting back’ the costs incurred by the supplier to convert the gas to LNG and ship it to the destination port. Domestic gas buyers in the ECGM are increasingly looking to JKM netback pricing as the benchmark for their domestic contracts, and this is also starting to emerge as a favoured benchmark by various levels of the Australian Government when setting domestic gas policy.

KPMG’s forecast long-run real price for LNG (JKM price) in the mid-scenario is USD$6.20/MMBtu, equivalent to AUD$8.35/GJ 1. Using the Australian Competition and Consumer Commission (ACCC) methodology to calculate Netback at Wallumbilla, our expectation is a long-run Wallumbilla Supply
Hub Netback price of approximately AUD$7.00 to AUD$7.50/GJ. Stakeholder consultation confirmed that this netback price point is considered a reasonable middle-point for long term gas prices for the ECGM, under balanced ECGM supply and demand conditions. Where supply is tight, the ECGM prices will be elevated, with the Australian Energy Market Operator’s (AEMO) General Statement of
Opportunities (GSOO) predicting tight supply conditions to persist in the near to medium term.

Volatility will exist in these prices depending on settlement dates for various delivery dates, demand and supply dynamics, short-term market events and other factors. However, using this price point as a guide, it is possible to analyse the economic viability and recoverability of gas from the Bowen Basin using a range of modelling scenarios.

2. Confirming the need
Spread over 14 gas basins, Australia had an estimated 74,992 PJ of 2p reserves and 121,140 PJ of 2C contingent resources in 2019. Three main gas markets have developed around these basins to supply the Australian market:

1. The ECGM;

2. The Northern Gas Market, which was recently linked to the ECGM by means of the Northern Gas
pipeline via Mt Isa from the Northern Territory; and

3. The West Coast Gas Market, which is independent of the others owing to the large distance
between Western Australia’s (predominantly offshore) basins and the Northern and Eastern
Markets.

Existing pipeline infrastructure transports gas from production regions, predominantly Queensland, to the regions of high gas demand such as Sydney, Melbourne and Adelaide. Historically the southern basins, such as the Gippsland, Bass and Otway which supplied these high demand regions, contained

1 Dependent on the exchange rate
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large volumes of gas, which was extracted relatively cheaply, however most of these resources are now approaching end-of-life, or have been depleted by decades of extraction.

This has resulted in the need for additional gas to be supplied from the northern states to the southern states and, in the short-to-medium term future, it is likely that net shortfalls on both a daily and annual basis will begin to be realised. These shortfalls may be as much as 300 to 400TJ/d during peak winter demand periods in southern states, starting from the mid-2020s.

As demonstrated by the analysis undertaken as part of this Study, there is a clear need for the development of additional gas production capacity, either by expanding existing basins, and hence reducing their lifespans, or by developing an additional gas basin to supplement the predicted shortfall of gas in the ECGM. Increasing supplies of gas from northern states into southern states via increased transport capacity and more efficient use of existing capacity is considered a key part of meeting southern demand. In addition, several projects have been announced that propose to supply alternative sources of gas into southern networks, including LNG import terminals, developing other frontier basins (such as the Beetaloo Basin) and developing other upstream gas projects (such as
Narrabri).

Whilst other prospective basins exist and could also be developed to provide gas into the ECGM, based on analysis undertaken as part of this Study, the Bowen Basin is in a prime position to supply the additional gas requirements due to the level of existing infrastructure, existing production and extensive exploration and appraisal activity within the Bowen Basin.

3. Understanding the resource potential
The development scenarios used for this Study have been informed by publicly available data layered with assumptions based on NSAI’s experience of over two decades of technical work in the Bowen
Basin. NSAI started the process by creating well type curve forecasts to represent typical well production over the life of an individual development well in the Bowen Basin.

It is noted that there is a range of coal properties across the Bowen Basin that can affect the production rates of the coals. This Study has attempted to capture the wide range of outcomes with different rates and plateau times using an understanding of what these wells have produced under current conditions as well as what is realistic for future development. As a result, 12 type curves were modelled to incorporate four peak production rates in addition to three plateau periods.

Outlined in Table 1 below are the variables used to generate the well type curves. Each well type curve was built up by combining a selection of each variable, resulting in over 100 individual well type curves being generated. The capex ranges were vetted through stakeholder meetings and agreed that the range represented a reasonable assumption for full development.
Table 1 – Well productivity cases (all variables modelled independently)
(Source: NSAI analysis)

Water Production Total well
Wellhead Well
Well CAPEX Well OPEX Handling Plateau operational
gas price productivity
(AUD) (AUD / mo) Charge Duration life
(AUD$ / GJ) (TJ/d)
(AUD /bbl) (years) (years)
$5.00 / GJ $1 million 0.26 TJ/d 2 years 10 years
$1 / barrel of
$7.00 / GJ $1.5 million $6,000 pcm 0.53 TJ/d 4 years 15 years
water
$9.00 / GJ $2 million 1.06 TJ/d 6 years 20 years

The analysis showed that meaningful volumes of gas can be produced economically in all but the worst cases, where a low gas price ($5.00 / GJ) is combined with a high well CAPEX ($1.5 or $2 million) and low productivity (0.26 TJ / d). Importantly, the overall conclusion from this modelling is that gas

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in the Bowen Basin is considered to be economically recoverable based on reasonable assumptions of cost, revenue, well design and coal geology.

Refer to Table 14 in the body of this report for the detailed results and economic production matrix.

What is included in the gas price?
The gas prices provided in this report are wellhead prices, and do not include transport to Wallumbilla,
as the pipeline route, length, size, capacity, utilisation and contracting model is not known at this
time. Estimates of a potential tariff for transport of gas from the Bowen Basin vary considerably
depending on utilisation of the pipeline, contract durations, volumes and types. A reasonable
estimate of a transport tariff from the Basin to Wallumbilla is in the range of $0.70 to $1.20. At this
concept stage, given the accuracy of forecast prices and the level of unknowns in the commercial
model this pipeline may take, the wellhead price of $7.00/GJ is considered reasonable when
compared against a mid-point range of $7.00 to $7.50/GJ at Wallumbilla, depending on exchange
rates and other factors. A key next step for understanding the potential of the Basin in more detail
would be to develop a detailed commercial model to analyse the potential transport tariff considering
the above variables.

4. Developing production scenarios
The Bowen Basin covers a vast geographic area and the coal measures in the Basin vary considerably, as does the amount and quality of subsurface data (including seismic survey, exploration wells, appraisal wells and production wells).

The Moranbah region to the north has considerable data, with existing CSG production from the
Moranbah Gas Project operated by Arrow Energy.

Whilst a highly active coal mining area, the central Blackwater region (from Moranbah in the north to
Blackwater in the south) has the least amount of subsurface data related to CSG resources.

The southern Mahalo region has been extensively explored, and there are projects advancing to the production stage.

As a result of the combination of varying levels of data (quantity and quality), and the several different coal measures within the Basin, the Bowen Basin production scenarios have been logically split into three main regions (Figure 6) with differing estimates of production as described below and illustrated in Figure 5.

Moranbah region
In the Moranbah region, the modelling indicates that a plateau flow rate of 200 TJ per day can be achieved with drilling and completing 319 wells over the ramp-up phase of development. The well count could include existing wells once prior volume commitments have been fulfilled. To continue the plateau of 200 TJ of gas per day, additional wells are drilled as needed over the next 15 to 20 years, with a peak of 1,059 active wells. It is assumed that 50 TJ of gas per day will be sent to the domestic market in Townsville, and the remaining gas will be transported south via a new pipeline. It is noted that the Moranbah region has several areas available for development with higher production potential than represented with the high case type curve wells, however the production model has been kept purposefully conservative given the concept level of this Study.

Blackwater region
The Blackwater region has the least amount of CSG production and pilot data and is considered to have the highest risk of development; as such, a plateau flow rate of 77 TJ per day has been modelled. The modelling indicates that this target can be achieved with 205 wells drilled and completed starting in
2030. Additional wells are drilled and completed as needed to maintain the 77 TJ of gas per day plateau flow rate over the next 15 to 20 years with a peak of 632 active wells. Delaying a start date until 2030
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allows for further delineation and data gathering in the Blackwater region and provides time to establish a firm gas supply in the Moranbah and Mahalo regions to provide economic support for pipeline investment.

Mahalo region
In the Mahalo region, a plateau flow rate of 180 TJ of gas per day has been estimated. Modelling indicates that this rate can be achieved with drilling and completing 319 wells over the ramp-up phase of development. To continue the plateau of 180 TJ of gas per day, additional wells are drilled as needed over the next 15 to 20 years, with a peak in active wells of 1,158 wells. There are existing wells in the
Mahalo region that could contribute to the total gas volume if prior volume commitments are fulfilled.
The majority of gas volumes from this scenario are available for a pipeline going to southern markets via the ECGM. Similar to the Moranbah region scenario, the Mahalo region also has an area of development that the high-side type curve well could exceed.

The production scenarios modelled have been based on the inputs and assumptions developed through existing knowledge of the Bowen Basin, publicly available data and stakeholder feedback. These result in a number of pathways to economically produce CSG from multiple regions in the Bowen Basin.

300
Mahalo region scenario
• 180TJ/d plateau
250 • 16-year plateau
• 1,158 wells at peak Moranbah region scenario
• 1,378 PJ total production
• 200TJ/d plateau
• 7-year plateau
200 • 1,059 wells at peak
• 1,326PJ total production

150 Mahalo & Blackwater scenario
• 175TJ/d to 250TJ/d
• 1,503 wells at peak
• 1,758PJ total production
100

Blackwater region scenario
50
• 77TJ/d plateau
• 9-year plateau
• 632 wells at peak
0 • 390PJ total production
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2047
2048
2049
2050
2051

Figure 5 – Modelled gas production profiles – all scenarios
(Source: NSAI analysis)

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Moranbah region

Blackwater region

Mahalo region

Figure 6 – Production scenario regions of the Bowen
(Source: NSAI Analysis)

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5. Understanding the role of coal mine methane
The Queensland State of the Environment Report (2020) confirmed that the outlook for gas and coal mining-based fugitive emissions was on the increase, and that fugitive emissions represented a sizeable portion of Queensland’s total emissions (11-15%). The Bowen Basin, which has traditionally focused on coal production, has the potential to bring more gas to Queensland’s domestic and export markets – by opening up areas for new (CSG) gas production and capturing unutilised gas from underground mines. However, due to the marked difference in CSG gas and incidental mine gas quality and its unpredictability, and highly variable flow rate, there are potential barriers to effectively capturing and utilising fugitive emissions.

Data obtained from the Clean Energy Regulator (CER) website indicates that CO2 emissions within the
Basin are highest in the central Moranbah and Middlemount regions, with the largest emitters releasing approximately 7.2mtpa, 3.2mtpa and 2.9mtpa CO2-e for FY19-20. This emission data also provides an indication of which mines have the largest potential for reduction in emissions through utilisation of
Coal Mine Methane (CMM).

CMM refers specifically to methane released from coal seams and surrounding strata either just prior or during coal mining (i.e. mining activities). As the build-up of methane in underground mines can create both an explosive and an asphyxiation hazard for mining operations, the CMM must be removed prior to mining operations for safety reasons, and levels of residual methane in the mine must be kept below safe threshold limits. This is achieved through the use of ventilation systems (i.e. ventilation air methane) and/or dedicated relief systems (i.e. drilled boreholes) for surface treatment and/or dispersion.

There are four types of CMM:

• Pre-drainage or SIS gas, which is pipeline quality gas, similar to commercial CSG. This gas is
produced prior to mining of a particular coal to de-gas it as much as possible and, where possible,
gas is provided to CSG operators in the area to supplement their gas production. However, its yields
depend on the permeability of the coal being drained.

• Open cut mine operational emissions are fugitive emissions from mining operations that occur
due to the release of methane from coal extraction, coal transport, coal handling and size reduction
operations. Similar to underground mining, large volumes of pre-drainage gas are also produced, as
this is the most efficient method of methane removal prior to mining and is necessary to manage
for safety reasons.

• Ventilation Air Methane (VAM) is by its nature predominantly air and is subject to strict quality
controls to ensure the health and safety of mine workers. VAM is therefore not suitable as a
recoverable resource using currently available and commercially viable technology.

• Goaf gas occurs after pre-drainage methods have maximised the removal of in situ gas through
surface or in seam drilling methods. It is generated during longwall cutting or extraction and
principally from the caved gob that remains behind the advancing cutting face. Goaf gas therefore
combines with a portion of ventilation air that is provided to the working air and does not typically
produce gas of high quality for direct use. It therefore requires extra processing before use or can
be utilised in certain energy generation applications.

One major Bowen Basin mine currently produces approximately 40 TJ/d of CMM. An approximate breakdown of the daily coal mine gas production is as follows:

• 9 TJ/d is ventilation air methane (VAM), which is vented directly to atmosphere and cannot be flared
due to low methane concentration (typically less than 0.5%);

• 18 TJ/d is transferred to Arrow (if it meets pipeline specification gas) or to EDL for local power
generation;

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• 2.5-3 TJ/d of very low concentration gas is vented in the field, for safety and operability reasons;
and

• The remaining 10 TJ/d of gas is flared. As methane (CH4) has a GWP100 (Global Warming Potential
over 100 years) of 28, flaring is preferable to venting to reduce the overall greenhouse effect of this
gas.

There are a number of barriers to utilising coal mine gas, meaning other coal mines have not been as successful, with another major mine operator in the Bowen Basin providing the following typical usage of coal mine gas:

• 60-70% is VAM, vented directly to atmosphere; and

• The remainder is flared or vented, although the amount flared instead of vented has increased in
recent years which has reduced GHG impact. Some of this gas is a mix of various products other
than methane which must be separated before use.

Industry’s main challenge to utilising coal mine gas in its current operations is that the quality and production rates of coal mine gas are variable, meaning it is not economic to enter into commercial gas supply agreements. However, the gas could be used more effectively on site, such as using pre-drainage gas to displace diesel usage, which contributes to environmental targets and social licence to operate.

To understand the potential quantity of CMM that could be released in the Bowen Basin, modelling of fugitive emissions from CMM was undertaken as part of this Study. Without development of the Basin and assuming no CMM capture, by 2030, the annual fugitive emissions open cut and underground coal mines in CO2-e is estimated at approximately 29mt of CO2e with a split of:

• 19mt from open cut operations;

• 3.5mt from pre-drainage;

• 1.5mt from goaf gas; and

• 5mt from VAM.

When compared to other components (VAM, Goaf, pre-drainage underground and pre-drainage gas), the largest single source of coal mining GHG emissions are from open cut mine operational fugitive emissions. Typically, the viability of pre-drainage is dependent upon the depth of the mine with open pit mines deeper than 200m being advised to employ pre-drainage during operation. Operational emissions cannot be captured as they are generally emitted during recovery of the coal as overburden is removed and pressures on the coals reduced.

When considering the development of the Basin, forecast fugitive emissions were modelled for all four production scenarios. The modelling indicated that the total emissions are forecast to be below 10Mt
CO2-et over the life of the project.

The fugitive emission modelling indicates that the reduction in fugitive emissions from utilising
CMM capture, even if only a small portion of the total, will far outweigh the GHG emissions impact of developing the Basin as a CSG play. This is largely due to methane having a GWP100 of
28, and hence capturing and combusting it will have a net positive effect on the emissions of the project despite the emissions required to develop the Basin.

Strategies for improved future utilisation, and therefore enablement of production and beneficiation of
CMM, are likely to be crafted around the following key focus areas:

• Overlapping tenements: New frameworks for coal and CSG overlapping tenures must continue
to strive for maximum flexibility for resource authority holders, inclusive of the ability for relevant
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parties to mutually agree on non-regulated arrangements that may fall outside legislative or default
requirements.

• Subsidisation: Power station and/or other gas beneficiation facilities will have a greater chance of
development through participation in emerging or potential future emissions subsidy schemes.

• Transmission Networks: Upgraded transmission systems may encourage or enable larger power
plants and drive common use infrastructure (e.g. gathering and transmission pipelines to centralised
power plants).

• Ventilation air methane: Mines could be incentivised to reduce VAM from established baseline
emissions through either emissions crediting or direct regulation.

• New Markets: New energy supply chains could be considered utilising either CSG and low-quality
gas associated with its production or incidental mine gas that has been treated to suitable quality,
although not necessarily pipeline specification gas.

• Infrastructure: Access to pipelines. One of the most significant barriers to utilising pre-drainage
coal mine gas is access to export pipelines, due to the typical lack of proximal export pipelines, and
the lack of required gas infrastructure to meet pipeline quality and pressure requirements. For these
reasons, it is typically not economic to capture coal mine gas and export it to the commercial
market.

• Gas Quality Requirements: CMM is typically highly variable in quality and flow, hence it can be a
challenge to deliver consistently economic gas to market at suitable quality.

• Emerging Technology: Developing and incorporating the use of emerging technology, such as
membrane separation of methane to improve concentration to useable levels, has the potential to
change the dynamics of CMM utilisation in the Basin.

Traditionally, mine operators have been averse to either investing in new gas processing infrastructure or owning and operating that infrastructure. Generally, mine operators are supportive of power generation and moving surplus energy as “electrons” as opposed to “molecules”. The current business landscape therefore suggests that policy drivers, improvements to the regulatory frameworks and cross sector collaboration from both private and public sector players will be critical to the development of the Bowen Basin gas resources and the reduction of fugitive emissions.

6. Developing solutions

Infrastructure development
The analysis undertaken as part of this Study indicates that the existing infrastructure to ship gas north from Moranbah to Townsville and other regional centres nearby is sufficient to cater for the expected demand in these areas, with little further infrastructure required.

However, with limited existing infrastructure in the central region, combined with large gas resources currently not connected to the ECGM, a new transmission pipeline connection is necessary to meet long-term market requirements. There are several likely options for pipeline routes that could connect the Mahalo, Blackwater and Moranbah regions to the ECGM:

• Routes developed as part of this Study; and

• Routes that have been proposed by industry.

Four routes were developed as part of this Study as illustrated in Figure 7. These routes should only be considered indicative of likely corridors for a pipeline – it is important to understand that this assessment is provided only to: confirm that reasonable pipeline corridors exist; determine the likely length of

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pipelines; enable estimated pipeline diameters and costs to be developed; and provide an understanding of key options in macro-level pipeline routing for the Bowen Basin.

Figure 7 – Identified Pipeline Options
(Source: GHD analysis)

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Identification of a preferred option
The selection of a particular pipeline route from one point to another requires a multi-criteria assessment to optimise the many constraints. Route selection is ultimately an iterative process requiring consultation between landowners, regulatory bodies, pipeline owners, engineers, constructors and other project stakeholders. However, to inform the outcomes of this Study, a Strategic Merit Test (SMT) was undertaken.

The SMT was undertaken using the Government’s objectives for the Basin as part of this Study, with results summarised in Figure 8 below.

Figure 8 – Strategic Merit Test
(Source: KPMG analysis)

Explaining the SMT

Gas to market
Due to the need to service the expected shortfall of gas supplies into the ECGM by the mid-2020s, the assessment was based on connecting the Bowen Basin to the ECGM. Whilst forecasts from AEMO can and do move around with time, given that they are a snapshot of a dynamic market, the overall conclusions from our analysis are that there is a trend of supply/demand gaps emerging beyond the end of this decade, and that more gas is needed based on current demand forecasts.

It is considered that Option 1 would be more effective for export of gas via LNG through its connection to Gladstone. Options 2A, 2B and 3 with a connection to Wallumbilla, would be more effective for supply to the ECGM. However, it is noted that once a connection is made into a pipeline, there are commercial ways to get contractual gas flows to the customer within the ECGM or to LNG export
(location-based gas swaps).

There is a higher capex involved for Option 2B but there is likely a greater upside with more gas being able to access the pipeline (multiuser). Option 2B would be able to capture more of the gas suitable for pipeline injection from the Moranbah, Blackwater and Mahalo regions, when compared to Option 2A.
Option 2A presents a similar opportunity, however, it is expected that it would be more difficult economically to access gas resources in the Blackwater region.

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Unlocking gas resources
The assessment was based on the number of gas permits the pipeline route supports.

When considering the options, Option 1 with a connection to Gladstone does not effectively capture the majority of gas permits in the Basin, supporting only the unlocking of the Moranbah region.
Furthermore, it would require a significant gathering network and large processing facilities in
Moranbah.

Options 2A and 2B with a connection to Wallumbilla support a whole-of-Basin solution, passing close to many existing exploration permits across both the Blackwater and Mahalo regions. Due to the close proximity of the existing exploration permits, these options also require a less significant gathering network, with several smaller processing facilities for local tie-in to the pipeline.

Although Option 3 provides a connection to Wallumbilla from Moranbah, as there are limited mine or petroleum leases between Blackwater and Moura, the southern half of this route is not expected to be as prospective for gas sources as Route Option 2B.

Capturing incidental coal mine gas
Options 2A and 2B run in close proximity to the existing exploration permits and maximise the utility of methane from coal in the Basin, from both mining operations and coal seam gas production. Option 2B provides the closest access to the majority of the prospective resource and is considered the route which maximises the capture of incidental coal mine gas. As described above, the southern half of
Option 3 is due to the limited mine or petroleum leases between Blackwater and Moura.

Due to its alignment, there is limited opportunity for Option 1 to capture incidental coal mine gas.

Supporting regional development
By supporting the development of the whole Basin, Options 2A, 2B and 3 offer a range of regional development opportunities. By only supporting the development of the Blackwater region and its supply of gas predominately to the LNG export market, Option 1 is considered to result in minimal regional development opportunities.

When considering the Government’s objectives for the Basin as part of this Study, based on the above
SMT, Option 2B delivers the greatest alignment to achieving these strategic outcomes.

Table 2 below details the technical parameters of Option 2B.

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Table 2 - Option 2B – To Rolleston (East) gas infrastructure
(Source: GHD Analysis)

Parameter Mahalo Mahalo + Blackwater + Moranbah

375 TJ/d (Mahalo 150 TJ/d + Blackwater 75 TJ/d +
Flowrate 180 TJ/d
Moranbah 150 TJ/d)
~ 1,158 wells & gathering network ~ 2,400 wells & gathering network
2 x new gas processing facilities 4 x new gas processing facilities and MGP
Required
End of line compression (~7 MW) expansion
Infrastructure
DN400, 140 km pipeline operating at 10.2 End of line compression (~ 9MW)
Mpag DN550, 390 km pipeline operating at 10.2 Mpag
Estimated Wells/gathering: $1-1.5M per well Wells/gathering: $1-1.5M per well
Capital Processing facilities: $630M Processing facilities: $1,225M
Expenditure Pipeline: $160M Pipeline: $600M
Development
Timeline 4 years 6 years
(best case)
Would need to oversize initial southern Viability of wells in central Bowen is unknown,
pipeline (to DN550), loop in the future, or pipeline would need to extend to Moranbah for
add additional future compression, to proven resources
Risks
unlock Moranbah. Additional upfront cost Constructability of pipeline route through
on oversized pipeline adds ~40% to Middlemount and Blackwater due to mines
pipeline cost only.

Notes:
1. Compression has only been allowed for at the GPFs and end of line to tie into QGP.
2. Pipeline capacity could be expanded in the future up to 400 TJ/d by adding mainline compressor stations.
3. Of the 200 TJ/d from the Moranbah region as stated in the production scenarios (refer Figure 6), 50 TJ/d has been assumed to be transmitted
North via the NQGP, with the remainder being transmitted via the new pipeline to Gladstone.

Approval pathways
A significant number of environmental and planning approvals are required for major petroleum and gas projects in Queensland to proceed, with the most critical approval being the Environmental Impact
Statement (EIS). An effective and proactive engagement program is also essential to manage approvals and mitigate the potential for approval delays. The complexity of major petroleum and gas projects also requires an effective interface between the proponent, community consultation team, environmental specialists and the engineering teams. This is necessary to manage approvals issues that may arise.

Key approval considerations that have the potential to impact a project schedule, particularly for major petroleum and gas projects in Queensland, are:

• Water; • Stakeholder engagement;
• Land acquisition; • Native Title;
• Overlapping tenure; • Environmental constraints; and
• Coexistence issues; • Environmental offsets.

There is potential for the Queensland Government to designate an infrastructure corridor to fast-track development within the Bowen Basin. This infrastructure corridor would enable not only pipeline development, but utilities development as well as gas, power and water.

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It is considered that the coordination and declaration of a State Development Area (SDA) could also present an avenue to facilitate the establishment of a gas pipeline in the Bowen Basin, however this would need to be considered in the context of the enabling legislation.

7. Identifying impact

Key risks and opportunities
Developing the Bowen Basin will be complex and challenging, but it has the opportunity to improve
Queensland’s productivity, liveability and environmental sustainability. Key to maximising the benefits to Queensland will be converting the challenges to opportunities.

Development of the Bowen Basin could improve the prosperity of Queensland, most notably the regions. The supply of market-competitive economic gas is expected to secure a new revenue stream to replace coal royalties and stimulate industrial development, particularly in the northern regions such as Townsville. This could have flow-on effects through to jobs and economic growth for future generations. However, in order to deliver this, three key barriers have been identified that must be overcome:

• A need to change the current state of play:

o There is a need to increase the appetite to invest for incumbent players.
o Creating a diverse and strong consumer demand for the gas for industry to underwriting a
large-scale development of upstream CSG reserves.
• The Bowen Basin is technically challenging:

o Evidence from existing production and exploration wells demonstrates that the Bowen Basin
coals have lower permeability, are located deeper and are higher pressure than the Surat Basin
coals.
o The use of enhanced recovery techniques, such as hydraulic fracturing, which brings with it a
range of technical, social and environmental risks, may be required.
o Wells also need to target specific coal seam measures to ensure productivity.
o Sufficient reserves need to be certified in a timely manner.
• Navigating a complex stakeholder landscape:

o The Bowen Basin coal measures are shallower on the eastern and western flanks – these
measures are the ones that are being extracted by Queensland’s large coal mining industry.
o Beyond 800m depth, it is difficult to economically extract CSG – meaning that CSG
development in the Bowen Basin will require strong cooperation between CSG proponents and
coal miners.
o Overlapping tenure on the same acreage is possible and presents immense opportunity to
capture coal mine fugitive gas emission, but also introduces complexity.

The role of Government
All tiers of government (Commonwealth, State and Local) will need to play a pivotal role in facilitating the development of the Bowen Basin if it is to maximise its benefits. To facilitate the development of the Bowen Basin to the benefit of all Queenslanders, and in response to stakeholder challenges, three key focus areas for government are starting to emerge:

• Enabling infrastructure: Facilitating, through direct investment, subsidy, or other de-risking
measure, the construction of common infrastructure to enable access to market, delivering
affordable gas supplies, increasing competition, building international competitiveness and
attracting private investment.
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• Supporting zero net emissions by 2050: Leading by example in reducing fugitive emissions,
investing in exploration activities and technology to improve the scientific understanding of
geosciences data needed by industry.

• Growing our regions: Strengthening the regions’ economies by supporting ongoing jobs across
supply chains, industries investing in skills for the development of next generation of workers and
creating new economic opportunities through diversification of the regions’ economic base.
Improving the resilience of Queensland’s regions through investment in community infrastructure.

These focus areas straddle numerous portfolios across all tiers of Government, with numerous initiatives already underway that will inform and influence the development of the Bowen Basin.
However, the unlocking of the Bowen Basin cannot be delivered by Government alone − industry must play their part.

To strengthen the regions’ economy and instil confidence for industry to invest, an agreed narrative on how Queensland will navigate the energy transition, combined with a strategic approach to planning and investment across all tiers of Government and industry, will be required. This approach will ensure that the benefits of individual initiatives across portfolios and industry will be maximised.

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The most likely scenario
There is a demonstrated risk of shortfalls in gas supply which imply a clear need for additional gas
production within Australia to supply the expected shortfall in the ECGM from the mid-2020s. Various
projects and initiatives are slated to address these forecast shortfalls, however no single project is a
solution. As such, there is clear potential for the Bowen Basin to be developed as a new upstream
source of gas that, if connected to the ECGM, would help contribute to closure of the projected supply-
demand gap.
Findings within this Study have identified that there are economically viable scenarios that could unlock
production from the Bowen Basin in volumes that will provide meaningful additional gas supplies to
market at a competitive price. However, to underpin the development of the Basin, the construction
of a new pipeline connecting the Basin to the ECGM will be required - only supporting the smaller play
of shipping gas from Moranbah to northern regional demand centres will not be sufficient to underpin
the development of the entire Basin.
At a netback price point of approximately AUD$7.00 to $7.50 / GJ at Wallumbilla, a number of pathways
to economically produce natural gas from multiple regions in the Basin have been identified. At this
price, it is anticipated with moderate levels of certainty that it will be possible to produce:
• Up to 180TJ/d from the Mahalo region, and a total of approximately 1,200PJ over the field life;
• Up to 80TJ/d from the Blackwater region, and a total of approximately 375PJ over the field life*;
and
• Up to 200TJ/d from the Moranbah region, and a total of approximately 1,200PJ over the field life.
* A lack of exploration and appraisal data specific to CSG production in the Blackwater region means this figure
is purposefully conservative pending further exploration based on the geographic and geophysical nature of the
region.

It is anticipated (based on forecasts and the assumptions and findings contained within this report)
that these production levels will be supported by a staged development of a pipeline, with the first
stage connecting the Mahalo region to Wallumbilla, and a future extension from Mahalo to Moranbah.
This staged approach has the benefit of supplying gas into the ECGM with less upfront capital
investment required, creating confidence for industry to invest and providing time for the certification
of sufficient reserves in the Blackwater region. Option 2B achieves a higher utility of CSG resources
and pre-drainage CMM from coal mines in the Basin than would otherwise not be realised, as it
provides the closest access to the majority of both of these prospective resources. However, further
investigation into the constructability of the pipeline through mining operations and leases needs to be
undertaken.
Getting the timing right for the development of the Basin will largely determine the resulting benefits
to Queensland. There are many factors that need to be considered from a timing perspective, however
an overriding factor is the forecast supply shortage in the ECGM. This implies that, for a pipeline to be
able to supply the market, the pipeline development would likely need to take Final Investment
Decisions (FID) by late 2023. Additionally, there would need to have been sufficient development of
reserves through exploration to de-risk the FID such that there is confidence in upstream economic
reserves instead of estimated resources that would underpin a large investment in a pipeline.
The analysis undertaken as part of this Study indicates that the ‘best case’ timeline for a material
increase in gas production in the Basin is approximately five years, however historical Basin
development and industry feedback indicate that the most likely timeframe for development of the
Basin is seven years.
With any pipeline asset development, the timing, configuration, and routing of the Bowen Basin
pipeline will be dependent on which party or parties take the commercial risk to invest into the asset.
A key role for the Queensland Government in subsequent phases of the development of the
Bowen Basin is to clearly articulate to industry their objectives for the development of the Basin
and measures to help mitigate risks in the construction of the pipeline.
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8. Defining next steps
Embracing the development of the Bowen Basin is expected to help drive Queensland’s economic recovery whilst transitioning to a low carbon, clean growth economy. The development of the Bowen
Basin will impact and provide benefits across all tiers of government and many portfolios, and this Study has demonstrated the criticality of pipeline infrastructure to the further unlocking of the Basin.

However, the unlocking of the Bowen Basin cannot be delivered by government alone; industry must play their part. Therefore, it is recommended that the proposed next step for the Bowen Basin is to undertake a Structured Market Engagement process.

Structured Market Engagement Process
To encourage industry participation and create confidence for industry to invest, both the
Commonwealth and Queensland Governments must be an informed leader in the development of the
Basin. Key to testing and refining the role of government in unlocking the Bowen Basin is a Structured
Market Engagement Process with likely market participants and other identified stakeholders.

Key elements of the process could include:

• Identification of market participants: Confirm market participants and key stakeholders to ensure
equal opportunity to all.

• Refining the potential role for government: Build upon the current understanding from the
market to clearly identify where government may best play a role in the short to medium term in
supporting industry.

• Testing potential government processes: Test and refine, through market feedback and
collaboration with the Commonwealth Department of Industry, Science, Energy and Resources
(DISER), a commercial model and process for potential government support (financial and/or in-kind)
and roles and responsibilities to support collaborative feasibility development.

• Identifying key thresholds: Identify, in consultation with market participants, key hold points and
thresholds that would need to be satisfied for investment decisions.

• Establishing indicative timetables and cost of development: Establish, in consultation with
market participants, a reasonable timetable, indicative cost for feasibility development and key
milestones therein.

This Study has identified several market participants and some of their drivers. The Structured Market
Engagement Process will build upon this knowledge and would incorporate the more traditional next step of a feasibility study by building an understanding of the commerciality of the pipeline from the market’s perspective. This approach is anticipated to improve private sector confidence in the establishment of the Bowen Basin, resulting in significant time savings.

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1. Introduction
1.1 Background
It is anticipated that new upstream sources of gas supply are required over the long term, from as early as the mid-2020s, to avoid shortfalls in the East Coast Gas and export markets. The Bowen Basin is one of five ‘strategic gas basins’ identified by the Commonwealth Government as part of its Gas Fired
Recovery Plan that may have a key role to play in bridging this supply-demand gap.

Developing the Bowen Basin has the potential to bring more gas to Queensland’s domestic and export markets in addition to making a valuable contribution to Queensland’s transition to a low carbon economy through the more productive use of incidental coal mine gas. If it can be brought to market economically, meaning that its cost of production and transport enables a comparable sale price to competing gas sources, and fulfil supply requirements effectively, it has the potential to help drive
Queensland’s economic prosperity. As such, the Queensland Department of Resources (DoR) is investigating the feasibility of further unlocking the Bowen Basin to:

• Help drive Queensland’s community and economic recovery;

• Future proof Queensland’s energy supplies;

• Transition to a low carbon, clean growth economy; and

• Make meaningful progress towards the Government’s targets of 30% reduction in 2005 emissions
by 2030 and zero net emissions by 2050 through Green House Gas (GHG) reduction in the supply
chain.

Investigation into further unlocking of the Bowen Basin will occur in stages. This Concept Study presents the critical first step in understanding the current and future opportunities the Bowen Basin may present in improving the delivery of gas to the domestic and export markets. It will explore options focussed on the following objectives:

• Improving surface economic viability of gas production and providing gas to market to deliver shared
benefits for the region and the State as a whole;

• Delivering efficient, multi-user gas transport infrastructure that will unlock gas resources;

• Enhanced commerciality of gas field developments in the Basin;

• Future-proofing gas supplies in Queensland; and

• Better management of incidental coal mine gas.

1.2 Purpose of this report
The purpose of this report is to ensure that the Queensland Government has the appropriate information to support future decisions on the development of the Bowen Basin. Founded on a robust evidence base, this report will provide a consistent reference point to enable conversations between industry and agencies of Government required to optimise the Basin’s development and community outcomes. This report will establish the economic and technical viability of the development of the
Bowen Basin as well as inform future investigation required to support investment decisions.

The outcomes documented in this report will form an independent clear plan, charting the scenarios and actions to help guide the next stage of development within the Bowen Basin.
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1.3 Report structure
This report is structured as follows:

• Section 2 describes the scope of this Concept Study, including the study area, key inputs and
approach to stakeholder engagement.

• Section 3 provides an overview of Australia’s existing gas resources and infrastructure.

• Section 4 identifies the global energy outlook, providing a summary of key findings from technical
analysis into the price environment for gas and associated products as well as the potential
commercial viability of extraction of these resources.

• Section 5 describes the domestic energy market and assesses the need for the development of
an additional gas basin in Australia. The assessment is underpinned by supply and demand
forecasts and the existing infrastructure supporting the domestic gas market. This assessment, in
combination with the global energy outlook, have informed a series of potential scenarios for Basin
development against which the infrastructure requirements have been prepared.

• Section 6 describes the potential role of the Bowen Basin in meeting the forecast global and
domestic demand for gas resources, including identified challenges and opportunities of the Basin.

• Section 7 details the potential market and production development scenarios identified for the
Bowen Basin. These low, mid and high production scenarios provide a sensitivity check and have
been founded on an independent assessment of the resource potential and recovery of the Bowen
Basin.

• Section 8 quantifies the Bowen Basin’s fugitive emissions and the potential pathways for coal
mine methane capture.

• Section 9 outlines the infrastructure options relating to transport and transmission, potential
common user facilities and other infrastructure as required by industry and timescale.

• Section 10 outlines the potential approval pathways available to facilitate the development of the
Bowen Basin.

• Section 11 identifies the most likely scenario for the development of the Bowen Basin, confirming
the need for the development of the Basin and highlighting the risks and opportunities including
the likely timing.

• Section 12 outlines the potential role of government in facilitating development of the Bowen
Basin.

• Section 13 identifies a suite of next steps for the Queensland Government to consider in
progressing the unlocking of the Bowen Basin.

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2. Scope of the study
2.1 Scope overview
The scope of the Study encompassed the following:

1. An overview and analysis of the supply, demand and price of wholesale gas in the eastern Australian
gas market over the next 10 years (the study period), including demand and supply forecast
scenarios and an exploration of physical and market constraints and influencing factors.

2. An assessment of upstream gas resources in the Bowen Basin to determine their readiness to
produce within the study period, including an outline of booked reserves and resources, and
identification of technical production challenges, infrastructure, financial and commercial and other
barriers to developing the gas resource.

3. Analysis of current and predicted sources of incidental coal mine gas to be captured from coal
mines in the study, including an outline of options to utilise incidental coal mine gas more
productively and the necessary regulatory and market conditions required to facilitate this.

4. An outline of the base-case (most-likely) scenario for developing gas resources in the Bowen Basin.

5. Sensitivity analysis of the base case scenario (i.e. how changes to key assumptions would
materially impact gas supply for the domestic market).

6. A set of options for facilitating the development of gas resources in the Bowen Basin, leveraging
existing Government initiatives such as the Australian Government’s Gas-fired Recovery including,
but not limited to, gas pipeline infrastructure.

7. Recommendations for further analysis in subsequent phases of this project.

2.2 Study area
As illustrated in Figure 9, the Bowen Basin occupies approximately 60,000 km2, extending from
Collinsville in the north to beyond the New South Wales border in the south; it is also overlapped in the southern region by the Surat Basin. The Bowen Basin is home to several types of coal seams which have varying potential for gas. It contains three main Permian coal measures – the Rangal Coal
Measures (RCM), the Fort Cooper Coal Measures (FCM) and the Moranbah Coal Measures (MCM). The
RCM are the shallowest seams in the Bowen Basin and have been extensively mined for coal along the Eastern and Western flanks where the coal is shallowest and typically, coal miners target coals that are less than 400m depth. With four major coal measures of economic importance for coal mining, the
Bowen Basin contains the State's most significant Permian coals.

The Bowen Basin has over 40 active coal mines, two gold mines, producing gas fields and a range of gas and coal exploration and appraisal activities. As a result of this activity, the Basin contains a diverse range of key stakeholders from resource companies, government organisations, utilities providers and gas-intensive manufacturing and power generation assets.

Due to the large extents of the Bowen Basin and the significant development occurring in the Surat, the focus of this Study was the northern section of the Basin, from Collinsville in the north to Emerald in the south, as highlighted in Figure 10. This study area is referred to as the Bowen Basin (or the Basin) throughout this report.

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Figure 9 – Bowen Basin
(Source: Geoscience Australia)

Figure 10 – Study Area
(Source: Department of Resources, Queensland)

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2.3 Approach to the study
To understand if further unlocking of the Bowen Basin is a viable option in supporting Australia’s gas reserves, this Study implemented a demand-led approach. This approach accounted for the complex and variable dynamics of the East Australian Gas Market (ECGM), and an increasing public focus on security of supply and prices. The Study was founded on six key focus areas, resulting in outcomes that are supported by evidence and tested with industry:

1. Understanding future global and local energy markets: An assessment of global energy
demand, in parallel with an understanding of the ECGM supply and its ability to meet demand. This
enabled the development of wholesale gas price scenarios for the ECGM over a 10-year time
horizon, considering a range of demand, supply, and transport scenarios. This assessment informed
the series of potential scenarios for Bowen Basin development against which the infrastructure
requirements have been assessed.

2. Confirming the need: An assessment of Australia’s gas reserves and alternate sources of supply
to confirm the need and priority of further unlocking of the Bowen Basin.

3. Understanding the resource potential: An assessment of potential gas production volumes from
the Bowen Basin, taking into consideration the level of confidence in available data and uncertainty
levels related to the various individual coal measures in the Basin to produce gas at commercial
rates.

4. Developing production scenarios: The development of production scenarios determining the
readiness of gas resources in the Bowen Basin to produce in the Study period; a 10-year outlook
and characterisation of the key challenge areas to be addressed in order to develop the Basin.

5. Understanding the role of Coal Mine Methane: The quantification of incidental coal mine
methane, potential methods of capture and viability to be utilised were also assessed.

6. Developing solutions: Identification of the infrastructure required to bring the Bowen Basin
resources to market, focusing primarily on pipelines, as well as considering other options for gas
use. The options analysis also included additional supporting infrastructure (e.g. roads and utilities).
Access to existing infrastructure and enabling utilities will be critical to the relative economic viability
of projects.

7. Identifying impact: An understanding of key contextual factors influencing the activation of the
Bowen Basin, the possible role of Government in facilitating the development of the Basin and the
potential impact the development of the Bowen Basin may have on the continued prosperity of the
region.

8. Defining next steps: Summarising the necessary roles of Government, industry and stakeholders,
and defining the logical sequence of next steps to progress the unlocking of the Bowen Basin.

Box 1: What do we mean by economic viability of the Bowen Basin?
For the purposes of this Study, economic viability of the Basin was defined as simply the cost of
production and transport to enable a comparable sale price to competing gas sources within
Australia.

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2.4 Understanding the evidence base
2.4.1 Available data on recoverable supply
The assessment of upstream gas resources in the Bowen Basin, including an outline of booked reserves and resources, has been informed by publicly available data. It is noted that significant explorative works have been undertaken by proponents in the study area, however, due to commercial confidentiality reasons, this information has not been used in the formation of the productivity scenarios. In lieu of industry data, testing of the productivity scenarios with industry has formed a critical input into the Study to ensure confidence in the results.

Refer to Section 7.1 for the detailed methodology adopted for the assessment of upstream gas resources.

2.4.2 Industry engagement
Hearing the voice of industry around the likely factors that will influence their investment decisions, both those within and outside of Government control, is critical to ensuring that the Queensland
Government has the information it requires to set appropriate policies and facilitate infrastructure investment that is conducive to accelerating the development of the Bowen Basin.

Over the course of the engagement, key industry stakeholders that have a vested interest in the Bowen
Basin were extensively engaged to gather views and test insights, forecasts and analysis. Figure 11 illustrates the industry stakeholders that have provided input into this Study.

Figure 11 – Key industry stakeholders
(Source: KPMG analysis)

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Industry engagement was undertaken in three phases with a focus on understanding:

• Demand and supply trends;

• Well economics;

• Potential opportunities and how to maximise the benefits;

• How government can help unlock the Basin; and

• Key risks.

Industry engagement throughout the project has resulted in a robust and pragmatic Concept Study with insights being informed by industry feedback. It is anticipated that this approach will enable a strong alignment between both Government and industry on the next steps for the development of the Bowen
Basin.

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3. Australia’s gas resources
3.1 Overview
Spread over 14 gas basins, Australia has large reserves of natural gas with over 116,000 PJ of proved and probable (2P) reserves under the JORC 2 definition, making natural gas Australia’s third largest energy resource. Gas is located within several high-density areas, such as the Carnarvon and
Surat-Bowen Basins which, together, contain more than half of Australia’s reserves.

Australian gas is a variety of wet and dry natural gas, predominantly comprised of methane, much of which is contained within the country’s immense coal seams. As illustrated in Figure 12, three main gas markets have developed around these basins to supply the Australian market:

1. The East Coast Gas Market (ECGM) – refer Section 5 for an outline of the ECGM;

2. The Northern Gas Market, which was recently linked to the ECGM by means of the Northern Gas
pipeline via Mt Isa from the Northern Territory; and

3. The West Coast Gas Market, which is independent of the others owing to the large distance
between Western Australia’s (predominantly offshore) basins and the Northern and Eastern
Markets.

Existing pipeline infrastructure transports gas from production regions, predominantly Queensland, to the regions of high gas demand, such as Sydney, Melbourne and Adelaide. Although historically the southern basins contained large volumes of gas which was extracted relatively cheaply, most of these resources are now approaching depletion or have been depleted by decades of extraction.

Figure 12 - Australian Reserves and Contingent Energy Resources 2019
(Source: Australian Energy Council 2019)

2JORC is the Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves ('the
JORC Code'). It provides a mandatory system for the classification of minerals Exploration Results, Mineral
Resources and Ore Reserves according to the levels of confidence in geological knowledge and technical and economic considerations in public reports.
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3.2 Gas basins reserves
Table 3 identifies Australia’s 14 major gas basins and their proven and probable reserves. Historically, production of gas was centred in the southern basins of Otway & Gippsland, offshore Victoria and South
Australia. In recent years, production from these basins has been in decline as reserves are increasingly depleted, whilst production from Queensland’s Surat and Bowen Basins have been increasing as a result of large Coal Seam Gas (CSG) to Liquefied Natural Gas (LNG) projects in south-west Queensland.
Table 3 – Australia’s gas basins – 2P reserves and 2C resources
(Source: Energy Council of Australia)
2019 2C Contingent Basin development
Basin 2019 2P Reserves (PJ)
Resources (PJ) status
Amadeus 242 208 Production
Bass 175 30 Production – Late Life
Beetaloo 0 6996 Early exploration
Bonaparte 783 17,762 Production
Browse 17,384 18,219 Production
Gunnedah 1,520 1,520 Undeveloped
Carnarvon 50,489 34,930 Production
Galilee N/A N/A Undeveloped
Clarence Moreton 0 2,254 Undeveloped
Cooper 1,040 2,037 Production
Gippsland 2,596 1,658 Production – Late Life
Otway 667 194 Production – Late Life
Perth 848 456 Production
Production (Surat) /
Surat / Bowen 36,982 23,711 Production & Appraisal
(Bowen)
Sydney 14 0 Undeveloped
Total 216,844 109,975

For the Northern Gas Market, the Bonaparte and Browse Basins comprise the largest gas supplies in their market at around 1,000 PJ and 17,000 PJ in 2P reserves respectively. These basins export gas as
LNG to markets in Asia via onshore and offshore LNG liquefaction plants.

The ECGM is comparatively more complex than both the Western and Northern Markets. A number of natural gas basins (Surat/Bowen, Gippsland, Otway, Bass, Cooper and Sydney) provide natural gas to domestic demand centres, as well as LNG for export via liquefaction plants at Gladstone in Queensland.
The ECGM is currently connected by pipelines to basins totalling 38,000 PJ in proven and probable reserves and over 70,000 PJ in estimates and contingent resources.

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4. Global & domestic gas price forecasts
Natural gas is a tradeable commodity and over the longer term, its price will be determined by supply and demand conditions on global markets. Natural gas comes in various forms (e.g., at a basic level wet and dry gas) and competes with other fuel sources (coal, oil, nuclear, renewables etc.). While it is beyond the scope of this Study to consider gas in the context of the spectrum of fossil fuels, it is important to recognise that the prices of fossil fuels, particularly over longer time horizons, are linked because they are highly substitutable. Processing and transportation costs, as well as other technological constraints, introduce wedges between the prices of different hydrocarbons. These wedges are unlikely to change systematically over time unless there is a technological breakthrough that drives low production, processing and transportation costs.

Given that natural gas is a commodity tradeable on world markets, the market price of Australian- extracted gas is expected to converge to real world prices in the long run (the link between global and domestic energy prices is explored in more detail in Section 4.2.1). Forming a robust view about how the global energy market is expected to evolve over a long-run horizon is therefore an important requirement when assessing the economic viability of further unlocking the Bowen Basin.

The purpose of this section of the report is to identify a plausible range for the global price of natural gas over the next 30 years. The global energy market analysis then guides our domestic gas price forecasts by providing an anchor price on which cost-based adjustments can be made to determine a price specific to the local market.

4.1 Forecasting global gas prices
4.1.1 Our approach
This section outlines the approach to developing the demand scenarios. KPMG-Macro, a global macro-econometric model, has been used to support the analysis. Energy is an important input in the global production system. There is a strong relationship between economic growth and energy prices.
Other things being equal, high energy prices increase production costs and slow down economic growth. Energy price shocks have disrupted economic activity over history, in some cases leading to recession and major dislocation. However, such shocks are, by their nature, largely unpredictable and temporary in nature. This analysis focusses on longer-term trends, abstracting from temporary supply or demand shocks in the energy market. This does not mean that the reactions of economies to short-run energy shocks are ignored. Energy shocks make businesses and governments focus on energy security and on energy efficiency, which can result in permanent changes in production technology and in energy supply.

In standard applications of KPMG-Macro, the supply side of the energy market is assumed to accommodate demand. Loosely speaking, growth in economic activity depends on, among other things, energy prices, which in turn depend on growth in economic activity. In this framework, faster economic growth tends to push up energy prices, which has a dampening effect on growth.

Over a longer horizon, the key drivers of gas demand will be:

• The price of gas relative to the price of substitute fuels (ranging from close substitutes through to
not-so-close substitutes);

• Growth in economic activity, including the regional and industrial composition of growth;

• Technological change driving improvements in energy efficiency. This may be partially driven by
policy settings; and

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• Environmental and other policies designed to increase energy efficiency and change the energy
mix.

Over a longer horizon, the key drivers of gas supply will be:

• The anticipated market price of gas; and

• Availability of reserves and the cost of extracting, processing and delivering the fuel to users relative
to other fuel sources.

4.1.2 Energy market backdrop
Energy consumption is analysed through a prism of global growth, including the regional and industrial composition of growth and energy efficiency. We then consider how the energy mix has changed over time, focusing on how the share of fossil fuels in total energy usage has changed over time and how the mix of oil, gas and coal has changed within the fossil fuel bundle. On the supply side, we analyse how proven oil and gas reserves have changed over time and relate to production in various regions to reserves.

The historical analysis provides a useful context for understanding the projections reported below and the key underlying assumptions. The key relevant findings of the historical analysis can be summarised as follows:

• There is a close relationship between energy demand and global growth;

• Global production appears to have become steadily more energy efficient;

• Improvements in energy efficiency appear to have dominated any regional or industrial
compositional changes in determining energy demand;

• Gas and non-fossil fuels have become a larger component of the energy mix over the historical
period;

• Global energy reserves and technologies for commercially accessing these reserves have, together
with the adoption of energy-saving technologies, generally allowed energy supply to accommodate
demand, although there is evidence that over the decade between 2005 and 2015, the rapid growth
in the world economy, and China in particular, put pressure on energy supply and, consequently,
on energy prices;

• Increases in proven reserves of oil and gas, expansion in energy production, as well as energy
transition activities and a saturated marketplace of energy providers, put downward pressure on
energy prices in the years prior to the COVID-19 pandemic;

• Curtailment of global economic activity and mobility during COVID-19 pushed down global energy
demand by 4.3% relative to 2019;

• The global economy has rebounded from depths of the contraction in the middle of 2020, where
world GDP had declined by 7%. This rebound has been stronger than initially contemplated, and
energy prices have followed - with crude oil and natural gas prices both now above their
pre-pandemic levels; and

• The global transition towards renewable energy sources has picked up pace in recent years and has
increasingly become a focus for policy makers. This topic is discussed in greater detail in Box 2
below.

In developing the future demand scenarios for gas demands and prices, views need to be formed about the persistence of the above relationships and trends.

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Box 2: Global Energy Transition
A reduction in carbon dioxide emissions (and their equivalents) of approximately 3-6% per annum
between now and 2050 is needed to limit global warming to 1.5-2°C (World Economic Forum, 2020).
In response to this identified need for a reduction in carbon dioxide emissions, policy makers are
increasingly focusing on transitioning to a carbon neutral future by skewing the energy mix in favour
of renewable energy sources. During the transition period from a global economy reliant on energy
generated by coal and oil to a global economy more reliant on sustainable energy production
methods, natural gas is widely seen as a ‘transition fuel’ which provides higher carbon efficiency
(i.e., less carbon dioxide is emitted per unit of energy output) than other fossil fuels.

As of June 2021, 131 countries have stated their intentions to be carbon neutral by 2050, but only a
few countries have developed robust policies or frameworks to deliver on a net-zero ambition.

Long-term energy demand projections are regularly produced by various players in the energy
market. These long-term energy demand projections vary considerably depending on underlying
assumptions and methodologies, however for all but the most ambitious climate scenarios of those
considered (i.e., BP’s Rapid Transition scenario, Equinor’s Renewal scenario and IEA’s Sustainable
Development scenario), projections show a steady rise in total energy demand out to the year 2040.
It is worth noting that the pace at which energy demand increases over the forecast period has
generally decreased compared to previously produced forecasts, in part due to the widespread
adoption of evolving technological advancements designed to improve energy efficiency.

Global energy demand forecasts considered in Figure 13 below show that demand for coal is
expected to decline (across most scenarios); liquids to grow (across most scenarios); natural gas to
grow (across all scenarios); and renewables growing to rival and, in a small number of scenarios,
surpass fossil fuel sources. The average share of fossils fuels in the energy mix in 2040 across all
scenarios shown in Figure 13 below is 75%, with non-fossil fuels, such as nuclear and renewables,
comprising the remaining 25%. Linearly extrapolated to 2050 (using 2015 and 2040 as reference
points) this figure would be 72%.

Coal Liquids Gas Nuclear Renewables (inc. Hydro)
25,000
2040
Mtoe

20,000

15,000

10,000

5,000

0

Figure 13 – Forecast global primary energy consumption by fuel type
(Source: KPMG analysis)

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4.1.3 Future Demand Scenarios
Central global demand scenario
The central demand scenario is based on KPMG’s current global macroeconomic forecasts for 2021 to
2050. Figure 14 shows KPMG’s projections for real Gross World Product (GWP). The main feature of these forecasts is that global growth over the next 30 years is expected to be lower than that recorded in the previous 30 years.

10.0%

8.0%

6.0%
Annual Growth

4.0%

2.0%

0.0%

-2.0%

-4.0%
1990
1993
1996
1999
2002
2005
2008
2011
2014
2017
2020
2023
2026
2029
2032
2035
2038
2041
2044
2047
2050
History Low Mid High

Figure 14 – KPMG-MACRO real Gross World Product forecast, 2021-2050
(Source: KPMG analysis)

It is also worth noting that, in our base case global macroeconomic forecasts, we do not have any major spurts of exceptional growth, analogous to the China experience in the recent past, for large developing economies such as Africa and India. While growth rates in these two regions are elevated over the forecast horizon, they are not assumed to accelerate during a rapid development phase before trailing off as they mature. Our maintained hypothesis is that the Chinese growth phenomenon will be difficult to replicate in other large, developing economies because they have very different political/economic systems.

Energy price shocks have disrupted economic activity over history, in some cases leading to recession and major dislocation. However, such shocks are, by their nature, largely unpredictable and temporary in nature. In developing the central demand scenario, we have incorporated the following key assumptions about the (i) industrial composition of the global economy; (ii) energy intensity of the economy; and (iii) share of fossil fuels in the energy mix. These assumptions are discussed in more detail below.

Industry composition of the economy
At the global level, the industrial composition of the global economy has not changed significantly in recent years. A small downward trend in industrial production as a share of GWP is evident between
1990 and 2020. In the central case scenario, we have assumed that the share of GWP accounted for by industrial production in 2050 falls to 16.4% in 2050, down from 26.5% in 2020 as illustrated in
Figure 15. This assumption decreases the rate at which energy consumption increases for a given increase in global economic growth.

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35%
29.0%
30%
26.5%
25%

20%
16.4%
15%

10%

5%

0%
1990 2020 2050
1990 2020 2050

Figure 15 – Global trend: industry share of GWP
(Source: KPMG analysis)

Energy efficiency
At the global level, a downward trend in the energy intensity of global production is evident. Our central case has the current trajectory continuing. This implies that, in 2050 at the global level, 0.09kg of oil equivalent energy inputs are required to generate 1 real $USD of GWP (see Figure 16). This assumption reduces the rate at which energy consumption increases with global economic growth.

25% 0.23

20%
0.16
15%

10% 0.09

5%

0%
1990 2020 2050
1990 2020 2050

Figure 16 – Global trend: energy efficiency
(Source: KPMG analysis)

Share of fossil fuels in the energy mix
The share of fossil fuels in the energy mix is assumed to continue falling in the central case scenario, moving from its current level of 83% to 70% in 2050 (see Figure 17). This is five percentage points lower than the average forecasted share of fossil fuels in the energy mix in 2040 across a range of energy market commentators (refer to Box 2). This assumption reduces the rate at which fossil fuels are consumed (as energy consumers switch to non-fossil fuels).

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100%
87%
83%
80% 70%

60%

40%

20%

0%
1990 2020 2050
1990 2020 2050

Figure 17 – Global Trend: share of fossil fuels in the energy mix
(Source: KPMG analysis)

These specific energy market assumptions, together with other assumptions embodied in KPMG’s global macroeconomic forecasts, yield a central case projection for global energy demand. Figure 18 shows that we are forecasting global energy demand to increase from 13,295 Mtoe in 2020 to
18,960 Mtoe in 2045 (a 42% increase in aggregate energy demand).

20,000
18,000
Global energy demand (Mtoe)

16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
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2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
2042
2044
2046
2048
2050

Figure 18 – Global demand for energy, 1990-2050
(Source: BP & KPMG analysis)

4.1.4 Alternative global demand scenarios
The central case scenario outlined above represents our best estimate of the expected outcome.
However, we recognise that there are many alternative outcomes with reasonable likelihood of occurring. To give some guidance on the possible range of outcomes, we consider two alternative scenarios either side of our central case. We refer to these scenarios as “low” and “high”.
Alternative scenarios have different settings for risk and global trade parameters designed to capture an economic environment, with higher risk and greater barriers to free trade in the low scenario and vice versa for the high scenario. Although the alternative scenarios have not been formulated in a formal probabilistic framework, we judge them to have reasonable likelihoods of occurring (i.e., we do not consider them to be in the tails of the distribution of possible outcomes).

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4.1.5 Long run price projections
Figure 19 below shows our long run projections for a reference real (2020 dollars) Japan Korea Marker
(JKM) price of LNG. In the central case, the real JKM price for LNG recovers from USD$4.40 per Mbtu in 2020 to around USD$8.80 per Mbtu in 2022. The price then declines to around USD$5.20 in 2026 before gradually rising to around USD$6.20 in 2050.

18.00

16.00
USD/Mbtu (2020 prices)

14.00

12.00

10.00

8.00 USD $8.3

6.00 USD $6.2

4.00 USD $4.5

2.00

0.00
2009
2011
2013
2015
2017
2019
2021
2023
2025
2027
2029
2031
2033
2035
2037
2039
2041
2043
2045
2047
2049
Low Mid High

Figure 19 – Projections for the real price of LNG (Japan Korea Marker)
(Source: KPMG analysis)

In the central case, the real JKM price for LNG recovers from USD$4.39 per Mbtu
in 2020 to around USD$8.77 per Mbtu in 2022. The price then declines to around
USD$5.23 in 2026 before gradually rising to around USD$6.18 in 2050.

4.2 Forecasting domestic gas prices
4.2.1 The link between global and domestic energy prices
In 2019, Australia became the largest exporter of LNG in the world, with 88mtpa of installed LNG capacity. Key to achieving this milestone was the investment in liquefaction plants in Gladstone, on
Australia’s east coast, with a combined nameplate capacity of 24mtpa or 27% of Australia’s total capacity. The establishment of LNG exports from Gladstone has linked the domestic market to international markets and influenced ECGM dynamics through pipeline flows and pricing.

Linking of the domestic gas market with the international LNG market has altered the market and pricing dynamics affecting the ECGM. By linking the Australian market to international buyers of LNG which often commands much higher prices, it has enabled the economic development of substantial volumes of high cost CSG. As a result, the ECGM has become closely linked with the dynamics of Asian LNG markets and their pricing instruments. This expansion of development to unconventional CSG resources, incentivised by the prospect of higher prices, has also improved the supply horizon or

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Australian gas which was previously anticipated to deplete faster due to the lower estimates of economically recoverable gas prior to CSG development.

Asian LNG markets
The majority of Australia’s LNG exports are sold into Asian markets, with China and Japan buying approximately 80% of LNG production, and South Korea and other northern Asian countries taking the remainder.

As LNG demand in Asia has continued to grow, more shipments have come into the region and prices have increasingly dislocated from the traditional benchmarks that included Brent crude. This has resulted in the emergence and use of the JKM LNG benchmark, a pricing instrument published by S&P
Global Platts. JKM has quickly become the main pricing measure used in the Asian spot market.

As a result of the significant trade in Australian LNG against JKM in Asian markets, the benchmark has also become an increasingly important influence in Australia’s domestic gas market dynamics.

Influence on the ECGM
At present, Australian LNG producers are the marginal suppliers of gas into the ECGM, and the price at which they would be willing to sell gas to domestic buyers influences the market price of gas domestically. The most likely destination for this gas (if not used to supply the ECGM) is the Asian LNG market. As such, domestic gas sales are increasingly linked to Asian LNG market pricing.

In theory, the LNG netback price is the price at which LNG exporters are indifferent between exporting
LNG and supplying the domestic market as this is the price at which both markets are at parity. An LNG netback price is a measure of an export parity price that a gas supplier can expect to receive for exporting its gas. It is calculated by taking the price that could be received for LNG and subtracting or
‘netting back’ the costs incurred by the supplier to convert the gas to LNG and ship it to the destination port.

Under current market dynamics, LNG netback prices based on Asian LNG spot prices (i.e. Platts JKM) play an important role in influencing domestic gas prices in the ECGM. In addition, Queensland LNG producers entered a Heads of Agreement (HOA) with the Government where a commitment was made to offer gas to the domestic market on competitive terms before offering any uncontracted gas to the international market.

There has also been a positive correlation between the LNG netback price and ECGM domestic prices over the previous two years (Figure 20), although volatility in this convergence still exists as domestic gas prices have experienced a positive spread over JKM netback throughout 2019 and 2020 as LNG prices have fallen.

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Wallumbilla Sydney Asian LNG netback price ACCC Forecast
14.00

12.00
$ per gigajoule

10.00

8.00

6.00

4.00

2.00

0.00
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
80%
60%
40%
20%
Price Gap (%)

0%
-20%
-40%
Price Gap (Wallumbila - Netback) Price Gap (Sydney - Netback)
-60%
-80%
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2016 2017 2018 2019 2020 2021 2022

5.00
4.00
3.00
2.00
Price Gap ($)

1.00
0.00
-1.00
-2.00
-3.00
-4.00
-5.00
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2016 2017 2018 2019 2020 2021 2022

Price Gap (Wallumbila - Netback) Price Gap (Sydney - Netback)

Figure 20 – Domestic spot price and Asian LNG netback price correlation
(Source: KPMG analysis)

An LNG netback price is not the sole factor that influences domestic prices in the ECGM. Individual prices paid by gas users will also reflect other factors that may be relevant to their circumstances, including the terms and conditions of their gas supply and any applicable transportation or retailer charges.

Notwithstanding this, domestic gas buyers in the ECGM are increasingly looking to JKM netback pricing as the benchmark for their domestic contracts, and this is also starting to emerge as a favoured benchmark by various levels of the Australian Government when setting domestic gas policy.
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Calculating an LNG netback price
A short-run LNG netback price at a particular location is calculated by taking a delivered ex-ship (DES)
LNG price and subtracting the cost of shipping the LNG from the loading port to the destination port, the short-run marginal cost of liquefaction, and the short-run marginal cost of transporting the gas from the relevant location to the LNG production facility.

Figure 21 – Calculating an LNG netback price
(Source: KPMG analysis)

4.2.2 Australia’s energy transition
Australia is not immune from the need to drive a low carbon energy future that is influencing global energy markets. An 11-14% emissions reduction below 2020 levels is required for Australia to meet the Paris Agreement, equivalent to 440 to 452 Mt CO2-e in 2030. Emissions for Australia in the year to
December 2020 were 510 MtCO2-e, a 14% reduction on 1990 levels but <4% decline on 2018 levels.
Given this trajectory, there is a need to drive further emissions reductions across the economy, and the pathways to achieve this are continuously evolving. Within this landscape, however, three broad trends have emerged in the energy sector that is shaping how energy will be delivered into the future.

It is important to consider these trends when assessing the potential pathways for development of the
Bowen Basin, as they will influence the demand for the Basin’s gas, the ability to finance development and the role of gas in the future energy mix.

Trend 1 – A decarbonisation journey, with the rise of renewables as the new baseload generation
Renewable energy generation has increased as a share of total Queensland generation from almost zero to more than 15% in the last decade. During this same period, gas powered generation has declined considerably as a result of both increasing Variable Renewable Energy (VRE) penetration and coal fired power generation remaining in the generation mix.

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16%
Proportion of QLD Generation 14%
12%
10%
8%
6%
4%
2%
0%

Gas (CCGT) Gas (OCGT) Gas (Reciprocating) VRE combined

Figure 22 – Share of total Queensland generation – gas vs. renewables (2011 – 2020)
(Source: KPMG analysis)

Trend 2 – An increasing need for a combination of storage solutions to address intermittency
As renewable penetration increases, there is forecast to be a large uptake in storage technologies, both for grid-scale and behind-the-meter distributed batteries. This large increase in storage capacity is required to address the inherent intermittency of renewable energy generation.

Figure 23 – Storage development outlook (2021 – 2041)
(Source: KPMG analysis)

Trend 3 – Increasing difficulty in obtaining traditional corporate and project financing for fossil fuel companies, combined with activist investor pressures
Traditional sources of finance and insurance for resources projects are pivoting away from fossil fuels.
Large insurers, asset managers and investment banks are committing to exit positions that generate revenue from coal, oil and natural gas, making it increasingly difficult for energy companies to finance new projects.

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Figure 24 – Positions of major energy industry participants on ESG
(Source: KPMG analysis)

4.2.3 Domestic price projections
KPMG’s forecast long run real price for LNG (JKM Price) in the mid-scenario is USD$6.20/MMBtu, equivalent to AUD$8.35/GJ (depending on the exchange rate). Using the ACCC methodology to calculate Netback at Wallumbilla, our expectation is a long-run Wallumbilla Supply Hub Netback price of approximately AUD$7.00 to $7.50/GJ.

16.00

14.00

12.00 KPMG long run JKM
price forecast (Mid
Scenario) $8.35
10.00
AUD $ / GJ

8.00

6.00 KPMG long run
Netback price forecast
(Mid Scenario) $7.08
4.00 Historic LNG Netback @WSH
Forecast LNG Netback @WSH
2.00 Historic JKM Price
Forecast JKM Price
0.00
Jan

Jan

Jan

Jan

Jan
Sep

Sep

Sep

Sep
Nov

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Nov

Nov
Mar
May

Mar
May

Mar
May

Mar
May

Nov

Mar
May
Jul

Jul

Jul

Jul

Jul

2018 2019 2020 2021 2022 2023

Figure 25 – Historic & forecast JKM and Netback (WSH) gas prices
(Source: KPMG analysis)

Volatility will exist in these prices depending on settlement dates for various delivery dates, demand and supply dynamics, short-term market events and other factors. However, using this price point as a guide, it is possible to analyse the economic viability and recoverability of gas from the Bowen Basin using a range of modelling scenarios.

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4.2.4 Commentary on the long-run netback price
The long-run forecast JKM LNG price presented in this report is an average projected price based on long-run drivers of gas demand globally. Short term, and potentially medium term, JKM prices will fluctuate based on short term market conditions, which historically have included Northern Hemisphere winter weather fluctuations, liquefaction plant shut-downs due to maintenance or damage, shipping constraints and gas storage inventory changes. Over the long term, these short-run increases or decreases in JKM LNG prices mean-revert to the fundamental long-term supply and demand dynamics of the market.

The netback price calculated at the Wallumbilla Supply Hub based on the long-run JKM LNG price generally sets a floor for gas prices within the ECGM, although short-term volatility means that prices fluctuate above and below the netback in the short term. The netback price point of approximately
AUD$7.00 to $7.50 / GJ at Wallumbilla that has been calculated as part of this Study is considered a reasonable middle-point for the long-term gas price for the ECGM (under balanced ECGM supply and demand conditions), although short-term fluctuations will occur due to short-term market dynamics.
Where supply is tight, the ECGM prices will be elevated, with the GSOO predicting tight supply conditions to persist in the near to medium term.

The analysis was also conducted using a low-point forecast of AUD$5.00/GJ and a high-point forecast of $9.00/GJ to test the sensitivity of economics with a wider range of gas prices. Section 7.2 provides an economic production matrix for all three gas prices, where various well type curves have been modelled for each.

As a base case scenario, the AUD$7.00/GJ central price forecast has been used to test the economic viability of the Bowen Basin development, as it provides a reasonable and realistic assessment of economic recovery.

Box 3: What do we mean by gas price?
The gas prices provided in this report are wellhead prices, and do not include transport to Wallumbilla, as the pipeline route, length, size, capacity, utilisation and contracting model is not known at this time.
Estimates of a potential tariff for transport of gas from the Basin vary considerably depending on utilisation of the pipeline, contract durations, volumes and types. A reasonable estimate of a transport tariff from the Basin to Wallumbilla is in the range of $0.70 to $1.20. At this concept stage, given the accuracy of forecast prices and the level of unknowns in the commercial model this pipeline may take, the wellhead price of $7.00/GJ is considered reasonable when compared against a mid-point range of
$7.00 to $7.50/GJ at Wallumbilla, depending on exchange rates and other factors. A key next step for understanding the potential of the Basin in more detail would be to develop a detailed commercial model to analyse the potential transport tariff considering the above variables.

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5. Domestic energy market
As described in Section 3, Australia’s domestic gas infrastructure can be grouped into three main gas markets:

• The ECGM;

• The Northern Gas; and

• The West Coast Gas Market.

The Bowen Basin is not connected to any of these gas markets with existing infrastructure, however it is located immediately north of the ECGM, which connects the Surat Basin in the north all the way to
Tasmania in the south. Given its proximity, the Bowen Basin’s likely source of market demand for gas will be the ECGM, and so the analysis of supply, demand, transport, price and competition has been focused on this market only.

5.1 The East Coast Gas Market
As illustrated in Figure 26, an interconnected gas grid connects Australia’s eastern, northern and southern states. This market has undergone structural change as the gas industry has developed, particularly in Queensland. Amid emergence of southern state supply decline, this has resulted in changes to the direction of pipeline flows, the supply/demand balance and gas contract prices.

The ECGM has evolved from separate state-based markets, each served by a single basin and a single transmission pipeline. Over the past 20 years, new pipeline investment has connected these markets, making it possible for bi-directional transport of gas between Queensland and the southern states.

This interconnected network expanded further in 2018 with the opening of the 622km Northern Gas
Pipeline, linking Tennant Creek in the Northern Territory with Mount Isa in Queensland. This new pipeline allowed the ECGM to source gas from the Bonaparte Basin in the Timor Sea, as well as onshore shale gas developments. The development of Queensland’s LNG industry has further transformed the
ECGM by giving producers the added option of exporting their gas offshore.

The ECGM can be thought of in terms of two dominant markets – northern and southern. The northern market encompasses all of Queensland through to Moomba in South Australia, while the southern market encompasses Adelaide, Sydney, and the Declared Wholesale Gas Market in Victoria. Prices in the northern and southern markets are generally distinct from each other, driven by varying physical and market dynamics:

• The market is physically dispersed and does not have a dense network of pipelines. Gas flowing
from Queensland is transported via several transmission pipelines which adds cost and can act as
a bottleneck;

• There are various trading points along the east coast, including Wallumbilla and Moomba, which
allow for the use of gas swaps to avoid these transport challenges;

• A depletion of cheap gas reserves from southern fields, such as the Gippsland and Otway Basins,
has resulted in 80% to 90% net-south gas flows per year since 2018; and

• The increasing trend of gas flowing from producers in the north to consumers in the south has
resulted in the need for additional investment in mid-stream infrastructure. This includes increasing
pipeline capacities (particularly the South West Queensland Pipeline (SWQP) and Moomba Sydney
Pipeline (MSP), and the potential use of LNG import terminals to supply gas to southern states,
especially during peak demand periods over winter.
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Figure 26 – Australia’s East Coast Gas Market infrastructure
(Source: Australian Energy Market Operator (AEMO))

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5.2 Gas demand
The demand for gas in the ECGM is driven by four main buyers of gas, which can be categorised into consumers of gas to export LNG, and domestic consumers who use the gas within Australia:

1. LNG exporters; and

2. Domestic consumers:

a. Commercial & industrial (C&I) businesses;
b. Electricity generators (GPG); and

c. Households (Res).
Figure 27 shows that, while LNG export is the largest consumer of east coast gas, domestic demand is still considerable – domestic customers in eastern Australia consumed approximately 600PJ of gas in 2021.

2,000
1,800
1,600
1,400
1,200 LNG Export
1,000
PJ

800
600
Gas Powered Generation
400
Residential/Commercial
200
Industrial
0
2014
2015
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2017
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2019
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2034
2035
2036
2037
2038
2039
2040
2020 GSOO

2021 ECGM gas consumption by sector

C&I

258 PJ
1,325 PJ 602 PJ 189 PJ Res

155 PJ

LNG Export
GPG

Figure 27 – Historic & forecast demand for gas in the ECGM
(Source: AEMO & KPMG analysis)

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5.2.1 Demand from LNG exporters
The development of Queensland’s LNG industry has transformed the eastern Australian gas markets by giving producers the added option of exporting their gas offshore. In 2019, Australia became the largest exporter of LNG in the world with 88mtpa of installed LNG capacity. Key to achieving this milestone was the investment in liquefaction plants in Gladstone, on Australia’s east coast, with a combined nameplate capacity of 24mtpa or 27% of Australia’s total capacity. The establishment of LNG exports from Gladstone has linked the domestic market to international markets and influenced ECGM dynamics through pipeline flows and pricing.

The liquefaction plants in Gladstone consume a combined 1,300 to 1,500PJ of gas per annum, representing approximately two-thirds of all gas demand in the ECGM. This considerable demand volume means that LNG exporters have considerable influence in the market from both a supply and demand perspective.

Linking of the domestic gas market with the international LNG market has changed how the gas price is set for ECGM participants. It has created opportunities for gas producers to sell gas for export, and for gas buyers to purchase gas that would otherwise be exported. As a result, Australia’s East Coast
Domestic Market has become closely linked with the dynamics of Asian LNG markets and their pricing instruments.

The three liquefaction plants in Gladstone are Australia Pacific LNG (APLNG), operated by Origin and
ConocoPhillips, Gladstone LNG (GLNG), operated by Santos and Queensland Curtis LNG (QCLNG), operated by Shell.

The Origin and ConocoPhillips-operated APLNG project commenced exports in 2016 with 9mmtpa nameplate capacity. The plant consumes gas from Origin Energy’s acreage in the Surat Basin and, beyond upstream expansion to backfill the trains, no expansions in export capacity are planned.

The Santos-operated Gladstone LNG project has been operating since 2015 and has a nameplate capacity of 7.8mmtpa LNG. Gas is sourced from the Surat and Bowen regions. There are several minor planned expansions of the GLNG project designed to extend its operational life, but no expansion of export capacity is planned.

The Shell-operated QCLNG project was initially designed to produce 8.5mmpta LNG, with potential expansion of up to 12mmpta after further development. This expansion is not anticipated to take place and, similar to the other two projects, development is limited to expansion of upstream gas supply.

It is essential for each of the three LNG plants to meet contractual LNG cargo schedules and volumes using the upstream gas extracted from the Surat and southern Bowen Basins. Beyond this, opportunities exist for LNG exporters to ship additional spot or uncontracted cargos of LNG, however this is now governed by the requirements of the HoA signed with the Federal Government and the
Australian Domestic Gas Security Mechanism (ADGSM). Both require LNG exporters to offer gas in excess of contractual volumes to the domestic market before being permitted to export it as LNG.

Global demand for LNG
LNG demand is expected to grow faster than overall natural gas consumption as global trade increases to connect regions of highest supply and demand. However, even after substantial postponements of planned Final Investment Decisions (FIDs) during the oil price crash and pandemic of 2020, there is still a risk of new LNG supply outpacing growth in the mid-2020s (Figure 28).

Mainland China is expected to be the largest single market of new LNG demand, but new and emerging importers are a significant source of long-term import growth, particularly in south and southeast Asia.

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800
Japan, South Korea, and Taiwan Europe
North America Other Asia
700 South America Middle East & North Africa
Sub-Saharan Africa Other
Liquefaction Capacity, MMt
600

500
MMt

400

300

200

100

0
2000 2005 2010 2015 2020 2025 2030 2035 2040

Figure 28 – Forecast global LNG demand
(Source: IHS Markit)

China
Coal-to-gas switching activity lessened in 2019 as the focus was shifted to economic growth. Near-term
LNG import growth in mainland China is expected to be dampened by the impact of COVID-19 and reduced fossil fuel consumption by approximately 25% in the country. China has pledged to reach net zero emissions by 2060, however it is still aiming to peak its emissions by 2030 and, coupled with an administrative and policy support for gas, and little to no local supply, China will certainly be a large LNG importer over at least the coming decade.

Japan
LNG demand is expected to decline over the rest of the decade due to Japan’s decarbonisation pledges which have been increased to a commitment to reduce greenhouse emissions by 46% from 2013 levels by 2030. This will no doubt impact any demand for gas as well as incentivise Japanese businesses to invest in alternative energy sources rather than bolster existing gas infrastructure.

South Korea
Although the low cost of coal and nuclear make them strong competitors to gas in South Korea’s near-term power mix, South Korean annual gas demand is still higher than Australia's at 2,070 PJ in
2020 and is forecast to increase. The Government’s plan to reduce South Korea’s long-term reliance on nuclear and coal-fired generation will support LNG demand and their currently unachievable decarbonisation targets will likely have little impact.

Impact on ECGM LNG export volumes
Currently there are no LNG export projects proposed, anticipated or under development in the ECGM beyond the existing three plants. Anticipated development projects involve expanding the upstream
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gas supply to backfill these plants only, without any additional export capacity (and thus total demand for gas) being added.

The growth in global LNG demand outlined previously is expected to be met by greenfield developments and brownfield expansions, such as Qatar’s North Dome expansion, as well projects in the USA and Russia. For the east coast LNG producers of Australia, this means continued exports of approximately 1,400 to 1,500PJ of gas annually into the future (Figure 29).

1,600

1,400

1,200

1,000
PJ

800

600

400

200

0

Figure 29 – Forecast LNG export gas demand (ECGM)
(Source: AEMO & KPMG analysis)

5.2.2 Demand from domestic users
Excluding LNG, C&I customers are the largest market for domestic gas – consuming 41% of gas sold to the domestic market, where it is used as an input to manufacturing. The electricity sector is another major consumer, using gas to fuel generators. Gas Powered Generation (GPG) accounted for 29% of domestic gas sales, with the remaining 30% sold to residential and minor commercial customers.

AEMO forecasts a period of relatively flat demand for natural gas in the ECGM across the medium to long term, following a period of decline from 2010 (Figure 30). Driving this flat forecast is a lower long-term outlook for GPG based on projections of growing distributed renewable energy generation.
Challenging economics faced by Australia’s industrial gas users means demand in the C&I sector is also projected to be flat. In the residential sector, new gas connections are likely to be offset by increasing efficiency and fuel switching away from gas appliances to electricity.

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750

500
PJ

250

0

C&I Residential GPG

Figure 30 – Historic & forecast domestic consumer gas demand in the ECGM
(Source: AEMO & KPMG analysis)

Whilst the forecast is for aggregate demand for gas in the ECGM to remain flat, the composition of this demand and its position in the market will continue to evolve. This will likely become evident through increases in uncontracted demand positions and the desire to re-contract through shorter term contracts, leveraging more flexible products in order for customers to respond to uncertainty in their downstream market.
Table 4 – Demand forecast, drivers and preferences by sector
(Source: KPMG analysis)

Demand
Sector Drivers Product Preferences
forecast

 Price  Longer term contracts
Commercial & Industrial FLAT  Energy efficiency  Stable pricing
 Demand for end products  Lower need for flexibility

 Lower demand for
centralised electricity  Highly flexible supply
LOWER generation  Rapid response times
Gas Power Generation LOWER
 Increasingly peaking to driven by weather-
backfill renewable volatility dependent peaking
 Weather-dependent
 Continuing and new energy
efficiency schemes
Residential FLAT
 Highly reliable supply
 Fuel switching away from
gas appliances

Forecast demand by market
Whilst the ECGM is considered a single market, the dynamics of each state within this market vary. In
South Australia, electricity generation accounts for 50% of gas demand. Industrial demand from medium to large industrials (>0.5PJ/a) dominates in Queensland, while industrial and residential demand are roughly equal as the main components in NSW. Victoria is the only state where a majority of demand (62%) is from small residential and commercial customers, who use gas mostly for heating and cooking. Over 80% of Victorian households are connected to a gas network, which is a legacy from the development of the Bass Strait oil and gas fields.

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250

200

150

100
PJ

50

0
2020
2022
2024
2026
2028
2030
2021
2023
2025
2027
2029
2020
2022
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2028
2030
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2023
2025
2027
2029
2020
2022
2024
2026
2028
2030
VIC QLD NSW SA TAS

Medium to Large Industrials (>0.5PJ/a) Small Industrials (0.01-0.5PJ/a) Residential and Commercial GPG

Figure 31 – Gas Demand Breakdown by State
(Source: AEMO & KPMG analysis)

Demand for gas is highest in Victoria, which is both increasingly reliant on northern gas supplies and is the most difficult market to access given physical and contractual transport bottlenecks. As such, obtaining firm capacity in key transport pipelines that link production to key hubs in Victoria will be an important competitive advantage to supply this market into the future.

5.2.3 The Northern Queensland gas market
The North Queensland Gas Pipeline (NQGP), also known as the Moranbah to Townsville Gas Pipeline, is a transmission pipeline located in north-east
Queensland (Figure 32). The NQGP supplies gas from the Moranbah gas processing plant to large industrial customers in Townsville, such as the
Yabulu gas fired power station and the Queensland nickel and copper refineries. The gas is sourced from coal seam gas fields in the Bowen Basin which are located near Moranbah and are jointly owned by AGL and Arrow Energy.

Demand for gas from the NQGP has been declining as power prices are increasingly pressured by competing renewable generation. Whilst the NQGP has a capacity of 108TJ/d, the pipeline is, on average, only flowing approximately 30TJ/d of gas from the
Moranbah Gas Project.

The commercial viability of the NQGP is further challenged by the fact that it is an islanded system.
This increases the need for longer term Gas Supply
Agreements (GSAs) with consumers to underpin continued economic operation of the pipeline.
However, trends in recent years have been for
Figure 32 – North Queensland gas market infrastructure shorter GSAs, with buyers unwilling to take on the (Source: AEMO) risk of long-term exposure given the volatility in gas prices that has existed since 2016.
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Queensland
Nickel Yabulu
Capacity: 108TJ/d
Moranbah Townsville
Gas Plant Power Station
Actual: ~30TJ/d
Dyno Nobel
Glencore Copper
Refineries Ltd

Figure 33 – Current state of gas supply & offtake – NQGP
(Source: KPMG analysis)

There is potential to stimulate demand to the north of the Bowen Basin, either by increasing the demand for gas fired power from existing power stations, or by growing demand from large industrial users.
Such increases are likely to contribute modest growth in gas production in the Bowen Basin, potentially between 30TJ/d to 60TJ/d, however it is unlikely to be sufficient to underpin a full-scale development of the Bowen Basin as a whole.

5.2.4 Hydrogen and its effects on gas demand
Domestic commercial demand for hydrogen is expected to grow significantly in the late 2020s, reaching
>1Mtpa in each of Victoria, Queensland and South Australia by 2036 (graph below). Victoria and
Queensland are forecast to be the largest consumers of hydrogen resources, with Victoria taking the lead at 1.5 Mt of hydrogen consumption by 2038 (Figure 34).

Importantly, these two states are currently the largest consumers of natural gas (Queensland with LNG and Victoria with residential and commercial customers). As such, it is expected that growth in commercially viable hydrogen at scale will have an effect on the demand for natural gas in the ECGM.
This growth is highly prospective however, as currently there is no hydrogen consumed in the ECGM and the technology is still in nascent trial phases.

1.4

1.2
Hydrogen Consumption (Mt)

1.0

0.8

0.6

0.4

0.2

0.0
2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

Queensland New South Wales Victoria South Australia Tasmania

Figure 34 – Forecast demand for hydrogen in the ECGM
(Source: AEMO & KPMG analysis)

Queensland has over AUD$20Bn committed to development of renewable energies, and by 2030
Queensland has pledged to be Australia’s leading hydrogen producing state. Hydrogen is expected to
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grow to as much as 100PJ out of the ECGM’s approximately 600PJ annual domestic consumer demand for gas (Figure 35). This is driven by fuel blending (hydrogen with natural gas), fuel switching (burning hydrogen as a primary fuel source) and industrial consumption of hydrogen as a production input.

Industrial hydrogen consumption will grow slowly after 2037 however, as most natural gas used in industry is as a reagent rather than a fuel source. Beyond 2040, natural gas as a primary fuel source may further decline as hydrogen becomes increasingly prevalent in domestic and global energy supply chains.

700

600

500
Annual consumption (PJ)

400

300

200

100

0

Net Natural Gas Consumption Hydrogen in Distribution Grid Industrial Hydrogen Consumption

Figure 35 – Forecast hydrogen demand relative to natural gas
(Source: AEMO & KPMG analysis)

5.3 Gas supply
The production of gas in the ECGM is adequate to service current and forecast domestic gas demand, assuming that gas produced above contracted LNG volumes is directed into the domestic market. The challenge in supplying sufficient gas to domestic consumers is not production volumes, but the ability to transport those volumes from the producers, which are increasingly located in the north (Queensland and Northern Territory), to consumers, who are located in the south (Victoria, New South Wales and
South Australia).

Traditionally, gas production to meet demand from the southern states has primarily come from the
Victorian gas basins – Gippsland, Otway and Bass – with production from these fields typically well in excess of Victorian demand. However, southern supply from existing and committed gas developments is forecast to reduce by more than 35% (163PJ) over the next five years, due to declining legacy fields.

In contrast, AEMO expects new and existing gas fields in Queensland and the Northern Territory to increase supply from approximately 77% of total ECGM supply in 2020 to 81% in 2024, helping to meet expected demand in eastern and south-eastern Australia (including tenements in Queensland that are reserved for domestic market use only). This is driving a change in where gas is produced and how it is transported across the ECGM. Further supply may be added to the system if proposed developments of LNG regasification import terminals in south-eastern Australia proceed.

5.3.1 Current and forecast gas supply
AEMO considers current gas production and transportation capacity across the eastern states is sufficient to meet current gas demand. However, despite ongoing field developments and increases in
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2P developed reserves, production from existing gas fields is in decline, particularly among southern fields. Gas production from existing and committed gas developments is forecast to provide adequate supply to meet gas demand until between 2023 and 2025 depending on the demand scenario, however this assumes that cargoes of export LNG above contracted levels are diverted to meet domestic demand if needed.

If anticipated gas field projects are developed, resource adequacy improves until at least 2026 (Figure
36). However, due to the location of most of the anticipated projects within Victoria, dynamic operational pipeline constraints would limit their effectiveness in addressing the forecast peak winter day supply gaps under certain conditions.

Beyond 2026, existing, committed and anticipated projects are forecast to be insufficient to meet southern demand, and southbound pipeline infrastructure upgrades would be required to deliver more gas from northern to southern states, particularly during winter peak days (refer Section 5.4 for details).
Alternatively, planned LNG import terminals will need to supply gas into southern markets during peak seasons to address shortfalls from northern piped gas (refer Section 5.5.2).

2,000

1,500
PJ

1,000

500

0
2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040
Developed Committed Anticipated LNG imports Forecast demand

Figure 36 – Forecast ECGM gas production (including LNG import)
(Source: AEMO & KPMG analysis)

5.3.2 Diversion of LNG export volumes to service domestic demand
Australian Domestic Gas Security Mechanism (ADGSM)
In response to price increases during 2016 and 2017, the ADGSM was established as a temporary supply security measure to cease on 1 January 2023. The ADGSM is intended to ensure sufficient supply of natural gas to meet the forecast needs of energy users in Australia. It aims to do so by limiting exports of LNG during a “domestic shortfall year” and establishing a licensing regime whereby the
Resources Minister may grant export permission to LNG exporters.

Under the ADGSM, LNG export restrictions will be imposed in only a “domestic shortfall year.” In order to arrive at such a conclusion, the Resources Minister is required to formally issue a declaration to announce his/her intention to consider whether the forthcoming year will be a domestic shortfall year
(the “Declaration”), consult relevant market bodies, Government agencies, potentially impacted industry players, other relevant Australian Government ministers and other stakeholders to seek their view on the then-current and forecast gas market conditions and any potential for a gas market shortfall
(the “Consultation”) and, if he/she has reasonable grounds to believe that there is a domestic gas market shortfall after the consultation, make a determination that gas export controls will apply in a particular year (the “Determination”). Since the introduction of the ADGSM in 2017, the Resources
Minister has not declared a domestic shortfall year.

A 2019 review of the ADGSM concluded that the improvement in the domestic supply outlook and subsequent market conditions (since 2017) can, in part, be attributed to the ADGSM. In particular, LNG
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exporters have increased their supply to the domestic market since the ADGSM was introduced and are currently, in aggregate, net contributors to the domestic market. The review recommended retaining the ADGSM until the scheduled 2023 cessation and amending the guidelines to include reference to the ACCC’s LNG netback price series in estimating a potential shortfall. This stops short of introducing direct price controls in the ECGM, but it does link the ADGSM to LNG netback prices.

Heads of Agreement
On three occasions, a HoA has been signed by the Australian Prime Minister and representatives of the three east coast LNG exporters (APLNG, GLNG, QGC) to ensure these producers make available a secure supply of gas to the east coast market. Under the agreement, LNG exporters committed to offer uncontracted gas to the domestic market before selling this gas internationally.

Domestic Gas Reservation Scheme
Whilst the ADGSM functions somewhat as a domestic gas reservation scheme, the Australian Federal
Government has announced its intention to explore options for a national domestic gas reservation scheme. This may take the form of an acreage reservation, preferential reservation, blanket reservations or case-by-case assessments. As the states hold jurisdiction over onshore petroleum resources, any
Federal Government scheme would need to be implemented with support of the states.

Queensland – Through its regulation of petroleum leases, the Queensland Government imposes a condition on certain tenements that any petroleum developed on the leased acreage must be sold and used only in Australia. Recently, the Queensland Government included a specific requirement for gas produced to be supplied to domestic manufacturing consumers. This approach will not impact the market materially because it will simply displace existing supply to these consumers. An independent review of this policy in 2019 found that stakeholders broadly accepted the policy but noted there was room for improvement around adaptability, efficiency and transparency, and provision of information to market participants.

Western Australia – Western Australia adopts a policy that requires LNG producers to reserve the equivalent of 15% of LNG production for the domestic market. LNG producers can obtain project approval by proving they will reserve gas for the market, develop the necessary infrastructure, and show diligence and good faith in marketing the gas. The policy has been in place for several years and is flexible with respect to exact timing, price, and sale conditions. The Western Australian domestic gas reservation policy has been relatively successful in terms of supporting the domestic market and not being a significant impost on LNG producers. One of the reasons for this is that in Western Australia the natural gas industry is predominately offshore, with conventional wells extracting large reserves of gas and without the complications of CSG production.

5.3.3 Forecast supply and shortfall (daily)
When assessing supply adequacy, it is important to take into consideration both annual and daily field production limitations. Whilst average annual supply may meet or exceed average annual demand, the demand for gas is typically seasonal – daily demand peaks exist in winter months as gas usage increases as a result of increased heating loads. In addition to seasonally driven demand, declining fields such as those in southern states also become maximum flow rate limited – meaning the maximum amount of gas able to be extracted from the field declines. Both of these factors combine to create daily supply-demand gaps that are not apparent when only considering annual average flows.

An example of this daily supply-demand gap is highlighted in modelling by AEMO, which has calculated supply-demand gaps between 13TJ and 374TJ/day across winter 2024 as declines in peak southern production, coupled with physical bottlenecks, generate supply shortfalls that are not evident in the annual supply-demand analysis (Figure 37).

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2,500

2,000

1,500
TJ/d

1,000

500

0
Jan-30 Feb-30 Mar-30 Apr-30 May-30 Jun-30 Jul-30 Aug-30 Sep-30 Oct-30 Nov-30 Dec-30

400

300
Supply Gap
(TJ/d)

200

100

0
Jan-30 Feb-30 Mar-30 Apr-30 May-30 Jun-30 Jul-30 Aug-30 Sep-30 Oct-30 Nov-30 Dec-30

Southern production Transported via SWQP LNG receipts
Southern storage Supply Gap Southern demand

Figure 37 – Daily supply-demand gap in southern states – 2030
(Source: AEMO & KPMG analysis)

Fortunately for the supply-demand balance across the east coast, Queensland gas demand has much less seasonal variation, and so the northern fields’ ability to meet peaks and troughs in daily demand is much less of a concern than in the southern states.

Additionally, LNG export demand typically peaks over the Australian summer months as global demand for LNG is highest during the Northern Hemisphere’s winter season. In aggregate, Queensland seasonal demand peak is forecast to occur over summer, and southern demand peaks are forecast to continue to occur in winter.

As a result, on balance, northern supplies are still sufficient to meet daily and annual supply-demand gaps. On balance, gas production capacity, supported by new upstream developments in the north, is expected to be sufficient to meet both LNG and ECGM demand. However, limits related to transport and storage capacity, which are a key part of the supply chain, will need to be addressed through further investment.

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5.4 Transport and Storage
Connecting producers to consumers in the ECGM is a network of bidirectional transmission pipelines connected to trading hubs and gas storage facilities between Queensland and Tasmania. As gas flows net-south (from Queensland into New South Wales and Victoria especially) increase, the transmission pipelines and storage facilities are increasingly becoming capacity constrained, leading to projected shortfalls in supply during peak winter periods.

5.4.1 Transmission pipelines
The pipelines leading south through, and downstream of, Wallumbilla have various usage patterns, with some pipelines having a strong correlation between usage and winter months in Australia. The SWQP is most prominent given that the pipeline provides access from northern to southern markets during winter months (Figure 38).

100%

80%

60%

40%

20%

0%
Feb-19

Feb-20
Mar-20

Sep-20
Sep-18

Mar-19

Sep-19
Nov-18
Dec-18

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Dec-19

Aug-20

Nov-20
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Apr-19
May-19

Oct-19

Jan-20

May-20
Jun-19
Jul-19

Jun-20
Jul-20

Oct-20
Comet Ridge to Wallumbilla Pipeline Darling Downs Pipeline

Reedy Creek to Wallumbilla Pipeline South West Queensland Pipeline

Figure 38 – Pipeline utilisation at Wallumbilla showing seasonality
(Source: AER Bulletin Board & KPMG analysis)

The SWQP is currently the only link between the northern and southern gas systems and is the limiting factor in transporting northern gas to southern states. It connects to the MSP and the
Moomba to Adelaide Pipeline System (MAPS)
(Figure 39).

Flow in the pipeline is bidirectional, and so it can be used to shift excess supply or meet peak demands in either system – meeting southern peak demand days in winter and sending excess southern gas north during summer or shoulder periods.
Figure 39 – South West Queensland pipeline location
(Source: KPMG analysis)
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Recently, the SWQP has been increasingly used to help meet demand in the southern states – gas was transported towards the southern states on over 70% of days in 2019, compared to fewer than 10% of days in 2016. The quantity of gas transported south has also increased, with gas transported south exceeding 200TJ on approximately 25% of days in 2019, compared to fewer than 10% of days in 2018.
In part, this is due to the addition of the NGP to the ECGM in January 2019, taking Mt Isa gas demand away from the SWQP.

Figure 40 shows the total SWQP capacity and the split between contract and uncontracted capacity.
During non-winter months, the proportion of uncontracted capacity is approximately 25%. However, during winter months, the proportion of uncontracted capacity drops to 10%. Given that the SWQP is the critical link between northern gas producers and southern gas consumers, shippers that do not currently have firm capacity on this facility may find it challenging to bring any additional gas from
Queensland to the southern states.

400,000 100%
350,000
300,000 75%
250,000
GJ

200,000 50%
150,000
100,000 25%
50,000
0 0%

Contracted Capacity Uncontracted Capacity SWQP Capacity

Figure 40 – SWQP capacity – 2021-2023
(Source: AER & KPMG analysis)

In the absence of greater southern supply sources being opened (either through the lifted ban on conventional gas exploration from mid-2021 or through LNG imports), meeting the gap in demand will require greater flow through SWQP from production sources in Queensland.

AEMO’s analysis indicates that under their central scenario, by 2022 only 4% of days will have gas flowing towards Wallumbilla on SWQP. By 2023, all days will have net flow towards Moomba in order to meet southern demand (Figure 41). This will require a significant increase in supply sourced from
Queensland through Wallumbilla in order to meet this flow rate.

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500
400

Flow towards
Queensland
300
200
100
TJ per day

0

southern states
Flow towards
-100
-200
-300
-400
-500

Percentage of days in the year
2016 2017 2018 2019 2022 2023 2024

Figure 41 – Historical and forecast flow distribution curve for SWQP
(Source: AER & KPMG analysis)

The options to overcome these transport challenges include additional compression to increase the capacity of the SWQP, or potentially executing gas swaps with producers that have positions downstream of SWQP, including Santos and others with gas positions at Moomba.

There are several proposed transport projects that are aiming to alleviate constraints on the SWQP, including:

• Upgrading the SWQP to provide an additional 25% capacity in both directions (see below APA
Group East Coast Grid Expansion project);

• Upgrading the MWP to provide an additional 25% toward Sydney;

• Upgrading the Victoria-New South Wales Interconnector to provide an additional 125TJ/day toward
Victoria; and

• Upgrading the Eastern Gas Pipeline so that it can flow bi-directionally.

There are also proposed projects that aim to construct new greenfield pipelines from the Amadeus
Basin and to connect Wallumbilla to Newcastle, however these are unlikely to proceed during the forecast period when compared to other upgrade projects.

APA Group East Coast Grid Expansion
As owner and operator of the SWQP and MSP, APA Group is currently undertaking an expansion project to improve capacity to transport gas south on both pipelines. The additional capacity is expected to deliver sufficient gas to meet forecast winter shortages from 2023.

The expansion will be delivered at a capital investment of approximately $270 million. It will increase winter peak capacity of the East Coast Grid by 25% through additional compression and associated works on both the SWQP and the MWP.

The first stage of expansion works will increase Wallumbilla to Wilton capacity by 12% and is targeted for commissioning in the first quarter of calendar year 2023, ahead of forecast southern state winter supply risks identified in the 2021 AEMO Gas Statement of Opportunities.

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The expansion will be delivered in a number of stages:

• Stage 1: The first stage of expansion works includes the construction of a single site of compression
on each of the SWQP and MWP and will increase gas transportation capacity by 12%.

• Stage 2: The second stage of expansion works includes an additional site on the SWQP and MWP
which will add a further 13% of capacity.

• Stage 3: APA is undertaking engineering and design works on a potential third stage (three additional
compressor locations on the MWP) of the East Coast Grid to add a further 25% transportation
capacity.

Most of the expansion works will occur on APA owned sites, which have existing infrastructure. Each project site will require a peak construction workforce of around 80 people. Construction of the proposed East Coast Grid Expansion Project is planned to commence in the first half of 2022. The construction of each compressor station is intended to take approximately nine months.

5.4.2 The role of gas storage facilities
For seasonal peaking, as assurance against potential supply disruption, and in order to take advantage of seasonal pricing variation, a number of gas storage facilities exist in the ECGM. There are four major southern facilities devoted to storage which are:

• Roma Underground Storage (RUGS) (Surat
Basin) – >50PJ;

• Silver Springs (Surat Basin) – 35PJ;

• Moomba storage (Cooper Basin) – 85PJ; and

• Iona/WUGS (Victoria) – 22PJ.

Storage facilities provide additional flexibility to help
meet maximum demand requirements by storing
surplus gas supplies produced in summer for use in
Roma Underground winter. The ability for storages to be refilled to
Storage capacity and/or to deliver gas at maximum
Moomba Storage withdrawal rates may, at times, be limited by
Silver Springs pipeline capacity.

Over recent years, as maximum daily production
capacity in southern states has reduced, there has
been an increased reliance on storages. As shown
in Figure 43, from 2017 through to 2019, each year
successively drew on more storage to help supply
Iona/WUGS peak and seasonal demands. In 2020, this observed
Major gas storage
trend was disrupted due to reduced total
facility
(>20PJ capacity) consumption, particularly from GPG consumption,
despite a small increase in southern residential and
Figure 42 - Gas storage infrastructure in the
commercial consumption, impacted by colder
ECGM
(Source: KPMG analysis)
winter conditions.

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500
2017 2018
400
2019 2020
300

200
TJ/day

100

0

-100

-200

-300
0% 50% 100%
Percentage of days in year

Figure 43 - Cumulative distribution of net changes in storage level for Iona UGS, 2017 to 2020
(Source: AER & KPMG analysis)

The critical role for gas storage is expected to increase as the maximum daily production capacity decreases further, particularly after 2023, although this may depend on the cost-competitiveness of
LNG import relative to storage. Storage tariffs are generally not publicly released by the proponents, but estimates indicate that storing gas can add $0.50 per GJ per day to the cost of delivered gas.

Existing storages alone cannot provide sufficient flexibility in the system long term to manage the seasonality of southern demand as the storage capacities are simply not deep enough. Proposed projects to expand capacity will improve their effectiveness but are still not expected to be the sole solution to the seasonal supply-demand gaps.

Proposed Storage Projects
There are three major projects proposed to increase ECGM storage capacity beyond its current 110PJ:

• Golden Beach Gas Storage Facility (Gippsland Basin, Vic) – GB Energy’s Golden Beach project is
designed for 12.5 PJ capacity with an estimated completion date in 2024.

• Iona Storage Expansion (Victoria) – Lochard Energy's Iona storage expansion is in the early
planning stage with an 18-month development timeframe from FID. The capacity of this project is
to be confirmed.

• SWP (South West Pipeline) (Geelong-Port Campbell, Vic) – APA’s SWP project (designated
WORM) is an augmentation of the transmission system which will enhance the Iona system’s
storage filling capacity as well as potential increases in storage capacity elsewhere in the system.

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5.5 Alternative sources of supply
Increasing supplies of gas from northern states into southern states via increased transport capacity and more efficient use of existing capacity is a key part of meeting southern demand. In addition, several projects have been announced that propose to supply alternative sources of gas into southern networks, including LNG import terminals, developing other frontier basins (such as the Beetaloo Basin) and developing other upstream gas projects (such as Narrabri).

5.5.1 Other frontier basins
Beetaloo Basin
The Beetaloo Basin is located in the central portion of the Northern Territory between McArthur River and Tennant Creek. The region contains moderate amounts of shale gas which can be accessed through hydraulic fracturing.

The Beetaloo sub-basin has been extensively studied for potential development of onshore gas production and has been estimated to have 2C contingent resources of 6,996PJ of natural gas as of
2019. The Beetaloo Basin has been extensively reviewed for the potential to develop its resource in a series of studies which identified potential development scenarios for hydraulic fracturing and the infrastructure requirements to bring the gas to market.

Development of the Beetaloo Basin has been anticipated based on a 100 well per year drill program with each well anticipated to be comprised of a 2,000m horizontal well with 40 fracturing stages. Gas would be supplied to existing pipeline infrastructure to the NGP or Amadeus networks as well as produced liquids being trucked to Darwin for further processing and separation.

The commercial potential of the Beetaloo Basin has been modelled to indicate a break-even gas price of $9/GJ for shale gas supplied to the market for mid estimate supply of 9.2 Tcf of commercially viable gas. If gas prices rise to AUD$12 / GJ then potentially far more gas becomes commercially viable
(63.3 Tcf). The development of the Beetaloo Basin is largely considered to be conducive to new LNG export infrastructure in the Northern Territory or backfill for the existing Darwin LNG liquefaction plant.
Development of the Beetaloo Basin will require significant investment, as it is a truly frontier basin with limited existing infrastructure, exploration or appraisal activity.

Estimates of time to first gas from a Beetaloo Basin development are beyond the 10-year
mark, and it is expected that development of the Bowen Basin could be achieved much
more quickly than the Beetaloo.

Galilee Basin
The Galilee Basin is a region in central Queensland situated between the Bowen and Cooper Basins. It is currently home to a number of coal mines and is prospective for unconventional gas, both in underground reservoirs and in the form of coal mine methane. The exploration of the region is in its early stages; however volumes of gas are anticipated to exist in the region due to its geological setting and similarities to its neighbouring basins in the Bowen and Cooper regions.

The Galilee Basin has several granted coal mining leases to Adani Mining Pty Ltd for their Carmichael project as well as numerous applications by a number of other proponents of the Basin totalling 1.5% of the Basin’s geographical area. The Carmichael Mine was initially proposed as the largest coal mine in Australia; however it has been scaled back to a 10Mtpa project which is anticipated to begin production by the end of 2021.
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The Galilee Basin is prospective for gas; however it is anticipated to be relatively high cost due to sparse deposits – although more exploration is required. The infrastructure in the Basin is very limited, and it is not effectively linked to the ECGM by pipeline. Rail and transport infrastructure is also extremely limited, although a rail corridor has been planned and is supported by existing policy measures (the
Galilee SDA) to support the provision of Galilee coal to the Abbot Point Coal Terminal in North
Queensland. Substantial investment is needed in infrastructure, exploration, and development before the Galilee can be considered as a viable supply competitor to the Bowen.

Narrabri gas project
The Narrabri gas project is a Santos project which has recently gained appropriate approvals for the development of natural gas reserves in Narrabri in northern NSW. This project is anticipated to supply
NSW domestic demand via existing pipeline infrastructure on the Moomba to Sydney line through the construction of a linking pipeline constructed by the APA Group. The project has attained approval from the federal environmental minister with work on the project having commenced in 2021. This comes after 10 years of political debate due to the controversial fracking methods which will be used to access gas from local basin water. The gas produced will be through hydraulic fracturing of deep (500-1200m) coal seams.

If approved, the Narrabri project is considered to have the potential to produce 200 TJ/d of gas from up to 850 individual wells. However, with projected supply deficits on the horizon, the market is anticipated to be adequate to service both supplies concurrently. The project is anticipated to cost approximately
AUD$3.6Bn and will have a project life of 20-25 years. It will directly compete with potential supplies of gas from the Bowen basin for the southern ECGM market. If approved, the project will supply half the demand for gas in NSW.

Although the project has been approved by both state and federal planning authorities, legal proceedings are underway as the decision is being appealed in the Land and Environment Court. The appeal is being brought to bear by local landholders and environmentalists on the grounds that regulators were ‘legally irresponsible’ for approving the project. The appeal claims that the Independent
Planning Commission (IPC) did not adequately consider the effect of greenhouse gas emissions, however Santos's legal defence has argued that the IPC was reasonable in its decision. While this appeal is still in the court system, the project is paused awaiting a result and hence production is delayed indefinitely.

5.5.2 LNG import
A number of LNG import terminals are proposed along the east and south-eastern coastline of Australia.
The purpose of these proposed LNG import terminals is to provide alternate sources of gas supply to attempt to fill projected supply-demand gaps in the ECGM. Whilst the import terminals may be part of the solution that addresses domestic gas shortfalls, it remains to be seen if seasonal peaking use is economic when compared with further investment in onshore piped gas.

LNG import process
The LNG import terminals proposed in Australia will utilise Floating Storage & Regasification Units
(FSRUs), which are marine vessels used to warm LNG to return it to a gaseous state. Seawater is used for this warming, where the LNG and seawater are flowed through a tube and shell heat exchanger.
The difference in temperature between the inlet seawater and outlet seawater is initially about -7ºC, this then blends back to ambient temperature when the cooler seawater is discharged to the environment. Working at full capacity, it takes approximately six days to re-gasify a 170,000m3 cargo of
LNG.

The limiting factor for operation of an FSRU in Australia is the volume, temperature and chlorine content of the discharged warming water. The Port Kembla Gas Terminal, for example, has environmental

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conditions that will limit the discharge of warming water that effectively constrains its capacity to import
LNG to 130PJ per year.

The role of LNG imports
The advantages of importing LNG rather than transporting gas from northern producers include the ability to purchase LNG during the Northern Hemisphere’s summer when prices are lower and sell gas into the Australian winter market (when domestic prices are higher). This presents a competitive option to piped supplies that require storage in the southern storage facilities for use during peak periods of demand.

LNG import terminals play a role in supplying peak shaving gas into the ECGM during winter demand periods (see Figure 44). Given the forecasts provided by AEMO in the 2021 Gas Statement of
Opportunities (GSOO), there is likely to be sufficient demand for LNG import to support two terminals, potentially one in NSW (Port Kembla) and one in Victoria.

2,000 LNG import supply into
demand peaks
1,600

1,200
TJ/d

800

400

0
Jan-30 Feb-30 Mar-30 Apr-30 May-30 Jun-30 Jul-30 Aug-30 Sep-30 Oct-30 Nov-30 Dec-30
Southern production Transported via SWQP
LNG receipts Southern storage

Figure 44 – The role of LNG in addressing the supply-demand gap, 2030
(Source: AEMO & KPMG analysis)

Proposed projects
Several projects propose to supply gas via FSRUs at dedicated LNG import terminals. These projects include terminals at Port Kembla and Newcastle in New South Wales, Corio Bay and Port Philip Bay in
Victoria and Port Adelaide in South Australia:
Table 5 – Proposed LNG import terminal projects in the ECGM
(Source: KPMG analysis)
Port Port Corio Port Philip Crib
Newcastle
Kembla Adelaide Bay Bay Point
Viva
Proponent AIE IG Partners EPIK Vopak AGL
Energy

Capacity 275TJ/d 330TJ/d TBC 275TJ/d TBC 550TJ/d

Location NSW SA NSW VIC VIC VIC

Operational Operational
Project Approvals Approvals
by end by Oct Announced Cancelled
status pending by 2022
2022 2022

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5.6 The need for a new gas basin
The ECGM is a complex, interconnected network of physical infrastructure, commercial positions and regulatory frameworks.
Overall, forecasts consistently predict a shortfall of gas supplies There is clear potential for the into the market by the mid-2020s, starting with peak demand periods (winter) and extending to net annual shortfalls. This will Bowen Basin to be developed drive upwards pressure on domestic gas prices and downward pressure on consumption, and thus economic activity in
as a new upstream source of gas-intensive industries.
gas that, if connected to the
Various projects and initiatives are slated to address these forecast shortfalls; however no single project is a solution to the challenges ECGM, would help contribute identified in this report. There remains the strong possibility that there will be residual gas demand of several hundred terajoules per
to closing the projected gas day that could ultimately be filled by development of the Bowen
Basin. It is important to note that the Narrabri Gas Project is already
supply-demand gap.
included in AEMO’s supply-side modelling of ECGM gas supply, and still a supply-demand gap exists, as outlined in the above analysis.

As such, there is clear potential for the Bowen Basin to be developed as a new upstream source of gas that, if connected to the ECGM, would help contribute to a closing of the projected supply-demand gap.
Physical connection to the ECGM is not necessarily required, as directing Bowen Basin gas to export via the facilities at Gladstone would enable swap positions to be executed with gas shippers that are connected to the ECGM as the Bowen gas displaces ECGM gas that would otherwise have been exported.

Whilst other prospective basins exist and could also be developed to provide gas into the ECGM, the
Bowen Basin is considered to be in prime position to supply this shortfall due to the level of existing infrastructure, existing production and extensive exploration and appraisal activity. Based on analysis undertaken for this report, it is anticipated that the likely timeline for development of the Australia’s prospective basins may be:

1. Bowen Basin: 5+ years;
2. Beetaloo Basin: 10+ years; and
3. Galilee Basin: 15+ years.

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6. The Bowen Basin
6.1 Location
As illustrated in Figure 45, the Bowen Basin extends southwards from Collinsville (near Bowen) to
Emerald and Moura (west of Bundaberg). Its area is put at 60,000 to 75,000 sq km, over a length of approximately 650 km. The Basin is shaped like an inverted Y: the single stem of the Y runs from
Collinsville to Dysart, a land corridor seldom wider than 50 km, where the majority of mines are worked.
The two subsidiary stems run south-west to Emerald and beyond, and south to Moura and Theodore.

As detailed in Section 2, the scope of this study is centred on the Bowen Basin, which forms an approximate triangle from
Collinsville in the north down to Theodore and inland towards Tambo in central
Queensland (Figure 10). The Bowen Basin, alongside the Surat, is Queensland’s largest gas and coal producing region and supplies a large portion of the LNG export and domestic gas along the East Coast.

The region contained within the Bowen
Basin intersects large swathes of prime agricultural land near Mackay. This region is predominantly used for cattle farming and other agricultural activities, such as the cultivation of sugar cane and other fruit, vegetable, and grain crops. This region is also home to several large coal mining operations which produce metallurgical and thermal coal, generally with extremely high grades.

Much of the local economy is reliant on mining activities in the coal, gold, and other metals industries as well as the pastureland for prime cattle. Ultimately, this region is relatively sparsely populated with several dispersed population centres and large mining operations making up the majority of activity.

Figure 45 – The Bowen Basin
(Source: NSAI Analysis)

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6.2 Geology
The Basin is home to several types of coal seams which have varying potential for gas. The Bowen
Basin contains three main Permian coal measures – the Rangal Coal Measures (RCM), the Fort Cooper
Coal Measures (FCM) and the Moranbah Coal Measures (MCM). The RCM are the shallowest seams in the Basin and have been extensively mined for coal along the eastern and western flanks where the coal is shallowest and typically, coal miners target coals that are less than 400m depth.
The Basin primarily contains sediments of Permian age deposited in fluvial, lacustrine, and deltaic settings. Minor marine influxes were also recorded. Most of the Basin's oil and gas discoveries to date are found along its southwestern margin, with the first commercial discoveries, the Timbury Hills and
Pickanjinnie gas fields, occurring in 1960. The MGP is located along the western flank of the Northern
Bowen Basin.
Permian-aged coal seams account for almost 80% of the coal in the State of Queensland. With four major coal measures of economic importance for coal mining, the Bowen Basin contains the state's most significant Permian coals. These measures, from youngest to oldest, are:
1. The Rangal/Bandana/Baralaba Coal Measures of Late Permian age;

2. The Late Permian Moranbah/German Creek Coal Measures;

3. The Collinsville/Blair Athol Coal Measures of Early Permian age; and

4. The Early Permian-age Reids Dome beds, present only in the southwestern corner of the Basin.

The North Moranbah underground coal mine, immediately to the west of PL 191, actively mines coal from the GM seam of the MCM. The MCM sub-crop immediately west of the mine area has unconformity under the shallow Cenozoic age cover, making them easily accessible to miners. The
MCM consist of sandstones, siltstones, shales, and coals with numerous seams and splits. RCM coals are actively mined in the Basin approximately 25 kilometres north of the Moranbah CSG project area at the Burton Mine.

CSG produced at Moranbah is sourced from the Goonyella Middle (GM) and P seams of the Moranbah
Coal Measures. Future production is likely from the Goonyella Middle Lower (GML) seam while the overlying Fort Cooper and Rangal Coal Measures have potential. Coal permeability in the Moranbah area is relatively low with production enhanced by in-seam drilling. Development has concentrated on seams around the 300m level to avoid the loss of permeability that generally comes with increasing depth.
The early data for this area are from numerous wells drilled by several coal companies to establish the location of coal seams and the viability of mining these coals. Initially, log data from these early wells were generally not available, but detailed schematics of the lithologies and formations encountered with depth were provided. The correlations in these schematics were then verified with well logs.
CSG prospective development has only been evaluated in this study for the RCM and the MCM. To date, economic CSG production has been established from the MCM and the RCM. However, promising gas content measurements have also been found in additional seams which may provide attractive drilling targets for future additional methane resources.

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Fort Cooper Coal Rangal Coal

Moranbah Coal

Figure 46 – Indicative cross section of Bowen Basin coal seams
(Source: Arrow Energy EIS, 2012)

6.3 Key Stakeholders
The Bowen Basin has over 40 active coal mines, two gold mines, producing gas fields and a range of gas and coal exploration and appraisal activities. As a result of this activity, the Bowen Basin contains a diverse range of key stakeholders from resource companies, government organisations, utilities providers and gas-intensive manufacturing and power generation assets. Figure 47 is a summary of the major stakeholders with interests in the Basin:

Figure 47 – Key stakeholders in the Bowen Basin
(Source: KPMG analysis)

6.3.1 Coal Seam Gas proponents
There are three major CSG proponents with active positions in the Bowen Basin; Arrow Energy, Blue
Energy, and a joint venture between WestSide and Mitsui E&P, which have interests both in coal and in gas.

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Arrow Energy
Arrow Energy Holdings Pty Ltd is a 50/50 joint venture between
PetroChina and Shell which has been operating in the Bowen
Basin since 2004. Arrow has a significant landholding in the
Bowen Basin via its wholly owned subsidiaries BNG (Surat) Pty
Ltd, Bow CSG Pty Ltd, and CH4 Pty Ltd, which hold Authorities to Prospect (ATPs) and Petroleum Leases (PLs) in the region.
Arrow Energy has the most expansive land interests in the region. They are currently the only operating gas producer in the
Study area, courtesy of their Moranbah Gas Project supplying gas north to Townsville. Arrow Energy’s activities in the Bowen
Basin include:

The Moranbah Gas Project a 50/50 joint venture with AGL
Energy, which has a greater presence in the south of the Bowen
Basin and in the Surat Basin. This project has been operating since 2004 and remains stable, supplying Townsville Power
Station and industrial customers in north Queensland.

The Bowen Gas Project (BGP), where Arrow Energy proposes to develop CSG resources in an area of approximately
800,000Ha. The BGP includes the proposed Arrow Bowen
Pipeline connecting Moranbah to the Gladstone LNG projects which is subject to separate approval processes.
Figure 48 – Arrow Energy ATP and PL holdings
(Source: KPMG analysis)

Blue Energy
Blue Energy Ltd is an oil and gas exploration company with a significant land interest in the Bowen Basin being held by its wholly owned subsidiary Eureka Pty Ltd. Until mid-2018,
Queensland Government-owned Stanwell Corporation Pty Ltd owned a 7.7% stake in Blue Energy.

Blue Energy’s holding in the north of the Basin is ATP814. This
ATP consists of seven disconnected blocks ranging from south of
Moranbah up to Glenden. Blue Energy does not have any PLs in the area, because its activities are currently only exploratory.

Blue Energy’s activities in the region include:

• Taking advantage of Arrow Energy’s existing CSG production
at its Moranbah Gas Project in the vicinity of ATP814 to
advance its own commercialisation strategy. Drilling by Arrow
and other adjacent operators to ATP814 has taken place,
conferring currently uncontracted CSG reserves to Blue
Energy.

• Blue Energy is the proponent of a gas pipeline from its ATP814
tenement in the Bowen Basin to Gladstone/Wallumbilla.

• 1,116 km2 of exploration permits including CSG wells, ~71 PJ
Figure 49 – Blue Energy ATP holdings
of 2P reserves and ~298 PJ of 3P reserves.
(Source: KPMG analysis)

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WestSide / Mitsui E&P
Westside Pty Ltd is an oil and gas explorer and producer operating in Australia and New Zealand. It holds significant land interests in the Bowen Basin with its partner Mitsui E&P Australia
Pty Ltd.

Westside’s landholdings in the region are expansive. It operates the Greater Meridian Gas Fields, the closest gas fields to export facilities at Gladstone. It also has landholdings in the south of the
Basin, where it is expanding its current activities in partnership with Australia Pacific LNG (APLNG). Westside and APLNG hold
PL tenements south of Emerald.

Westside’s current operations in the region include:

• Exploratory activities in its ATP688 tenement, north of
Moranbah. Multiple exploratory wells have been drilled on
the site and Westside intends to perform further testing to
capture gas and water production data to evaluate the
prospects of the field. This tenement is in the vicinity of the
Moranbah to Townsville pipeline so presents a significant
commercial opportunity.

• Currently producing 40 TJ/d, connected to GLNG pipeline and
the QGP in the Meridian Project.

There are also a variety of smaller CSG proponents in the Basin, ranging from small holdings held by large multinationals, to Figure 50 – WestSide/Mitsui ATP & PL holdings
(Source: KPMG analysis) exploration prospects owned by smaller companies.

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6.3.2 Coal mining proponents
The Bowen Basin is Queensland’s largest coal mining region, producing large quantities of high grade metallurgical and thermal coal for export and domestic use. Coal mines exist across the Basin, from
Collinsville in the north to the very south of the Basin near the New South Wales border (Figure 51).
Notable coal miners with operations and acreage in the Basin include Glencore, Peabody, BMA/BMC and Anglo American.

Figure 51 – Current coal mining operations in the Bowen Basin
(Source: QLD Government (2010). Central Queensland Coal. Department of Employment, Economic Development, and
Innovation)

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Glencore
Glencore PLC is a global commodity trader and mine operator with operations across the country from the
Pilbara to Mt Isa and the Bowen Basin. Glencore is
Australia’s largest coal producer and has a large interest in the Bowen region with three major metallurgical coal operations in the northern portion of the Basin.

Glencore’s operations in the Study area include:

• The Newlands Complex is an open pit and
underground complex producing steaming and
metallurgical coal with a production capacity of
approximately 5.5Mtpa and a mine life of around
five years.

• Collinsville Mine is also an open pit and
underground complex mine producing both
metallurgical and thermal coal. Production capacity
of Collinsville is around 3Mtpa and has an expected
mine life of 20 years.

• Hail Creek is a high-quality open pit Metallurgical
coal operation with an annual production capacity of
approximately 5.5 Mtpa and an anticipated mine life
extending to 2040. Figure 52 – Glencore operating assets
(Source: KPMG analysis)

BHP Mitsubishi Alliance /BHP Mitsui Coal
The BMA (BHP Mitsubishi Alliance) and the BMC (BHP
Mitsui Coal) are subsidiaries of the BHP and Mitsubishi and Mitsui mining organisations. BMA is owned 50-50 by BHP and Mitsubishi and is the largest exporter of metallurgical coal in Australia. BMC is owned 80% by
BHP and 20% by Mitsui. They operate multiple mines in the Bowen region as well as a substantial coal export terminal south of Mackay at Hay Point.

Their assets in the Study area include:

• Blackwater is an open pit mine producing both
metallurgical and thermal coal with a mine life of 20
years as of 2020. Blackwater has a production
capacity of approximately 13.5 Mtpa and is owned
by the BMA joint venture (JV). Blackwater is one of
the largest coal resources in the world with 860
million tonnes of proven reserves.

• Goonyella Riverside Broadmeadow is owned by
the BMA JV and is an open pit and underground
mining complex with a 40-year mine life and
production capacity of 16 Mtpa of both thermal and Figure 53 – BMA/BMC assets
coking coal. (Source: KPMG analysis)

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• Caval Ridge metallurgical complex (UG/OP) is owned by the BMA JV and has an annual production
capacity of 5.5 Mtpa.

• Daunia open pit mine can produce 4.5Mtpa of metallurgical coal and is expected to achieve a
21-year Life of Mine (LOM) from 2013 indicating a remaining LOM of around 13 years.

• Peak Downs is an open pit metallurgical coal mine producing 9 Mtpa and is owned by the BMA JV.

• Poitrel open pit mine is owned by the BMC JV and produces approximately 2 Mtpa of metallurgical
coal.

• Saraji is an open cut coal mine owned by BMA and produces approximately 2.5 Mtpa of
metallurgical coal.

• South Walker Creek open cut mine is operated by BMC and produces approximately 2.5Mtpa of
coking coal.

Peabody
Peabody is a global coal producer with operations across the United States and Queensland and NSW in
Australia. Peabody’s share of coal mined at their operations was 4.5 Mt in Queensland in 2019 from their Bowen Basin project. They are the fifth largest coal producer in Australia producing both metallurgical and thermal coal.

Peabody’s projects relevant to the Study area are:

• North Goonyella is owned by Peabody and is a
1.6Mtpa coking coal open pit mine.

• Coppabella is jointly owned by Peabody, CITIC
Resources, Marubeni, Sojitz, Nippon Steel, and
other investors and produces 2.2Mtpa (100%
basis) from an open pit operation.

• Moorvale is part of the Coppabella joint venture
and is hence owned partially by Peabody. This
mine produced 1.6Mtpa (100% basis) in 2019.

• Millennium an open pit and underground mine is
owned by Millennium Coal Pty Ltd. Which is a
subsidiary of Peabody. It currently produces Figure 54 – Peabody Bowen Coal Assets
approximately 2Mtpa but is planned for expansion (Source: KPMG analysis)
to 5.5Mtpa. It was expected to close in 2020
however was expanded to a mine life of around
seven years and recently sold to MetRes which
also purchased the Mavis Downs Mine.

• Middlemount is an open pit mine owned 50% by Peabody and 50% by Yancoal and produces
approximately 2.9 Mtpa (Peabody share 1.45Mtpa) of thermal and coking coal.

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Anglo American
Anglo American is a multinational coal company with a focus on metallurgical coal and has three underground coal mines and two open cut operations in the Bowen Basin. Anglo American also has a number of key JV partnerships and growth projects in the region.

Anglo American’s operations in the Study area are:

• Capcoal is a combination of the Capcoal open
cut mine and the Grasstree underground
longwall mining operation. Together these
make up Capcoal which is a coking coal project
capable of producing 15Mtpa from a region
near Middlemount.

• Dawson is an open cut mine producing coking
coal operated by Anglo American which has a
controlling 51% interest in the project which is
held in partnership with Mitsui Holdings. This
mine has been producing since 1961 and now
has an annual production of 4Mtpa.

• Moranbah North is an underground longwall
mine producing metallurgical coal from the
Goonyella seam with a mine life of 15 years.
Anglo American owns 88% of this operation
with 12% owned by a variety of other JV
Figure 55 – Anglo American coal assets
partners. Moranbah North produces
(Source: KPMG analysis)
approximately 8Mtpa.

• Moranbah South is a 50:50 JV between Anglo and Exxaro in the North Bowen. This project
achieved Government approval in 2014 and is anticipated to be developed into a new underground
longwall operation within the next 10 years.

• Grosvenor is an underground longwall coal mine which commenced operations in 2016 and is
anticipated to achieve a mine life in excess of 30 years. It is located approximately 200Km
south-west of Mackay and produces approximately 7Mtpa of coking coal.

• Aquila is a metallurgical coal project in the approvals stage and is intended to be a longwall
underground mine wholly owned by Anglo American.

6.4 Comparing the Bowen & Surat Basins
Most important are the geological differences between the two basins. These geological differences impact the potential for development across the Bowen and make the development scenarios vary from what has been demonstrated in the much more developed Surat Basin developments. The major geological and productivity differences between the two basins include:

• Thicker coal seams, in conjunction with lower permeability in the Bowen Basin, allowing for
horizontal well development to contact more of the coal surface. Horizontal well development has
been used for several years in the Bowen and there is confidence that this method can be continued
going forward. The cost of horizontal development is higher than vertical well development;

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however due to the tighter coals in the Bowen Basin, horizontal wells will be required to reach the
forecasted plateau rates.

• The Bowen Basin has four to six coal seams versus the 40 or more in the Surat Basin, and the
Bowen coal is generally thicker than the Surat, meaning it can be developed with horizontal wells.
A general rule based on economics would be to target seams 2m in thickness or greater with the
horizontal wells.

• The Bowen coals also have steeper dips than the Surat coals, which creates narrow fairways of
potential production. As an example, the Bowen may only be 5-10 productive locations wide versus
50 locations wide in the Surat. In addition, the Bowen has more faults and geologic unknowns than
the Surat, resulting in greater variability of coal across the basin.

• The Bowen coals have lower permeability than those in the Surat. As a result, the Bowen coals
produce both gas and water at lower rates, with lower individual well productivity. This results in
the need for a greater number of wells, or longer horizontal wells, and thus incurs higher capital
and operating cost for the same amount of gas produced.

• The Bowen coals generally have a higher gas content in the coal seams compared to the Surat. This
is a positive, as it can require less coal contacted to produce more gas. However, as mentioned
above, the higher gas content is often offset by the lower permeability, so whilst more gas exists
for a given foot of coal contacted, the flow rates may still be lower than a similar foot of coal in the
Surat.

Given the above commentary on the subsurface, the way the Bowen Basin will develop will be materially different to what occurred with the three CSG to LNG projects in the Surat Basin that were mostly developed over the last decade. The CSG to LNG projects were the largest coal seam gas developments globally, with many billions invested into wells and upstream production infrastructure, as well as some of the largest gas transmission pipelines developed in Australia. In contrast, the development of the Bowen Basin is expected to be more like the gas infrastructure that exists in the northern part of the Basin, replicated with a southern pipeline and gas gathering and production facilities that are of a similar scale to that at Moranbah.

As a result of these differences, the Bowen Basin is generally accepted to be a more difficult and more expensive play than the Surat Basin, reflected by the fact that Surat Basin acreage, and not Bowen, was developed to supply gas to the Gladstone LNG plants.

6.5 Existing infrastructure
6.5.1 Transport
In addition to supporting the development of the Bowen Basin through the transport of goods and services, the transport network is fundamentally important to the social and economic function of the region. As illustrated in Figure 56, the Bowen Basin is currently served by a combination of road, rail, port and air assets.

Table 6 summarises the existing transport infrastructure’s baseline assessment and its capacity to facilitate the development of the Bowen Basin.

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Figure 56 – Queensland Bowen Basin Logistics Map – Major Transport Infrastructure
(Source: GHD analysis)

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Table 6 – Existing transport infrastructure
(Source: GHD analysis)

Current Standard /
Infrastructure Description Comments on Capacity
Capacity

Ports

Spare LNG liquefaction and
Existing large port facility with export capacity available, as at
20 wharves, predominantly least 1 train on Curtis Island is
used for coal (70M), LNG (23M) FY20/21 total throughput not currently utilised (equivalent
Port of Gladstone to ~600 TJ/d).
and alumina (6M) export, and 122M tonnes.
bauxite (17M) and petroleum Adequate import capacity for
(1M) import. construction materials and line
pipe.

Existing large port facility near FY20/21 total throughput
Bowen, for the export of coal. 30M tonnes, current Spare capacity currently for coal
Abbott Point
Expansion planned for Galilee export capacity 50M export only.
Basin coal. tonnes per year.

Existing large port facility,
40 km south of Mackay, for the FY20/21 total throughput Spare capacity currently for coal
Port of Hay Point
export of coal, consisting of two 46M tonnes. export only.
terminals.

Existing port facility, Annual total throughput
Insufficient capacity for import
predominantly used for coal, FY19/20 7.6M tonnes,
Port of Townsville of line pipe for construction. No
sugar and fertiliser export, and including 5.4M tonnes
facilities for export of LNG.
fuel import. export.

Existing port facility, with four Annual throughput
wharves, predominantly used FY20/21 3.2M tonnes, May have capacity for import of
Port of Mackay for coal and sugar export, and a 160 ships. Total capacity line pipe for construction. No
small percentage (~5%) approx. 6M tonnes per facilities for export of LNG.
breakbulk. year, up to 600 ships.

Key Roads

National Highway A1, extending
the length of the Eastern Bowen Wide single lane, fully Capacity available to support
Bruce Highway
Basin from Gladstone to sealed. additional traffic.
Townsville.

Peak Down Highway upgrade
projects are currently in progress
to accommodate increase in
traffic. Primary access route for
State Route 70, extending from
Peak Downs workers, fuel, machinery and
Mackay 280km southwest to Single lane, fully sealed
Highway other supplies to the coal mines
Clermont.
of the Bowen Basin. Hazards
include narrow two-lane highway
only, frequently used for oversize
loads, and fatigued workers.

Insufficient capacity to support
Gregory State Highway A7, from Mount
Single lane, sealed and additional traffic. Pavement
Developmental Surprise 900km southeast to
unsealed widening projects proposed by
Road/Highway Springsure.
TMR.

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Current Standard /
Infrastructure Description Comments on Capacity
Capacity

State Route 7, three separate Single lane. Only northern
Insufficient capacity to support
Fitzroy sections from near Taroom, section is fully sealed.
additional traffic. Upgrade to two
Developmental heading north to the Peak Middle section partially
lane sealed road required
Road Downs Highway near sealed, southern section
including bridge crossings.
Coppabella, totalling 454 km. mostly unsealed.

Insufficient capacity to support
Bowen State Route 77, from Bowen Single lane. Final 70km
additional traffic. Upgrade to two
Developmental 259km southwest to Gregory nearest to Belyando is
lane sealed road required
Road Development Road at Belyando. unsealed.
including bridge crossings.

State Route 11, from Peak
Single lane. Only the first Insufficient capacity to support
Suttor Downs Highway near Nebo,
68km until North Goonyella additional traffic. Upgrade to two
Developmental 167 km west to Bowen
mine near Elphinstone is lane sealed road required
Road Developmental Road near
sealed. including bridge crossings.
Belyando.

Has minimal capacity to support
State Route 60, from Gladstone additional traffic. Improved bridge
Dawson Highway 405 km west to Springsure via Single lane, fully sealed crossings and structures required
Rolleston to accommodate prospective
increase in fright traffic

Increased capacity between
State Highway A4, from Rockhampton and Gracemere.
Capricorn Highway Rockhampton 575 km west to Single lane, fully sealed However, majority of the
Barcaldine highway is single lane leading to
capacity constraints.

Multiple access roads to the
Bowen Basin Access Low standard unsealed
Basin ranging from 5 km to Suitable for exploration only.
Roads roads
100 km

Rail

There is some capacity for
Average total throughput
non-coal trains on the CQCN,
of ~232 million tonnes per
including livestock, passenger,
year (mtpa), predominantly
Connects Bowen Basin mines freight and light engine, as
Aurizon Central coal. Main lines e.g.,
with major ports including Abbot required by the Transport
Queensland Coal Blackwater to
Point, Hay Point and Gladstone. Infrastructure Act (1994).
Network (CQCN) Rockhampton to Gladstone
The network is mostly electrified. Potential to use spare capacity
and Moranbah to Mackay
for transport of construction bulk,
have 5-10 mtpa available
particularly pipeline construction
capacity.
materials.

Aerodromes

Sufficient capacity for handling
passengers and aircraft
~1M passengers per year
movements at present. It is
and 15,000 aircraft
Public airport, operated by forecasted that passenger
Mackay Airport movements, also has some
Mackay Airport Pty Ltd. numbers will be on the decline
cargo processing capacity,
and there is spare capacity
2,000m runway.
available with little capital
investment.

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Current Standard /
Infrastructure Description Comments on Capacity
Capacity

~500k passengers per year Sufficient capacity at present
Public airport, owned and
Rockhampton and 10,000 aircraft including planned terminal
operated by Rockhampton
Airport movements, 2,600m upgrades to improve passenger
Regional Council.
runway capacity.

CHRC are also responsible for
~250k passengers per year
Public airport, owned and several landing facilities, suitable
and 5,700 aircraft
Emerald Airport operated by Central Highlands for light aircraft, at Capella,
movements, 1,900m
Regional Council (CHRC) Dingo, Duaringa, Rolleston and
runway
Springsure.

~160,000 passengers per Capacity expansion needed for
Private airport, owned/operated year, 1,500m sealed future with prospective increase
Moranbah Airport
BHP Mitsubishi Alliance. runway suitable for Dash-8 in mining activities in the Bowen
Q400 aircraft, (74 seats) Basin

Capacity expansion needed for
1,500m sealed runway
Middlemount Private airport, owned/operated future with prospective increase
suitable for Dash-8 Q400
Airport Anglo American Coal in mining activities in the Bowen
aircraft, (74 seats)
Basin

When considering the need for transporting construction inputs required to support the development of the Bowen Basin, Table 7 summarises the limitations of the road, rail and port networks. As detailed below, road trains of up to 53.5m in total length may be used within Queensland to deliver dry bulk product to sites for either domestic and/or internationally imported freight from the two identified potential import gateways. However, break bulk product, such as tubing/pipeline, may be restricted to a Type 1 road train due to their long lengths.
Table 7 – Transport network limitations from product origin to site
(Source: GHD analysis)

Road network
Product
Train network Port infrastructure
origin
Dry bulk Break bulk (pipes)

International

Axle weight limit 25 t Supports direct calling of import and
Port of Road trains export vessels. Max vessel length up to
Type 1 road train Max train length of
Gladstone <53.5m 320m, max depth 18.8m, beam 55m,
1,800 m displacement 140,000 mt.

Supports direct calling of import and
Port of Quad road export vessels. Max vessel length
Type 1 road train n/a
Mackay trains 230m, max depth 13m, beam 33m,
displacement 55,000 mt.

Domestic

Quad road
Local area Type 1 road train n/a n/a
trains

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6.5.2 Utilities
Power
As illustrated below in Figure 57, existing high-voltage transmission infrastructure is prevalent in the
Bowen Basin, due to the existing established industrial users including coal mines.

Figure 57 – Queensland HV transmission network
(Source: AEMO)

Additionally, as highlighted in Figure 58, the Bowen Basin region has recently seen an increase in renewable power generation, with several large-scale projects also in the planning and design phases to come online in the near future. Refer to Table 8 for a detailed list of power generation in the region.

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HV Transmission (Powerlink)
Study Focus Area

Figure 58 – Power generation assets in the Bowen Basin region
(Source: Department of Resources, Queensland Government)

Table 8 – Power generation facilities > 200 MW in the Bowen Basin, including existing and proposed assets
(Source: GHD analysis)

Name Fuel Owner Year Capacity (MW) Status

NRG Gladstone Operating
Gladstone Power Station Coal 1976 1,680 Existing
Services

Bowen Renewable Energy Pumped
RE Partners 1,500 Proposed
Hub hydro

Stanwell Coal Stanwell Corporation 1993 1,460 Existing

Bowen Renewable Energy
Solar RE Partners 1,300 Proposed
Hub

Callide C Coal IG Power/Callide 2001 840 Existing

Callide B Coal CS Energy 1988 700 Existing

Bowen Renewable Energy
Wind RE Partners 500 Proposed
Hub

Clarke Creek Wind and Solar Under
Wind Lacour 450
Farm (Stage 1) construction

Lotus Creek Wind Farm Wind Epuron 450 Proposed

Smoky Creek Solar Farm Solar Edify Energy 450 Proposed

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Name Fuel Owner Year Capacity (MW) Status

Clarke Creek Wind and Solar
Wind Lacour 400 Proposed
Farm (Stage 2)

Broadsound Solar Farm Solar Hadstone Energy 355 Proposed

Clarke Creek Solar Farm Solar Pacific Hydro 350 Proposed

Clarke Creek Wind and Solar
Solar Lacour 315 Proposed
Farm (Stage 2)

Aldoga Solar Farm Solar Acciona Energy 250 Proposed

Rodds Bay Solar Farm Solar Renew Estate 250 Proposed

Raglan Solar Farm Solar Eco Energy World 240 Proposed

Comet Solar Farm Solar Hadstone Energy 235 Proposed

Renewable Energy
Gregory Solar Farm Solar 215 Proposed
Developments

Bouldercombe Solar Farm Solar Eco Energy World 200 Proposed

Water and Waste management
Due to the extensive development within the Basin, the extensive existing water and waste management infrastructure is expected to be sufficient to support the gas industry.

6.5.3 Upstream gas infrastructure
Existing upstream gas infrastructure assets are concentrated in the north of Moranbah, and in the southern extent of the Study area. The upstream gas infrastructure includes the Moranbah Gas Project
(MGP), the Westside production facility near Moura, and the Denison Gas production facilities in the
Denison Trough to the north of Rolleston.

The MGP has been in operation since 2004 and is the prominent gas infrastructure within the northern region. Key features include:

• Four compression trains, each with a four-stage gas fired reciprocating compressor;

• A rated capacity of 68 TJ/day, with historical data indicating that typical flow rates range
approximately between 25 to 30 TJ/day;

• Tri-ethylene glycol (TEG) package including TEG regeneration and an oily water separation system;

• Capability of compressing gas from 700 kPag to 13.0 MPag; and

• Raw gas supply to the MGP occurs via the adjacent Dyno Nobel Delivery Station which includes
separation systems, gas metering stations and pressure regulation facility.

Westside’s production facility near Moura is comprised of three central processing plants and three nodal compression stations. The nodal compression stations consist of inlet separation and compressions while the central processing plant consists of inlet separation, reciprocating compression, triethylene glycol (TEG) dehydration and coalescing filtration. The Moura Central
Processing Plant (CPP) has an estimated capacity of 16 TJ/day while the Dawson River CPP and TEG capacity is rated at 9 TJ/day. Westside’s production connects to the ECGM via a small pipeline that ties

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into the QGP near Moura and to the GLNG via a connection the GLNG Transmission Pipeline near to the connection into the QGP.

The Denison Gas production facilities in the Denison Trough to the north of Rolleston includes the
Rolleston Gas Plant and Yellowbank Gas Plant in the South. The Rolleston Gas Plant includes a Dew
Point Control Unit to remove hydrocarbon liquids from gas and compressor units for gas compression.
Furthermore, the gas plant hosts an inlet separation unit and water handling facilities. Additionally, the condensate loadout system has been upgraded along with the refurbishment of site offices and camps.
The Rolleston Gas Plant restarted in the year 2020 after being closed for approximately nine years.
Current gas production from the Denison Trough, which includes both north and south gas processing facilities, is estimated to be approximately 20 TJ/day with a forecast of 60 TJ/day in the near term. The
Denison Gas production connects to the East Coast Gas Market via a small pipeline that ties into the
QGP near Rolleston.

6.5.4 Gas pipelines
The major existing pipelines in the Bowen Basin region, and associated technical details are listed in
Table 9 and illustrated in Figure 59.

As shown in Figure 59, the existing pipelines are concentrated to the south, with some sparse gas infrastructure in the north, and limited infrastructure in the central region. This results in the large gas reserves in the region being unconnected to the ECGM.
Table 9 – Existing pipelines - Bowen Basin region
(Source: GHD analysis)

Pipeline Length / Diameter Total Capacity Owner Directionality / Route

North Queensland Gas 391 km Single
108 TJ/d Palisade
Pipeline (NQGP) DN 300 Moranbah to Townsville

435 km Single
Gladstone LNG (GLNG) 1430 TJ/d Santos
DN 1050 Wallumbilla to Gladstone

Queensland Gas Pipeline 627 km Northern: 145 TJ/d Bi-directional
Jemena
(QGP) DN 300 Southern: 37.2 TJ/d Wallumbilla to Gladstone

Australia Pacific LNG 530 km APLNG (Joint Single
1560 TJ/d
(APLNG) DN 1050 Venture) Wallumbilla to Gladstone

Wallumbilla Gladstone 543 km Single
Pipeline (WGP, formerly 1510 TJ/d APA
QCLNG) DN 1050 Wallumbilla to Gladstone

107 km Single
Denison Pipeline (DP) 30 TJ/d Denison Gas
DN 150 Turkey Ck to Arcadia (QGP)

Eastern: 340 TJ/d
755 km + 182 km
South West Queensland Western: 384 TJ/d Bi-directional
Looped – DN 400 & APA Group
Pipeline (SWQP) (summer) Moomba to Wallumbilla
DN 450
404 TJ/d (winter)

438 km Bi-directional
Roma Brisbane Pipeline
(RBP) Looped – DN 250 & Eastern: 210 TJ/d APA Group Roma (Wallumbilla) to
DN 400 Brisbane

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Figure 59 – Major existing pipelines in Bowen Basin
(Source: Queensland Government Open Data Portal (2020) https://www.data.qld.gov.au/dataset/queensland-mines-permits- current-web-map-service-json)

North Queensland Gas Pipeline
The North Queensland Gas Pipeline (NQGP), connecting Moranbah and Townsville, is the only transmission pipeline currently connected to the Bowen Basin.

The NQGP is comprised of a high-pressure pipeline from the Moranbah gas processing plant to the
Townsville Power Station, a lateral pipeline connecting the pipeline to the Stuart Industrial precinct, and delivery facilities at Yabulu and Stuart.

The mainline of the NQGP is 391 km in length and a diameter of DN300 (12 inch), with capacity to supply 108 TJ/d from the Bowen Basin to Townsville.

The NQGP is currently owned by Palisade, after changing ownership multiple times since its construction by Enertrade (formerly owned by the Queensland Government) in 2004. The pipeline is currently operated by EIM, a company jointly owned by AGL and Arrow Energy.

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The NQGP is a non-scheme pipeline under Part 23 of the National Gas Regulations, but previously had
Category 2 and Category 3 exemptions. The pipeline was therefore exempt from information disclosure provisions, and from publishing service usage information, service availability information and financial information. Although the Category 2 exemption was revoked in May 2021, reporting has not yet been published, and therefore there is a lack of transparency on current operating and spare capacity of the pipeline.

6.5.5 CSG water infrastructure
The existing CSG Water Infrastructure in the central Bowen Basin comprises water management infrastructure constructed to support the Moranbah Gas Project. The Moranbah Gas Project commenced operations in 2004 producing gas for the domestic market supplying to the Townsville
Power Station and industrial customers in north Queensland. To date, approximately 744 wells have been drilled with a network of approximately 180 kms of water gathering pipelines constructed from well heads to a network of eight lined aggregation dams. Water is transferred from the aggregation dams to two feed ponds to the 2 ML/d water treatment facility which is located at the Moranbah Gas
Processing Facility. Treated water is supplied to a standard, suitable for irrigation and use by the adjacent Grosvenor mine. Brine from the water treatment process is stored in two brine ponds.

6.5.6 Infrastructure baseline implications
Transport
Existing enabling infrastructure such as ports, roads, railways and airports in the Bowen Basin are well equipped contributing to the region’s economy and growth. There are five ports close to the Bowen
Basin which includes the Port of Gladstone accommodating 20 wharves predominantly used for coal,
LNG, alumina, Bauxite and petroleum imports and exports. Current throughput capacities of the ports in the vicinity of the Bowen Basin range from 3 million tonnes to 122 million tonnes with spare capacities for coal exports available at present. Some of the ports are potentially conducive to importing construction materials and line pipe.

With regards to access to roads and highways, the Bruce Highway is well connected and extends between Gladstone and Townsville thereby covering the eastern section of the Basin. The Peak Downs
Highway is primarily used by workers for heavy hauling of machinery and offering supplies to the coal mines. Other roads, such as Fitzroy Developmental Road and Bowen Developmental Road, may require upgrading to two lanes to support additional traffic and bridge crossings.

The coal rail network in the Bowen Basin is operated by Aurizon. The Aurizon coal rail network links approximately 50 mines present in the Basin with major ports such as the Port of Gladstone, Abbott
Point and Hay Point. With an average total throughput of approximately 232 million tonnes per annum of coal, there is additional capacity for non-coal trains to accommodate passengers, freight and construction equipment and materials.

Mackay Airport accommodates close to one million passengers every year and manages 15,000 aircraft movements along with cargo processing facilities. Comprising a runway length of 2,000 metres, the airport is capable of hosting small to medium sized aircraft, including cargo carriers. Several airports of leaner capacities, such as the Rockhampton Airport, Moranbah Airport and Middlemount Airport, offer improved connectivity within the Bowen Basin with some airports owned and operated by mining organisations.

Some of the limitations to transport networks include constraints on road train lengths, and weight and length limits on railway trains. Gladstone and Townsville ports are suitable for the supply of equipment and materials required for gas infrastructure development and have previously been used to import for resource projects in the Bowen Basin.

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Utilities
The baseline assessment of the utilities within the Bowen Basin indicates that it will be able to support development without significant upgrades to wastewater and waste management facilities. The electricity requirements for gas development are also sufficient, although may require additional local distribution to new sites.

There is a general consensus amongst the coal mine operators in the Bowen Basin that high voltage transmission infrastructure is quite pervasive, however, operators have alluded to the fact that access to power continues to be a barrier as power linkage between facilities and high voltage power networks remains a challenge in many areas of the Bowen Basin. Additionally, the Bowen Basin region has recently seen an increase in renewable power generation, with several large-scale projects also in the planning and design phases to come online in the near future.

Upstream gas infrastructure
New gas process facilities and expansion of existing gas process facilities, and associated well pads and gathering systems, would be required to process additional gas development in the Basin. The extent and timing of these would be dependent on the timing and success of exploration programs.

Expansion of existing facilities is the quickest way to increase gas production, however this would need to be sufficiently close to the new areas of gas production, otherwise it is more economical to develop new facilities in close proximity to the gas wells. Whilst the proximity is relative and based on several factors, as an indication, it could be considered that 20 km to 30 km is the likely upper range for proximity of gas wells to gas process facilities. At these distances, the gathering system would require some form of nodal compression, that is, where several wells collect into a central location and the gas pressure is boosted to enable the coal seam gas to be moved over longer distances.

Gas pipelines
New export pipelines are required to transport gas from the Bowen Basin to market locations. These pipelines are required to be designed, constructed, and operated in accordance with the relevant
Queensland Government legislation and to Australian Standard AS2885 Pipelines – Gas and liquid petroleum. Additionally, the gas export pipelines will be covered under the National Gas Law which regulates the commercial operation of pipelines in participating jurisdictions, which includes
Queensland.

These pipelines will be required to transport the gas at high pressure due to the significant distances involved. Typical gas transmission pipeline systems within Australia required flow rates to range from moderate flows to high flows.

Consideration should be given for an infrastructure corridor for pipelines and other linear infrastructure, from the Bowen Basin to the market connection locations.

CSG water infrastructure
The CSG water infrastructure required will be developed as part of the gas production facilities for new production areas and expanded as required within the existing facilities, should the existing gas production facilities be expanded. The water rates expected for the Bowen Basin are materially lower per well than that seen in the Surat Basin, therefore the relative scale of the CSG water infrastructure will be less that that seen in the Surat Basin. There have been various configurations used for CSG water infrastructure since the development of the Moranbah Gas Project, and it is expected that each gas production proponent will develop a configuration that suits their project requirements. The produced water management will need to comply with the requirements of the approved development plans for the petroleum lease, and it is noted that the requirements on management of CSG water have changed over time. Given the use of raw water within coal mining operations, it is expected that a reasonable percentage of produced water will be able to be beneficially used in mining operations.

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6.6 Socio-economic baseline
This section presents a baseline overview of the socio-demographics of the Bowen Basin and explores key themes, trends and outliers that may be relevant to consider in the context of any project impacts. The full baseline is provided in Appendix E.

As highlighted in Figure 60, the study area used to establish the baseline includes five local government areas (LGAs) which cover the Bowen Basin:

• Whitsunday LGA;

• Isaac LGA;

• Central Highlands LGA;

• Woorabinda LGA; and

• Banana LGA.

As detailed in Table 10, in 2020, there are estimated to be 86,636 residents across the study area, which represents less than 1% of the Queensland population. 3 The study area is home to larger shares of children (aged 0-15) and working-aged residents Figure 60 – Socio-economic study area
(aged 30-64) than Queensland, while conversely the (Source: (Queensland Treasury, 2021) area has a smaller share of young workers (aged 15-
29) and senior residents (aged 65+) than the Queensland average. 4

This reflects an ongoing trend throughout regional Australia whereby young people leave rural areas and relocate to larger, urbanised areas to access employment, education and social opportunities. It may also indicate that the study area supports a larger proportion of workers who are raising families.
Over the next 10 years to 2031, the study area is expected to grow at an average annual rate of 0.7%, which is slower than the state average of 1.7%. 5

Most of the residents in the study area are located in Whitsunday LGA and Central Highlands LGA
(41.5% and 33.2%, respectively), indicating larger labour forces to support industry activity. Whitsunday
LGA contains the urban areas of Airlie Beach-Cannonvale and Bowen (9,334 and 8,851 residents, respectively), which are both located on the coast approximately 70 km outside of the Bowen Basin. 6
As such, these urban areas tend to support the established tourism sector (discussed below). The other urban areas of significance across the study area include Emerald in Central Highlands LGA, Moranbah in Isaac LGA, and Biloela in Banana LGA (13,529, 8,334 and 5,724 residents, respectively). 7 These are located within the Bowen Basin in close proximity to mining tenements and are more likely to support mining workforces. As such, workers for project construction are likely to be sourced from these towns.

3 ABS.Stat, 2021, ERP by LGA (ASGS 2020)
4 ABS, 2016 Census
5 Queensland Government Population Projections, 2018 edition (medium series).
6 ABS, 2016 Census
7 ABS, 2016 Census
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Woorabinda LGA is an Aboriginal Shire which encompasses a small geographical area (390km2) of non-contiguous land and a small population (995 residents; 1.1% of the study area). 8,9 Woorabinda Shire has a significant Indigenous population (94.1%).

The study area has higher labour force participation rates 10 compared to Queensland (73.1% vs. 52.1%), as illustrated in Table 10. 11 The unemployment rate in the study area is lower than the state-wide average (4.5% vs. 7.3%).

Table 10 – Demographic summary
Indigenous
Labour Participa- Unemployed Unemploy-
Estimated Resident Share of Total
LGA force tion rate persons ment rate
Population (2020) Population
(2021) (2019)* (2021) (2021)
(2016)

Whitsunday 35,927 41.5% 4.9% 21,366 66.7% 1,425 6.7%

Isaac 20,987 24.2% 3.6% 12,987 76.6% 264 2.0%

Central
28,727 33.2% 4.3% 17,131 77.7% 717 4.2%
Highlands

Woorabinda 995 1.1% 94.1% 592 87.2% 43 7.3%

Banana 14,065 16.2% 4.1% 8,412 74.8% 297 3.5%

Study area 86,636 100% 5.2% 60,488 73.1% 2,746 4.5%

Queensland 5,176,186 4.0% 2,713,872 52.1% 197,348 7.3%

*Participation rate for working age population 15 years and older.
Sources: ABS.Stat, 2021, ERP by LGA (ASGS 2020), 2001 to 2020; Australian Government’s Small Area Labour Markets (SALM) publication,
March Quarter 2021; ABS, 3235.0 Regional Population by Age and Sex, Australia, June 2019.

In 2016, 98,000 residents in the study area were employed. Whitsunday LGA employs the largest number of local residents (33,782 workers; 34.5%) while Banana LGA employs the fewest (14,315 workers; 14.6%), except for Woorabinda LGA. As demonstrated Figure 61, the most common industry of employment was Mining, employing approximately one in five workers across the study area (20.4%;
9,122 workers) – significantly higher than the Queensland average (2.4%). This highlights that within the study area, mining represents a large industry specialisation, especially in Isaac LGA (38.7%; 3,759 workers) and Central Highlands LGA (25.2%; 3,269%). Within the Mining industry, Coal Mining employs the majority of workers (8,309 workers), while Oil and Gas Extraction employs the fewest (95 workers).

Other major industries by employment in the study area include Agriculture, Forestry and Fishing
(12.6%), Accommodation and Food Services (9.6%) and Retail Trade (8.1%) in terms of employment, as shown in Figure 61. While Isaac LGA and Central Highlands LGA mainly support mining, Banana LGA specialises in Agriculture, Forestry and Fishing and Whitsunday LGA specialises in Accommodation and
Food Services, which is a hallmark for tourism activity.

8 ABS, 2019, 3218.0 Regional Population Growth, Australia 2018
9 ABS.Stat, 2021, ERP by LGA (ASGS 2020), 2001 to 2020
10 Aged 15 and over
11 ABS, 3235.0 Regional Population by Age and Sex, Australia, June 2019
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Mining

Agriculture, Forestry and Fishing
Whitsunday (R)

Accommodation and Food Services Isaac (R)

Retail Trade Central Highlands (R)

Woorabinda (S)
Education and Training
Banana (S)
Health Care and Social Assistance
Core Study Area

Construction Queensland

Transport, Postal and Warehousing

Public Administration and Safety

Other Services

0% 10% 20% 30% 40%
Proportion of local workforce
Figure 61 – Top ten industries by employment, place of usual residence
(Source: ABS, 2016 Census)

6.6.1 Socio-economic implications
The existing socio-economic profile of the Bowen Basin presents a challenge for the development of the Bowen Basin and the continued prosperity of the region. The demographic profiles reflect the ongoing trend throughout regional Australia, whereby young people leave rural areas and relocate to larger, urbanised areas to access employment, education and social opportunities. Coupled with lower-than-average population growth, higher-than-average labour force participation rates 12 and lower unemployment rates, it suggests that the Bowen Basin has limited latent capacity to support a construction workforce for new projects.

12 Aged 15 and over
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7. Bowen Basin production scenarios
The development scenarios for the Bowen Basin are based on the potential productivity of the coals in the Basin, and the economic recovery of reserves from those coals. The assessment has been informed by publicly available data. It is noted that significant explorative works have been undertaken by proponents in the study area, however, due to commercial confidentiality reasons, this information has not been used in the formation of the productivity scenarios. In lieu of industry data, testing of the productivity scenarios with industry has formed a critical input into the Study to ensure confidence in the results.

A model was developed that calculates the economic production of a single well with properties based on a number of inputs, then scaled to a whole-of-basin scenario by stacking individual wells to achieve a full field development profile.

The outputs of this model include a range of full field development production profiles for both gas and water, and the number of wells required to achieve that production. From this, infrastructure requirements, capital and operating costs can be developed to determine potential development pathways for the Basin (refer Section 9 for infrastructure details).

7.1 Production model inputs & assumptions
The development scenarios used for this Study have been informed by publicly available data that are layered with assumptions based on NSAI’s experience of over two decades of technical work in the
Bowen Basin. NSAI started the process by creating type curve forecasts to represent typical well production over the life of an individual development well in the Bowen Basin. The type curves were calibrated to actual production that has been released publicly on a per well basis, in addition to NSAI’s knowledge of how Bowen Basin’s CSG wells perform over time. There is a range of coal properties across the Basin that can affect the production rates of the coals, and NSAI have attempted to capture the wide range of outcomes with the different rates and plateau times. As a result, 12 type curves were modelled to incorporate four peak production rates as well as three plateau periods.

7.1.1 Natural gas price
The natural gas prices used to define the revenue-side of the model are taken from the analysis outlined in Section 4.2.3. The central mid-price scenario has been used to model the base case scenario as the mid-point average gas price.
Table 11 – Wellhead gas price cases
(Source: KPMG Analysis)

Case Value

Low price $5.00 / GJ

Mid price $7.00 / GJ

High price $9.00 / GJ

7.1.2 Production economics
In order to simulate the economic viability of an individual well, a model was created that incorporates capital expenditure, operational expenditure, revenue and taxes for an individual well. The model then simulates production from the well based on the geological factors outlined in Section 7.1.3, and costs

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applied on a production volume basis. This then provides a Net Present Value (NPV) for the well at a range of hurdle rates (discount factors).

Well economic life
Two main assumptions underpin the economic model of an individual well:

1. The Petroleum Resource Management System definition of reserves includes the requirement
that all reserves must be economic and, therefore, gas price has a profound effect on the
volumes of reserves in the Bowen Basin. If gas volumes cannot be drilled, completed and
brought to market under a positive cash flow, they are not reserves.

2. As the gas volumes drop later in life, the economic limit will be reached and the wells will cease
to contribute reserves to the overall value. A well’s production is capped when the NPV of
the well drops to zero as production declines and operational expenditure exceeds revenue.

Well CAPEX
Three well capital cost cases (well CAPEX) have been used in the development of the production scenarios in order to test economic viability of the scenarios at different well cost price points.

In upstream coal seam gas development projects, well CAPEX is the most significant cost to the developer given the high number of wells required over the life of a project. CSG developments can typically require the drilling of thousands of wells, and so small changes in well CAPEX can have a significant effect on the viability of projects.

The three well CAPEX price points have been selected based on current known drilling technologies, the types of wells likely to be required in the Bowen Basin and the known drilling costs of existing developments.
Table 12 – Well CAPEX cases
(Source: NSAI analysis)

Case Value

Low cost $1 million / well

Mid cost $1.5 million / well

High cost $2 million / well

Well OPEX
Well OPEX has been estimated based on experience and knowledge of the Basin to be $72,000 per well per annum. This OPEX incorporates the operation, maintenance and periodic workover of active wells in the development scenario.

Water handling
Water content of Bowen Basin coals is significantly lower than in the Surat Basin, where the water handling infrastructure is a large cost component of CSG development. Based on expected water production volumes and known geological properties of the Bowen Basin coals, an average water handling cost of $1.00 per barrel of water has been included in well economic calculations. This cost includes the handling, treatment, disposal and/or re-use of produced water within the project area(s).

Revenue
Each well is assigned a revenue stream that applies the wellhead price of natural gas ($5.00, $7.00 or
$9.00 per GJ of production) to the total production of gas from that well. This is included in the well economic model as a monthly revenue stream based on monthly production volumes.

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Taxes
The well economic model incorporates a nominal operating expense to approximate production-based taxes, e.g. petroleum resource rent taxes. Production-based taxes are applied at an all-inclusive rate of
6.35% of gross well revenue, where well revenue is gas price ($ / GJ) multiplied by the individual well’s production (in GJ).

7.1.3 Geology
The Moranbah region (refer Section 7.3.2) currently produces gas from the MGP operated by Arrow
Energy Pty Ltd. and is limited to a market of 50 TJ of gas per day. The key targets for development in the Moranbah region are the Moranbah Coal Measures (MCM), Fairhill Coal Measures and Rangal Coal
Measures (RCM). Currently, gas is produced from the MCM and RCM. The Fort Cooper coals have little to no pilot data and therefore have not been included in this Study.

The Blackwater region (refer Section 7.3.2) has very little gas production and pilot data to assess potential for gas production in the key target zones. Subsurface mapping and regional geologic understanding show a narrow fairway requiring linear development. The key target zones in the
Blackwater region are the MCM, Fairhill Coal Measures, RCM, German Creek Coal Measures and
Burngrove Formation.

The Mahalo Region (refer Section 7.3.2) is a wider portion of the Basin with production on both sides.
The key target zones in the Mahalo region are the Bandana Coal Measures, Baralaba Coal Measures,
German Creek Coal Measures and Burngrove Formation. Current gas production in the south region is mostly from the Bandana and Baralaba Coal Measures.

Well productivity type curves
A number of individual well type curves have been developed based on existing knowledge of production, exploration and geology of the Bowen Basin across its various coal measures, geographical locations and coal properties, including permeability (refer Table 13 below). The basis for the modelled flowrates comes from data gathered from three main sources:

1. Press releases from developers, explorers and proponents over the course of Bowen
development that point to production levels within the ranges modelled;

2. The production and well data supplied by the Queensland Government on a biannual basis; and

3. NSAI’s experience within the Basin, which gives us confidence in the range.

The intent of the well type curves is to approximate the different productivities of the various coal measures in the Bowen Basin. After projecting the majority of all the active wells in the Basin, an internal understanding is gleaned of what these wells have produced under current conditions as well as what is realistic for future development.

Outlined in Table 13 below are the productivity cases used to generate the well type curves. Each well type curve is built up by combining a range of productivity variables:

• Ramp rates – have been assumed at six months for de-watering and reaching plateau production
for an individual well, based on NSAI’s experience in the Basin.

• Well productivity – three productivity cases have been defined based on NSAI’s experience in the
Basin, each of which were extensively tested with stakeholders that currently have exploration or
production in the Basin. The low, mid and high productivity wells (0.26TJ/d, 0.53TJ/d and 1.06TJ/d)
represent the range of coal types in the Basin and their varying productivity (due to different
permeabilities, gas pressures, geological features etc.).

• Production plateau length – three different durations were tested to analyse well economic life.
The three plateau lengths of two, four and six years represent the range of coal types in the Basin,
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their initial gas in place volumes and pressures, the ability to operate these wells at peak production
as a result, as well as how economic the wells remain as they decline.

Over 100 well type curves were calculated using the complete range of productivity variables in Table
13, and then combining them with the complete range of capital costs to drill and complete each well and the complete range of received gas prices.
Table 13 – Well productivity cases
(Source: NSAI analysis)

Ramp rate (time to Production plateau
Case Well productivity
reach plateau) length
2 years
Low productivity 6 months 0.26 TJ/d per well 4 years
6 years
2 years
Mid productivity 6 months 0.53 TJ/d per well 4 years
6 years
2 years
High productivity 6 months 1.06 TJ/d per well 4 years
6 years

Drilling technology
Individual drilling techniques and technologies have not been explicitly modelled in the production scenario development. Rather, well CAPEX and OPEX has been estimated based on known current drilling technologies, such as targeted surface-to-inseam horizontal well drilling.

Well CAPEX has not been adjusted over the life of the development to capture variables, such as:

• Improvements in drilling technology that improve productivity;

• Improvements in drilling technology that lowers well CAPEX;

• Process improvements, efficiencies of scale and scope that lower well CAPEX and OPEX over time;
or

• Escalation or inflation of costs that would increase well CAPEX or OPEX.

As the purpose of the scenarios is to provide comparative analysis of various scenarios, these variables are not considered material to the conclusions of the model and can be further explored in the subsequent phases of this Study.

Water production
Water production within the Bowen CSG development has been modelled for at 4,500 barrels a month peak rate and declining exponentially to a total volume of approximately 150,000 barrels per well. In the early development timeframe, we expect the water to take a more prominent role in the field. As the development matures, the volumes of water required to be produced before gas is released from the coals should be lowered. As more wells are drilled and the offset development drainage areas are de-watered, the continued development will support a reduced water volume overall. For the purposes of this exercise, we have assumed a consistent water volume for all development wells and have not assumed any benefit of Basin-wide de-watering.

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7.2 Individual well type curves
Using the variables and fixed properties outlined in Section 7.1 and the mix of production plateau lengths given in Table 13, individual well type curves were developed. An example of nine individual well type curves is shown in Figure 62 below. These nine curves represent nine different combinations of the variables given in Table 13 at a fixed well CAPEX of $1 million, and a received gas price at the wellhead of $7.00/GJ. This figure is illustrative of the well type curves.

High productivity well
1,200
• Plateau production rate
~1,000MSCFD (1.06TJ/d)
1,000 • 6-year production plateau
Mid productivity well
• 10, 15, 20 year well life
•
Production Rate (MSCFD)

Plateau production rate
800 Low productivity well
~500MSCFD (0.53TJ/d)
• 4-year production plateau • Plateau production
rate ~250MSCFD
600 • 10, 15, 20 year well life
(0.26TJ/d)
• 2-year production
400 plateau

200

0
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41
Year
Figure 62 – Illustrative individual well type curves
(Source: NSAI analysis)

Table 14 below tabulates the individual well type curves and whether economic gas production is considered feasible for this combination of assumptions and inputs.
Table 14 – Individual well productivity cases – economic production matrix
(Source: NSAI analysis)
Wellhead gas Well CAPEX Production Plateau Economic
Well productivity
price (AUD$ / GJ) (AUD) Duration (years) production
2 X
Poor 4 X*
6 X*
2 
$1 million Average 4 
6 
2 
$5.00 / GJ
Good 4 
6 
2 X
Poor 4 X
$1.5 million 6 X
2 
Average
4 

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Wellhead gas Well CAPEX Production Plateau Economic
Well productivity
price (AUD$ / GJ) (AUD) Duration (years) production
6 
2 
Good 4 
6 
2 X
Poor 4 X
6 X
2 
$2 million Average 4 
6 
2 
Good 4 
6 
All well type cases at a $1 million well CAPEX are economic for a
$1 million
$7.00 / GJ gas price
2 X
Poor 4 X*
6 X*
2 
$1.5 million Average 4 
6 
2 
Good 4 
$7.00 / GJ
6 
2 X
Poor 4 X*
6 X*
2 
$2 million Average 4 
6 
2 
Good 4 
6 
All well type cases at a $1 million well CAPEX are economic for a
$1 million
$9.00 / GJ gas price
All well type cases at a $1.5 million well CAPEX are economic for a
$1.5 million
$9.00 / GJ gas price
$9.00 / GJ
2 X
$2 million Poor 4 X*
6 

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Wellhead gas Well CAPEX Production Plateau Economic
Well productivity
price (AUD$ / GJ) (AUD) Duration (years) production
2 
Average 4 
6 
2 
Good 4 
6 
* Case is negative value at PV10, but does generate positive net revenue

7.3 Bowen Basin production scenario development
The individual well type curves were used as the basis for the modelling of a range of stacked well production profiles, generating a number of production scenarios to help determine whether there are economic scenarios that could help unlock the Bowen Basin. The development scenarios were run at a mixture of type curves to represent the coal variability across the three regions. We understand that the coal properties change and are not necessarily consistent from development drainage area to drainage area.

7.3.1 Stacked well productivity mixes
A number of different combinations of type curves have been stacked to achieve the targeted full field production plateau numbers outlined above.

Three production cases have been modelled – a low productivity case, a mid-productivity case and a high productivity case. These cases are made up of different mixes of individual well type curves as shown in Table 15 below.
Table 15 – Stacked well productivity mixes

Full Field Production Profile Case
Individual Well Type
Low Case Mid Case High Case

0.26TJ/d 50% 33.3% -

0.53TJ/d 50% 33.3% 50%

1.06TJ/d - 33.3% 50%

Average 0.4TJ/d 0.62TJ/d 0.8TJ/d

7.3.2 Regional segregation
As described in Section 6.1, the Bowen Basin covers a vast geographic area. Elongated in the north- south direction, the northern-most tip of the Basin is approximately 650 km from the southern-most tip.
Across this distance, the coal measures in the Basin vary considerably, as does the amount and quality of subsurface data (including seismic survey, exploration wells, appraisal wells and production wells).

The Moranbah region to the north has considerable data, with existing CSG production from the
Moranbah gas project operated by Arrow Energy.

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Whilst a highly active coal mining area, the central Blackwater region (from Moranbah in the north to
Blackwater in the south) has the least amount of subsurface data related to CSG resources.

The southern Mahalo region has been extensively explored, and there are projects advancing to the production stage.

As a result of the combination of varying levels of data (quantity and quality), and the several different coal measures within the Basin, the Bowen Basin production scenarios have been logically split into three main regions as outlined in Figure 63.

Moranbah

Blackwater region

Mahalo region

Figure 63 – Production scenario regions of the Bowen
(Source: NSAI Analysis)

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Moranbah region
The Moranbah region centres on production from existing PLs and ATPs in the regions north of the township of Moranbah, utilising the existing Moranbah Gas Plant (operated Arrow by Arrow Energy) and the North Queensland Blue
Gas Pipeline (operated by Palisade). Westside

The geology and productivity of the coals in this region are well understood, as CSG has been produced in this region since 2004.

Acreage in this region is predominantly held by Arrow Energy (currently producing from the Bowen Gas Project), Westside (currently exploring) and Blue Energy (in exploration and appraisal phase).

Whilst there is existing production in this region, challenging economics mean existing infrastructure is significantly under-utilised.

Figure 64 – Moranbah region scenario – area of production
(Source: NSAI analysis)

Blackwater region
The Blackwater region scenario centres on acreage held by Arrow Energy. This region of the Bowen Basin is the least explored and appraised section of the Basin and, as such, data quantity and quality is low.

Notwithstanding this, there are multiple major coal mines in this region, and so geological data exists that centres on coal production rather than gas. This has been used to develop the productivity model described in this report for the Blackwater region scenario.

Infrastructure to support gas development in this region is limited – currently no pipelines exist that could transport gas produced from this region to either Moranbah or the East
Coast Gas Market. To unlock this region of the Basin would require a large capital investment in this enabling infrastructure, as well as a much more detailed exploration and appraisal campaign to confirm its prospectivity for commercial CSG Figure 65 – Blackwater region scenario – area of production production. (Source: NSAI analysis)

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Mahalo region
The Mahalo region has numerous existing coal projects and some existing natural gas
ATPs and PLs.

The region is covered under the DAWE
(Department of Agriculture Water and the
Environment) as the Mahalo SDA and existing approvals for CSG production are in place, with some of the most recent being in 2019.

The Mahalo region currently has over 95 gas wells, existing pipeline and compression facilities, and water management equipment.

Coal operations have been under way in the
Mahalo region for decades and recently a precedent has been set for gas exploration activities with the Comet Ridge Mahalo gas project achieving full approvals.

Westside Corporation has a significant acreage position along the east side of the basin and produces approximately 40TJ per Figure 66 – Mahalo region scenario – area of production
(Source: NSAI analysis) day from the Meridian project.

Arrow and Blue Energy also have large acreage holdings in this region and a number of further exploration tenements awaiting approvals.

7.3.3 Production targets by region
For this analysis, reasonable production targets were identified for each region, based on NSAI’s experience in the Basin and confirmed through stakeholder consultation.

Moranbah region
In the Moranbah region, a target rate of 170 TJ of gas per day was used. Modelling indicates that this target can be achieved with drilling and completing 319 wells over the ramp-up phase of development.
The well count could include existing wells once prior volume commitments have been fulfilled. To continue the plateau of 170 TJ of gas per day, additional wells are drilled as needed over the next 15 to
20 years. It is assumed that 50 TJ of gas per day will be sent to the domestic market in Townsville, and the remaining 125 TJ of gas per day will be transported south via a new pipeline. It is noted that the
Moranbah region has several areas available for development with higher production potential than represented with the high case type curve wells, however the production model has been kept purposefully conservative given the concept level of this Study.

Blackwater region
The Blackwater region has the least amount of CSG production and pilot data and is considered to have the highest risk of development. A target of 70 TJ/day was used. Modelling indicates that this target can be achieved with 205 wells drilled and completed starting in 2030. Additional wells are drilled and completed as needed to maintain the 70 TJ of gas per day target over the next 15 to 20 years. This delay allows for further delineation and data gathering in the Blackwater region and also provides time to establish a firm gas supply in the Moranbah and Mahalo regions to provide economic support for pipeline investment.
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Mahalo region
In the Mahalo region, a target rate of 170 TJ of gas per day was used. Modelling indicates that this target can be achieved with drilling and completing 319 wells over the ramp-up phase of development.
To continue the plateau of 170 TJ of gas per day, additional wells are drilled as needed over the next
15 to 20 years. There are existing wells in the Mahalo region that could contribute to the total gas volume if prior volume commitments are fulfilled. The majority of gas volumes from this scenario are available for a pipeline going to southern markets via the ECGM. Similar to the Moranbah region scenario, the Mahalo region also has an area of development that the high-side type curve well could exceed.

7.3.4 Production timing and ramp rates
It will be necessary for drilling to start before any pipeline is ready to be able to load the line once it is ready and not have an extended period of little to no revenue for the pipeline. The ramp-up rates on a project basis (total number of wells) discussed below is related to current economics and the assumption of pipeline construction. The ramp up on an individual well basis is based on experience in the Basin and how the historical wells have de-watered. For the initial months of life, the wells produce mostly water with gradual increasing gas rates. It has been assumed that, if a market exists, the stakeholders will develop the wells to supply that market.

The number of wells that can be drilled in a certain timeframe is limited by the number of drilling rigs that can be deployed into the field, and the time taken to drill, complete and redeploy the rig for a single well. For the Mahalo region, there are also existing wells that can be incorporated into the ramp up to plateau quickly.

For the Moranbah region, the target rate is reached with a more prolonged build-up over two years by bringing on eight wells per month over that time period. It has not been assumed that existing wells will contribute to the total gas but, if they do, it will lower the number of wells required.

For the Mahalo region, there is an existing base of 208 wells that have been drilled and are ready to be brought into the system over the first six months. In addition to those wells, three wells per month are scheduled to come online to reach plateau and maintain the rate.

The Blackwater region brings on seven wells per month to reach the plateau. There are 169 wells drilled and ready to come online once the first years of linking in the Central area are reached.

7.3.5 Constructing a production scenario
A series of cases have been modelled using combinations of the above assumptions and inputs. In total, 108 cases were modelled and analysed.

The method for creating each case is outlined in Figure 67 overleaf. Fixed economic input assumptions, including well OPEX, water handling costs and tax costs, are combined with variable productivity,
CAPEX and wellhead prices to model a range of potential production scenarios.

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Figure 67 – Methodology for creating a development case
(Source: KPMG Analysis)

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7.4 Bowen Basin production scenario results
7.4.1 Scenario 1 – Moranbah region
Scenario 1, the Moranbah region scenario, involves the development of acreage in the north of the
Bowen Basin. This is an area with the most exploration, appraisal and production data and so production
figures presented in this report have high confidence.

The premise of Scenario 1 is to develop up to 200TJ/d of gas, sending approximately 50TJ/d northwards
via the existing Moranbah Gas Plant and the North Queensland Gas Pipeline, with the remaining
150TJ/d flowing south via new infrastructure to supply gas to the ECGM via Wallumbilla.

Depending on the productivity of the coals, between 699 and 1,348 wells are required at the peak,
with production of approximately 200TJ/d achievable for a plateau duration of approximately seven to
nine years (Figure 68).

High-Case
250 5,000
• 205TJ/d plateau
• 8-year plateau 4,500
• 699 wells at peak Mid-Case
• 1,133PJ total production
200 • 200TJ/d plateau 4,000
• 7-year plateau

No. of Active Wells
Production (TJ/d)

• 1,059 wells at peak 3,500
• 1,326PJ total production
150 3,000

2,500
Low-Case
100 2,000
• 197TJ/d plateau
• 9-year plateau 1,500
• 1,348 wells at peak
50 • 1,117PJ total production 1,000

500

0 0
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Figure 68 – Scenario 1 – Moranbah – gas production profiles
(Source: NSAI Analysis)

Water production in this scenario peaks at between 29kbwpd and 65kbwpd depending on well
productivity, with total water production over the life of the field expected to be approximately
132mmbw to 324mmbw (Figure 69).

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20,000 2,000
Mid-Case
High-Case
18,000 1,800
• 46kbwpd
• 29kbwpd at peak
• 699 wells at peak • 1,059 wells at peak
16,000 • 260mmbw total 1,600
• 133mmbw total production
production
14,000 1,400
Water production (bwpd)

Low-Case

No. active wells
12,000 1,200
• 65kbwpd at peak
10,000 • 1,348 wells at 1,000
peak
• 324mmbw total
8,000 production 800

6,000 600

4,000 400

2,000 200

0 0
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Figure 69 – Scenario 1 – Moranbah – water production profiles
(Source: NSAI Analysis)

7.4.2 Scenario 2 – Blackwater region
The Blackwater region scenario involves the development of natural gas infrastructure in the central portion of the Bowen Basin which is a narrow corridor of coal seams. This scenario would involve a production peak plateau of approximately 70TJ/day. This relatively low production target is due to the lack of current exploration and appraisal data of the coals in this region. Numerous regional coal players would also need to be engaged due to the potential overlap of interest between CSG players and existing mining leases/landholdings.

Depending on the productivity of the coals, between 240 and 632 wells are required at the peak, with production of approximately 80TJ/d achievable for a plateau duration of approximately seven to nine years (Figure 70).

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High-Case
90 • 85TJ/d plateau 2,500
• 7-year plateau Mid-Case
• 240 wells at peak
80 • 77TJ/d plateau
• 350PJ total production
• 9-year plateau
• 632 wells at peak 2,000
70
• 390PJ total production

60
Gas production (TJ/d)

No. active wells
1,500
50 Low-Case
• 80TJ/d plateau
• 7-year plateau
40
• 615 wells at peak
1,000
• 341PJ total production
30

20
500

10

0 0

Figure 70 – Scenario 2 – Blackwater – gas production profiles
(Source: NSAI analysis)

Water production in this scenario peaks at between 14kbwpd and 50kbwpd depending on well productivity, with total water production over the life of the field expected to be approximately
45mmbw to 110mmbw (Figure 71).

60000 Low-Case 2,500

• 50kbwpd at peak
50000 • 615 wells at peak
• 110mmbw total production 2,000
Mid-Case
Water production (bwpd)

40000
•
No. active wells
41kbwpd at peak
• 632 wells at peak 1,500
• 87mmbw total
30000
production
1,000
High-Case
20000
• 14kbwpd at peak
• 240 wells at peak
• 45mmbw total production 500
10000

0 0

Figure 71 – Scenario 2 – Blackwater – water production profiles
(Source: NSAI Analysis)
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7.4.3 Scenario 3 – Mahalo region
The Mahalo region scenario involves the development of the southern portion of the Bowen Basin to supply gas via pipeline to the ECGM through Wallumbilla.

This scenario is predicated on the development of many production facilities with substantial capacity and key production on both sides of the Basin. The highest production will be on the on the west side of the Basin in the (Greater Comet Ridge structure). The figure below illustrates the lower production rates and lower permeability coals on the east side (horizontal development), and the coals which do not outcrop in the far south (no colour-filled bands).

Depending on the productivity of the coals, between 643 and 1,365 wells are required at the peak, with production of approximately 180TJ/d achievable for a plateau duration of approximately 12 to 16 years (Figure 72).

200 5,000
Mid-Case
180 4,500
• 180TJ/d plateau
High-Case • 16-year plateau
160 • 180TJ/d plateau • 1,158 wells at peak 4,000
• 12-year plateau • 1,378 PJ total
140 • 643 wells at peak production 3,500
• 1,178 PJ total production
Gas production (TJ/d)

No. active wells
120 3,000

100 Low-Case 2,500
• 180TJ/d plateau
80 • 12-year plateau 2,000
• 1,365 wells at peak
• 1,161 PJ total production
60 1,500

40 1,000

20 500

0 0
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2040
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Figure 72 – Scenario 3 – Mahalo – gas production profiles
(Source: NSAI analysis)

Water production in this scenario peaks at between 29kbwpd and 65kbwpd depending on well productivity, with total water production over the life of the field expected to be approximately
132mmbw to 324mmbw (Figure 73).

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70,000 Mid-Case 5,000
• 59kbwpd at peak
Low-Case • 1,158 wells at peak 4,500
60,000 • 67kbwpd at peak • 260mmbw total
• 1,365 wells at peak production
4,000
• 323mmbw total
production
50,000 3,500
Water production (bwpd)

High-Case

No. active wells
• 30kbwpd at peak 3,000
40,000 • 643 wells at peak
• 133mmbw total
production 2,500
30,000
2,000

20,000 1,500

1,000
10,000
500

0 0
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Figure 73 – Scenario 3 – Mahalo – water production profiles
(Source: NSAI analysis)

7.4.4 Scenario 4 – A staged approach for Mahalo and Blackwater
regions
Scenario 4 combines both Scenarios 2 and 3 in a phased development approach. The Mahalo region would be developed initially, with a greenfield pipeline connecting the region to the ECGM. As the
Mahalo area is developed and pipeline capacity is increasingly utilised, the pipeline would be extended northwards to the central area of the Bowen Basin.

This approach has two advantages compared to Scenarios 2 and 3 on their own:

1. The ability to de-risk development of the central area of the Bowen Basin (between Blackwater
and Moranbah) by developing the Mahalo region first, with a lower CAPEX investment in
transport infrastructure and upstream development.

2. The ability to further appraise the central region of the Bowen Basin, given its current lack of
data related to CSG prospectivity. As the Mahalo region is developed, the central area could
undergo a reasonable appraisal program and a stage-gate decision on when, or if, to extend
the pipeline northwards could be taken based on this data.

Depending on the productivity of the coals, between 858 and 1,922 wells are required at the peak, with production of approximately 175TJ/d achievable during the first phase of development (Mahalo region), and 250TJ/d during the second phase of development (Mahalo region plus the Blackwater region) (Figure 74).

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300 5,000
High-Case Mid-Case
• 175TJ/d to 250TJ/d • 175TJ/d to 250TJ/d 4,500
• 858 wells at peak • 1,503 wells at peak
250
• 1,508PJ total • 1,758PJ total 4,000
production production
3,500
200
Gas production (TJ/d)

No. active wells
3,000
Low-Case
150 • 175TJ/d to 250TJ/d 2,500
• 1,922 wells at peak
• 1,490PJ total
2,000
production
100
1,500

1,000
50
500

0 0
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Figure 74 – Scenario 4 – Mahalo & Blackwater regions – gas production profiles
(Source: NSAI analysis)
Water production in this scenario peaks at between 33kbwpd and 92kbwpd depending on well productivity, with total water production over the life of the field expected to be approximately
177mmbw to 347mmbw (Figure 75).

100,000 5,000
High-Case Low-Case
90,000 4,500
• 33kbwpd at peak • 92kbwpd at peak
80,000 • 858 wells at peak • 1,922 wells at peak 4,000
• 177mmbw total • 431mmbw total
production production
Water production (bwpd)

70,000 3,500 No. active wells

60,000 Mid-Case 3,000
• 75kbwpd at peak
50,000 2,500
• 1,503 wells at peak
• 347mmbw total
40,000 2,000
production
30,000 1,500

20,000 1,000

10,000 500

0 0
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Figure 75 – Scenario 4 – Mahalo & Blackwater regions – water production profiles
(Source: NSAI analysis)

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7.5 Summary
The production scenarios modelled, based on the inputs and assumptions developed through our existing knowledge of the Bowen Basin, publicly available data and stakeholder feedback, result in a number of pathways to economically produce natural gas from multiple regions in the Basin, as shown in Table 16 below:
Table 16 – Summary of the Bowen Basin production scenarios

Production Plateau Total Production
Scenario Productivity Case No. Wells
TJ/d PJ

Low 205 1,348 1,117
Moranbah Mid 200 1,059 1,326
High 197 699 1,133
Low 80 615 341
Blackwater Mid 77 632 390
High 85 240 350
Low 1,365 1,161
Mahalo Mid 180 1,158 1,378
High 643 1,178
Low 1,922 1,490
Mahalo +
Mid 175 – 250 1,503 1,758
Blackwater
High 858 1,508

The actual pathways to development may differ from these scenarios as technology improves, costs reduce, and further exploration and appraisal programs are prosecuted (particularly in the central region of the Bowen Basin between Moranbah and Blackwater). However, it is clear from the analysis conducted that it is achievable to unlock production from the Basin in volumes that will provide meaningful additional gas supplies to the ECGM, consumers in North Queensland (particularly
Moranbah and Townsville) and potentially to the Gladstone LNG plants for export to trading partners in
Asia.

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8. Coal mine methane capture
Queensland’s fugitive emissions, the greenhouse gases emitted during coal mining or gas extraction activities, have increased significantly over two decades. The Queensland State of the Environment
Report (2020) confirmed that the outlook for gas and coal mining-based fugitive emissions was on the increase, and that fugitive emissions represented a sizeable portion of Queensland’s total emissions
(11-15%). As most of the associated emissions are methane, which has a higher greenhouse gas warming potential than CO2, the impact of the mining and gas extraction sector on the regional anthropogenic carbon emissions is material.

While it is largely technically unfeasible with current viable systems and generally uneconomic to pursue many types of coal mine methane, such as that which is produced in shallow open pit operations, several types of coal mine methane have high potential for capture. These are traditionally in deep, open pit operations where pre-drainage gas is feasible for capture (deeper than 200m) and in underground mines where pre-drainage is previously carried out, however the products are largely under-utilised and could be brought to market as per the recommendation of this report.

The Bowen Basin, which has traditionally focused on coal production, has the potential to bring more gas to Queensland’s domestic and export markets – by opening up areas for new (CSG) gas production and capturing unutilised gas from underground mines. However, the marked difference in CSG gas and incidental mine gas quality, unpredictability and variable flow rates are potential barriers to effectively scaling common use infrastructure.

Traditionally, mine operators have also been averse to either investing in new gas processing infrastructure or owning and operating that infrastructure. Generally, mine operators are supportive of power generation and moving surplus energy as “electrons” as opposed to “molecules”. The current business landscape therefore suggests that policy drivers, improvements to the regulatory frameworks and cross-sector collaboration from both private and public sector players will be critical to the development of the Bowen Basin gas resources.

8.1 Defining Coal Mine Methane
Coal Mine Methane (CMM) refers specifically to methane released from coal seams and surrounding strata either just prior or during coal mining (i.e. mining activities). As the build-up of methane in underground mines can create both an explosive and an asphyxiation hazard for mining operations, the
CMM must be removed prior to mining operations, and levels of residual methane in the mine kept below safe threshold limits. This is achieved through the use of ventilation systems (i.e. ventilation air methane) and/or dedicated relief systems (i.e. drilled boreholes) for surface treatment and/or dispersion.

8.1.1 Types of CMM
Pre-Drainage or SIS gas
The introduction of various gas drainage techniques in Australian gassy mines was necessary to complement ventilation system design and to satisfy statutory requirements in both open cut and underground mines. Gas pre-drainage can simultaneously reduce the risk of dangerous methane concentrations accumulating as well as reducing methane emissions into the atmosphere; moreover, the gas may be recovered as a valuable energy source for local power generation plants, as sales gas or other beneficiation.

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Pre-drainage gas is usually of sufficient quality (>70-90% methane) that conventional treatment and upgrading techniques may be employed to produce pipeline quality gas with some additional unit processes. Where CSG tenements overlap coal tenements, there is opportunity for large-scale coal and CSG co-development as CSG extraction essentially provides drainage of gas for future mining projects.

While various methods and models exist for the estimation of gas liberated during extraction, actual realised volumes are dependent on a host of variables: drainage method, drilling technique, permeability of coal seams and strata, hydrogeology and gas migration. Nevertheless, it is proven that the most effective drainage method for high quality gas extraction is by pre-drainage: vertical or directional holes drilled from the surface, or horizontal longholes from developmental headings or in seam headings.

Open cut mine operational emissions
In open cut mines, fugitive emissions from mining operations occur due to the release of methane from coal extraction, coal transport, coal handling and size reduction operations. It occurs across the mine in a similar way to natural methane seepage. There are no requirements or practical methods for capturing this gas that is effectively emitted at atmospheric pressure. However, like underground mining, large volumes of pre-drainage gas are also produced, as this is the most efficient method of methane removal prior to mining and is necessary to manage for safety purposes.

Ventilation Air Methane (VAM)
VAM is by its nature predominantly air and is subject to strict quality controls to ensure the health and safety of mine workers. VAM is therefore not suitable as a recoverable resource using currently available and commercially viable technology.

Goaf gas
Goaf gas extraction, on the other hand, occurs after pre-drainage methods have maximised the removal of in situ gas through surface or in seam drilling methods. Goaf gas is a post drainage technique that occurs in parallel with mining activities and is critical to managing actual methane levels in underground atmospheres.

Goaf gas is generated during longwall cutting or extraction and principally from the caved gob that remains behind the advancing cutting face. Goaf gas therefore combines with a portion of ventilation air that is provided to the working area and does not typically produce gas of high quality for direct use.
However, like pre-drainage systems, goaf gas extraction would require similar treatment, only to the extent and degree that secondary treatment processes increase to meet higher grade specifications.

Additional upgrading and cleaning technologies must be considered when coupling goaf gas extraction to either power or industrial sales gas offtakes.

8.2 Bowen Basin coal mine emissions
The coal mines in the Bowen Basin have a substantial annual greenhouse gas emissions footprint, which could be reduced via increased use of pre-drainage of gas and utilisation of goaf gas. Annual emissions data, outlined in Table 17, shows the largest emitting coal mines as identified by the
Commonwealth Clean Energy Regulator, providing an indication of which mines have the largest potential for reduction in emissions through utilisation of CMM.

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Table 17 – List of Queensland coal mines by annual emissions
(Source: Clean Energy Regulator (2021). 2019-20 Safeguard Facility Data. Australian Government)
Annual emissions
Facility name Company
(tonnes CO2-e)
Capcoal Mine (note 1) Anglo-American 3,149,800
Moranbah North Mine (note 1) Anglo-American 2,318,893
Goonyella Broadmeadow Mine BHP/BMA 1,273,036
Oaky Creek Coal Complex Glencore 1,227,828
Grosvenor Mine Anglo-American 1,185,349
Kestrel Mine Kestrel Coal 970,726
Carborough Downs Coal Mine Vale 656,281
Curragh Mine (note 1) Coronado Global Resources 614,968
Blackwater Mine BHP/BMA 592,875
Dawson Mine (note 1) Anglo-American 570,556
Hail Creek Mine Glencore 503,591
Peak Downs Mine BHP/BMA 497,134
Newlands Coal Complex (inc. NN UG) Glencore 434,665
Saraji Mine BHP/BMA 417,183
Ensham Resources Minesite Idemitsu Ensham Resources 402,871
Clermont Coal Operations Glencore 381,970
South Walker Creek (note 1) BHP/BMA 264,293
Jellinbah Mine Jellinbah Group 246,250
North Goonyella Coal Mine Peabody 243,234
Coppabella Coal Mine Peabody 219,580
Middlemount Coal Mine Yancoal 214,732
Foxleigh Mine Qmetco 200,394
Poitrel Mine (note 1) BHP/BMA 194,712
Yarrabee Coal Mine (Open Cut) Yancoal 184,282
Rolleston Coal Mine Glencore 166,843
Collinsville Mine Glencore 153,071
Isaac Plains Coal Mine Stanmore Coal 111,665
Total 16,740,501
1. Data for some listed mines was sourced from Safeguard’s multi-year emissions monitoring period, from 2016-2019. For these mines,
the most recent annual covered emissions value was used in the table above, typically FY2019-20.

Figure 76 indicates the CO2 emissions from various coal mines in the Bowen Basin. From the map, it can be inferred that CO2 emissions are the highest in the central Moranbah and Middlemount regions.
Data related to CO2 emissions were obtained from the Clean Energy Regulator (CER) website which is an independent statutory authority responsible for administering legislation to reduce carbon emissions and increase the use of clean energy in Australia.

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8.2.1 Future mines planned in the Bowen Basin
Currently, it is estimated that there are a total of three mines that are planned to be constructed and operated in the coming years. These mines are proposed to be located close to the central region of
Moranbah and Middlemount. Planned projects and their proposed coal production estimates are listed below:

• Olive Downs Coking Coal Project (Central Moranbah region) – 15 Mtpa;

• Winchester South Project (Central Moranbah region) – 11 Mtpa; and

• Valeria Coal Mine Project (Middlemount region) – 20 Mtpa.

All three mines are proposed to be open-cut type with construction to begin early in the decade and production to ramp up by 2025-2026. Analysis on gas emissions and methane capture from these proposed coal mines are not considered in this report. It is hypothesised that production life of several existing coal mines could be coming to an end and thus new mines’ CMM will be offset by the reduction is current levels of CMM gas production.

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Figure 76 - CO2 emissions by coal mine
(GHD analysis)
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8.3 Modelling fugitive emissions from CMM
CMM emissions data was primarily based on gas production estimates as a derivative of coal production data available for individual mines in the Bowen Basin. Coal production data was acquired from the Queensland Government “Open Data Portal”. These production estimates were for a designated period from 2015 to 2020.

Based on research and historical recovery data on CMM from various sources, tested with industry stakeholder feedback, the average CMM produced per tonne of coal produced (ROM production) was determined, with upper and lower quartile ranges to reflect the levels of uncertainty in the gas production volumes due to different coal gas contents across the Basin, as well as different mining techniques (Table 18).
Table 18 – Average gas production per tonne of coal produced
(Source: KPMG analysis)

Methane Production Lower quartile Average range Upper quartile

Open Cut Mines 1 m3/t 2.5 – 3.5 m3/t 5 m3/t

Underground Mines 9 m3/t 11 – 12.5 m3/t 14 m3/t

CMM emissions by source were calculated as a percentage of total gas production per annum and were categorised into the following:

1. Open-Cut Mines:

a. Pre-Drainage Gas (35%)

b. Operational fugitive emissions (65%)

2. Underground Mines:

a. Pre-Drainage Gas (35%)

b. Goaf Gas (15%)

c. Ventilation Air Methane (VAM) (50%)

Figure 77 below estimates yearly fugitive emissions (in CO2-e) from regular operation of existing open cut and underground coal mine operations. As indicated, the annual fugitive emissions of existing underground mines in CO2-e are estimated at approximately 9.5-10mtpa with a low and high case average of 7.25Mtpa and 11.25Mtpa respectively.

Figure 78 dissects these total emissions by source/type for a given year (2030). Of the 29mt of CO2-e forecast to be released (assuming no CMM capture), 19mt is from open cut operations, 3.5mt from pre-drainage, 1.5mt from goaf gas and 5mt from VAM.

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50,000,000

45,000,000
Upper quartile
40,000,000

35,000,000

30,000,000
Emissions (CO2-e)

25,000,000 Average fugitive emissions forecast range

20,000,000

15,000,000 Lower quartile

10,000,000

5,000,000

0
2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054
Figure 77 - Estimated total Underground and Open Cut and Underground Coal Mine Fugitive Emissions
2022-2054
(Source: KPMG analysis)

35,000,000

30,000,000

25,000,000
Emissions (CO2-e)

20,000,000

15,000,000

10,000,000

5,000,000

0
CO2e Emissions Open Cut Pre-Drainage (UG) Goaf (UG) VAM (UG)
(Total) Emissions

Figure 78 – Total unabated CO2 emissions from coal mining by source – 2030
(Source: KPMG analysis)

Evident in this figure, the majority of all coal mining GHG emissions are from open cut mine fugitive emissions, of which only pre-drainage gas can be captured. Operational emissions cannot be captured as they are generally emitted during recovery of the coal as over-burden is removed and pressures on the coals reduced. Underground mines still account for around 30% of emissions and hence are worth mitigating if possible.

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8.4 CMM capture
8.4.1 Current capture initiatives in the Basin
One major Bowen Basin mine currently produces approximately 40 TJ/d of CMM. An approximate breakdown of the daily coal mine gas production is as follows:

• 9 TJ/d is VAM, which is vented directly to atmosphere and cannot be flared due to low methane
concentration (typically less than 0.5%);

• 18 TJ/d is transferred to Arrow (if pipeline specification gas) or to EDL for local power generation;

• 2.5-3 TJ/d of very low concentration gas is vented in the field, for safety and operability reasons;
and

• The remaining 10 TJ/d of gas is flared. As methane (CH4) has a GWP100 of 28, flaring is preferable
to venting to reduce the overall greenhouse effect of this gas.

There are a number of barriers to utilising coal mine gas, meaning other coal mines have not been as successful, with another major mine operator in the Basin providing the following typical usage of coal mine gas:

• 60-70% is VAM, vented directly to atmosphere; and

• Remainder is flare or vented, although the amount flared instead of vented has increased in recent
years which has reduced GHG impact. Some of this gas is a mix of various products other than
methane which must be separated before use.

Industry’s main challenge to utilising coal mine gas in its current operations is that the quality and production rates of coal mine gas are variable, meaning it is not economic to enter into commercial gas supply agreements. However, the gas could be used more effectively on site, such as using pre-drainage gas to displace diesel usage, which contributes to environmental targets and social licence to operate.

8.4.2 Modelling potential capture improvements
Potential methane capture has been modelled based on a number of inputs and assumptions:

• It was assumed that fugitive emissions from open cut mines were unable to be captured.

• It was also assumed that VAM did not contribute to methane capture.

• The potential recovery rates of CMM through known capture technologies was estimated as a
percentage of total CMM by each different source including:

• Open cut mines:

o Pre-drainage (30% of pre-drainage gas emissions)
• Underground mines:

o Pre-drainage (30% of pre-drainage gas emissions);
o Goaf (20% of Goaf Gas emissions); and
o VAM (0% of VAM emissions).

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8.4.3 Potential CMM capture pathways
Strategies for improved future utilisation, and therefore enablement of production and beneficiation of
CMM, are likely to be crafted around the following key focus areas:

Overlapping tenements: New frameworks for coal and CSG overlapping tenures must continue to strive for maximum flexibility for resource authority holders, inclusive of the ability for relevant parties to mutually agree on non-regulated arrangements that may fall outside legislative or default requirements. Mining and gas operators should also consider smart transfer arrangements that allow gas operators or power producers to maximise revenue through peaking distribution.

Subsidisation: Power station and/or other gas beneficiation facilities will have a greater chance of development through participation in emissions subsidy schemes. Such financial incentives also ease the development of commercial agreements between mining and petroleum lease holders. Australian
Carbon Credit Units (ACCUs) held by owners of mine gas beneficiation plants can also be used as offsetting mechanisms for coal mining operations. Additionally, preferential pricing schemes for electricity derived from coal mine gas may incentivise independent power producers or encourage owner/operators to beneficiate gas in other ways.

Transmission Networks: Electrical transmission networks may constrain the output of future power station developments. The capacity of line systems will require upgrading in certain areas to maximise the dispatchable power from mine gas power plants. Upgraded transmission system may then encourage or enable larger power plants and drive common use infrastructure (e.g. gathering and transmission pipelines to centralised power plants).

Ventilation air methane: Mines could be incentivised to reduce VAM from established baseline emissions. Flaring or thermal oxidation of VAM is preferred to simple VAM venting, as combustion of
VAM would materially reduce total CO2 equivalent emissions (noting that methane has a CO2-e of
2513). The capital expenditure required safe thermal oxidation of VAM, where technology exists although has not yet been adopted for widespread use, means that more incentives via policies, grants, or emissions targets, may be required for coal mining operators to continue developing and increase their usage of this technology.

New Markets: New energy supply chains could be considered utilising either CSG and low-quality gas associated with its production or incidental mine gas that has been treated to suitable quality, although not necessarily pipeline specification gas. Natural gas value chains, starting with either piped gas or gas delivered via virtual pipelines could also open new markets for sales gas from the perspective of resource authority holders. However, given the relative higher cost of gas drainage compared to prevailing natural gas prices, such energy supply chains would likely require emissions’ subsidy mechanisms or similar incentives to drive development of these projects.

Infrastructure: Access to pipelines. One of the most significant barriers to utilising pre-drainage coal mine gas is access to export pipelines, due to the typical lack of proximal export pipelines, and the lack of required gas infrastructure to meet pipeline quality and pressure requirements. For these reasons, it is typically not economic to capture coal mine gas and export to the commercial market.

However, pipeline transport is not the only method of gas transport and delivery to end users or customers. Depending on scale of gas delivery and transport distance, there may be economic benefit in considering either compressed natural gas (i.e. trucked transport) or even small scale LNG plants.

131IPCC (2007) Climate Change 2007: The Physical Science Basis. Contribution of Working Group I to the Fourth
Assessment Report of the Intergovernmental Panel on Climate Change. [S. Solomon, D. Qin, M. Manning, Z.
Chen, M. Marquis, K.B. Averyt, M. Tignor and H.L. Miller (eds.)]. Cambridge University Press. Cambridge, United
Kingdom 996 pp.
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Gas Quality Requirements: CMM is typically highly variable in quality and flow, hence it can be a challenge to deliver consistently economic gas to market at suitable quality.

Emerging Technology: Developing and incorporating the use of emerging technology, such as membrane separation of methane to improve concentration to useable levels, has the potential to change the dynamics of CMM utilisation in the Basin.

8.4.4 Treatment of CMM for utilisation
Given the varying quality of CMM, including methane content, oxygen content, nitrogen content, dust, fines and water content, significant treatment is required to bring the CMM to a useable specification.
For details of the treatment processes required, please refer to Appendix D.

At a high level, CMM may require:

• Dehydration;

• Acid gas removal;

• Nitrogen removal; and

• Oxygen removal.

8.4.5 Potential utilisation options
Power Generation
Historically, the majority of the power generation requirements at centralised hubs and processing facilities have been met by the use of sales gas with gas turbine infrastructure, while the majority of remote compression motive power has been met with (direct) gas drives, the bulk of which are reciprocating engines. However, the electrification of field and hub infrastructure is becoming more common due to the following:

• The use of electric drives can reduce the cost of maintenance of field assets and improves the
reliability of the units;

• Electrification creates the opportunity for renewables integration into the power system to assist
reducing fuel gas requirements and the carbon footprint of the operation;

• If provided from a centralised power supply, waste heat can be used to generate steam required
for processing facilities, which can create boiler fuel gas savings and result in a significant carbon
footprint reduction; and

• If provided from a centralised power supply or large microgrids, electrification of remote field
stations can provide more flexibility to maintain the gas fired power at high efficiency compared
with many individual gas drives at remote locations that can become oversized and less efficient
as local field volumes decline.

Therefore, for the gas processing facilities and associated utilities and support facilities, it is expected the electrical power supply would be provided by the local distribution network in the Bowen Basin.
This aligns with the recent trend of electrifying gas processing facilities, such as Senex/Jemena’s
Project Atlas, rather than using dedicated local power generation as has been the traditional approach.
The close proximity of gas resources in the Bowen Basin to existing power infrastructure supports this approach. There is still also an opportunity to utilise coal mine goaf gas for local power generation, which can then be used directly by both the coal mines and gas processing facilities, displacing coal fired power generation.
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With the rapid development of industrial scale photovoltaic systems, there is also potential to power the gas process facilities with a hybrid gas–powered generation and photovoltaic generation. Such a facility could also be provided by a third-party owner, with potential for a regional grid connection to multiple gas processing facilities. This power supply to gas processing facilities needs to provide very high reliability. The total potential electrical load could range from modest, in the order of hundreds of kilowatts, to large, in the order 50 to 100 megawatts. This depends on the number and size of gas process facilities, and the level of electrification used in the facilities. For reference, the EDL operated waste gas power stations at Moranbah North and German Creek have capacities of 64 MW and 45
MW respectively.

The selection of power generation technology is dependent on a number of factors including scale of application, load variability, proximity to grid networks, topography, pole and line distribution costs.
Ultimately the determination of lifecycle cost of electricity can only be evaluated on a case-by-case basis. For all electrification options, the potential benefit of a battery energy storage system (BESS) and renewable generation from wind and solar in combination with more traditional infrastructure, should also be evaluated. The use of microturbines or gas engines for combined heat and power (CHP) applications at remote locations is also a worthwhile valuation.

Compressed Natural Gas
A Compressed Natural Gas (CNG) unit primarily comprises the compressor, compressor auxiliaries, and any associated gas pre-treatment equipment. For the transport of CNG in a virtual pipeline, specialized tube trailers are used that store gas at 250 – 300 barg. The tube trailers and storage tubes are usually supplied, with varying numbers of tubes and trailer capacity, and hooked up to a regular prime mover for transport. CNG packages that are used for refuelling stations are practically identical in nature, with the exception that dispensing and vehicle loading infrastructure is not required.

CNG packages would typically be skid mounted. The compressors themselves could be engine or motor driven, depending on site location (remote or centralised). Ideally, CNG packages should receive gas at above atmospheric pressure, but certain units can tolerate low inlet pressures (<50 kPa). It is not uncommon however to utilise a booster configuration for medium to large size packages.

CNG is worthy of consideration for remote or stranded, small scale assets, particularly where clean gas is available but insufficient quantities to warrant larger scale investment (e.g. pipelines). CNG can be used to transport gas over short distances and can typically provide some cost benefit over larger infrastructure investments where road transport distances are <100km. The variable OPEX does become a key parameter though as road transport maintenance, fuel, labour all contributes significantly to the lifecycle cost for this option.

Micro LNG
The global commoditisation of LNG has provided a solid base for the emergence of new LNG applications and markets, particularly for small scale plants that can be used to monetize captured, smaller resources or otherwise stranded gas that cannot support or justify large scale LNG plant development. Like CNG packaged plants, the use of LNG small scale plants for end users is contingent upon a sustainable, virtual pipeline that can reliably maintain a constant supply of LNG through trucked transport.

Despite higher unit costs associated with the smaller scale plants, the lower capital and general project risk is an enabler for small scale project development and may be attractive to some project developers.
As with most technologies in early development, increased maturation and adoption is likely to lead to improved economies of scale. An example of this is the creative solutions being employed to improve modularisation and containerisation of small-scale LNG plants. This includes the use of pressurised
LNG tanks for storing smaller amounts of LNG, compared to the conventional atmospheric flat bottom

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tanks. Pressurized tanks also allow for a more effective way to manage boil-off gas (BOG), largely eliminating the need for costly BOG recovery systems.

Small scale LNG plants are regularly defined as anything below 1 million ton per annum (150 TJ/d) compared with modern large-scale LNG plants that are between 4 – 8 Mtpa per LNG train. Small scale plants have been further sub-categorised as micro-LNG and mini-LNG at capacities of below 30,000 tpa (4.5 TJ/d) and 300,000 tpa (45 TJ/d) respectively. While the core elements remain the same, different liquefaction processes principally drive variations between vendor options. Liquefaction of natural gas in small scale requires a few pre-treatment steps. These process steps help to avoid operational disturbance of the downstream cryogenic plant section and ensure that the LNG product meets defined quality requirements. Depending on the integration of LNG unit with other collection facilities, and the extent of centralized gas processing, the scope of the small-scale LNG plant would change on a case-by-case basis.
Table 19 – Summary of technology providers – small scale LNG
(Source: GHD analysis).

Technology Refrigerant Process (licence) Technology Supplier
Prico® Black & Veatch
SMR Chart Industries
SMR Wartilsa
PCMR, SCMR GE (Baker Hughes-GE)
SMR
Mixed Refrigerant K-SMR® Kogas
Cycles AP-M ® Air Products (APCI)
Cryobox® Galileo
LiMuM® Linde
PCMR Kryopak
Pre-cooling + SMR
OSMR® LNG Limited
N2-Reverse Brayton Wartsila
Single Refrigerant – OCX® Mustang Technologies
Expander (SRE)
Expansion / Brayton Single / Multiple
Various
Cycles Expander
C3MR® Air Products (APCI)
Pre-cooling + SRE
NicheLNG® CB&I

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8.5 Infrastructure requirements
There is measurable potential in harnessing methane emissions from coal producing mines in the
Bowen Basin and converting them into sales quality gas, also leading to reduced CO2 emissions from the region. An analysis on methane emissions and consequently potential methane capture from various coal mines currently operating in the Bowen Basin was performed. The analysis covered the majority of the Bowen Basin with approximately 52 mines being considered. As the Bowen Basin comprises both open-cut and underground coal mines, coal mine methane capture assessment was conducted for both types of mines.

8.5.1 Methodology & assumptions
Queensland mine gas does not contain appreciable amounts of acid gas components or higher hydrocarbon gases. The presence of volatile heavy metals (e.g. mercury, selenium etc) is also not typical of mine gas. Therefore, gas treatment is primarily concerned with de- hydration, although inert gas removal could be important to meet industrial gas users’ and/or sales gas specifications. The presence of oxygen can require a specific oxygen removal unit since oxygen is known to degrade downstream solvent chemicals and increase the potential for corrosion, especially for steel pipelines. Removal of CO2 from wet gas is also important for managing corrosion in steel pipelines and gas processing equipment, hence the application of acid gas plants upstream of dehydration units. Where only minor amounts of acid gas are present, they can be removed by absorption along with the removal of water.

Fractionation and separation units for C2+ recovery was not considered for mine gas processing.

The development of coal mine methane infrastructure must consider not only the varying feed quality of the CMM itself, but also the end user application. Typical gas specifications for pre-drainage gas and goaf gas are presented in the tables below:
Table 20 – Typical coal mine methane quality
(Source: GHD analysis).

Parameter U.o.M Pre-Drainage gas Goaf Gas
Methane Content Mol% 85-95 30-60
Carbon dioxide Content Mol% 3-5 5-12
Oxygen Content Mol% 1-2 2-10
Total Inert Content Mol% 5-7 >30
Total sulphur mg/m3 10-50 10-50
Dust - Low High
LHV (methane) MJ/m3 39.8
LHV MJ/m3 32-38 12-22

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Table 21 – Typical end user feed specification
(Source: GHD analysis).

Power Generation Industrial User
Parameter U.o.M Note 1 Note 2 Sales Gas (AS4564)

Methane Content Mol% >30-40 >94 -
Carbon dioxide
Mol% <50 <3.0 -
Content
Oxygen Content Mol% < LEL <0.2 <0.2
Total Inert Content
Note 3 Mol% No Limit <6-7.0 <7.0

Total H2S mg/m3 Minimal <7.0 <5.7
Total Sulphur mg/m3 Minimal Minimal <50
Water Content mg/m3 No free water No free water 112.0
Dust - Nil Nil Nil
LHV MJ/m3 > 35 ~39.8 (Max. 42.3 HHV)
Notes:
1. Generalised specification – requirements will differ depending on application (gas engines vs turbine/micro turbines)
2. Typical user might include reforming plant (H2 production) or fertiliser plant (NH3/Urea production or user requiring general process heat
(e.g. for a fired heater)
3. Inert content, methane content and extent of variability will all be key considerations in evaluating choice of power generation
technology. Traditionally, gas engines are most flexible and can operate on much lower heating value gas. Efficiency, by products’
formation and contaminant emissions (SOx, NOx, PMs) must also be considered on a case-by-case basis.

8.5.2 Results and Observations
Flowrates of methane emissions and potential methane captured from various coal mines in the Bowen
Basin were identified. It was inferred that underground mines could both emit and capture higher quantities of methane when compared to open-cut mines. The Bowen Basin was segregated into different geographical regions comprising a specific set of coal mines with their corresponding methane emissions and potential for captured methane flow rates. The total methane emissions and potential CMM capture are tabulated Table 22 and Table 23 respectively.

Based on the tabulated data, a series of options was identified for each mining hub/region. In accordance with the technologies capture pathways identified above, a series of corresponding treatment technologies and, hence, overall infrastructure scope was developed. The facility scoping for each scenario was then used to derive rough order numbers for capital expenditure.

A summary of infrastructure scenarios is presented in Table 24. Under each scenario the suite of likely, suitable process technologies was considered for upgrading of the relevant gas.
Table 22 – Total methane emissions flowrate
(Source: GHD Analysis)

Open Cut (TJ/d) Underground (TJ/d)
Geographical Location Pre drainage Fugitive Pre drainage Goaf VAM
Moranbah North 0.74 1.37 0 0 0
Moranbah Central 3.68 6.84 12.67 5.43 18.10
Clermont 0.47 0.88 0 0 0
Middlemount 0.6 1.1 10.7 4.6 15.3

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Open Cut (TJ/d) Underground (TJ/d)
Geographical Location Pre drainage Fugitive Pre drainage Goaf VAM
Blackwater 1.5 2.8 0 0 0
Rolleston 0.5 1.0 0 0 0
Moura 0.7 1.4 0 0 0

Table 23 – Captured methane flowrate
(Source: GHD Analysis)

Geographical Location Open Cut (TJ/d) Underground (TJ/d) Total (TJ/d)
Moranbah North 0.22 0 0.22
Moranbah Central 1.1 4.9 6
Clermont 0.14 0 0.14
Middlemount 0.2 4.1 4.3
Blackwater 0.4 0 0.4
Rolleston 0.16 0 0.16
Moura 0.2 0 0.2

Based on the values presented in the above table, potential methane capture is the highest for
Moranbah Central and Middlemount region. The Moranbah central region comprises of noteworthy mines like Moranbah North Mine, Goonyella Broadmeadow Mine, Grosvenor Mine and the
Middlemount region comprises of notable mines like Capcoal Mine, Kestrel Mine, Oaky Creek Coal
Complex to name a few. Figure 79 provides a map of the Bowen Basin indicating the total captured methane in the region.

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Figure 79 – Potential methane captured
(Source: GHD analysis)

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Table 24 – Summary of possible CMM scenarios – end user applications
(Source: GHD analysis)

Gas Gas Scenarios
Region Type Drainage Drainage
(TJ/d) (GJ/d) Micro Power Pipeline
CNG
LNG Gen Export
Pre- Not
0.20 200 Yes No Yes
North Drainage feasible
Moranbah Not
Goaf 0.0 0 No No Yes
feasible
Pre-
4.4 4410 No Yes Yes Yes
Moranbah Drainage
Central Not
Goaf 0.69 689 No No Yes
feasible
Pre-
3.00 3038 No Yes Yes Yes
Drainage
Middlemount
Not
Goaf 0.58 581 No No Yes
feasible
Pre- Not
0.40 404 Yes No Yes
Drainage feasible
Blackwater
Not
Goaf 0.00 0 No No Yes
feasible
Pre- Not
0.13 128 Yes No Yes
Drainage feasible
Clermont
Not
Goaf 0.00 0 No No Yes
feasible
Pre- Not
0.15 148 Yes No Yes
Drainage feasible
Rolleston
Not
Goaf 0.00 0 No No Yes
feasible
Pre- Not
0.20 200 Yes No Yes
Drainage feasible
Moura
Not
Goaf 0.00 0 No No Yes
feasible

Based on the tabulated CMM scenarios, a basic assessment of required infrastructure can be undertaken. For the purposes of this study each end user application was considered to be an offtake for the respective (i.e. 100%) volume of the available mine gas. In reality there may be various configurations at each potential mining hub or region, including the blending of pre-drainage gas and goaf gas from different mines. The relative distance to final customer will also influence the decision in regard to gas transport, which may be as gas, liquid or in a virtual pipeline with road transport.

Pipeline Export
The pipeline export scenario can also be considered a proxy for industrial gas offtake since pipeline specification gas could be expected at the battery limit of an industrial facility. Pipeline export requires the highest quality specification and therefore warrants the below steps:

• TEG Dehydration: The design of TEG unit requires a specific water target. It is typical to design for
pipeline specification which requires water levels in the product gas to be no greater
than 65mg/Sm3;

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• Acid Gas Treatment: A mixed solvent process can be assumed, which may be factored on expected
low sulphur content and relative high CO2 content; and

• Compression: A compressor station is required for each pipeline export scenario to take gas from
the relative low pressure at the exit of treatment units to pipeline operating pressure of ~9-10
MPag. Owing to relatively close proximity to other transmission systems, it is not envisaged that
booster compressor stations would be required.

Upgrading of goaf gas to pipeline specification was not considered a realistic scenario, given both scale and quality concerns, hence the requirement for oxygen and nitrogen rejection units was omitted.

Power Generation
The relatively small scale under consideration is assumed to be gas engines. No additional pre- treatment units are considered in combination with power generation infrastructure. Goaf gas utilisation through power generation is considered the only viable option.

Micro LNG
The LNG plant can be considered a “black box” package, supplied turnkey on an EPC basis. For small scale plants the liquefaction plant cost, being containerised or modularized, is somewhat standardised. Site establishment and bulk earthworks costs are significantly lower for small scale plants, while equipment unit costs are greater.

Compressed Natural Gas (CNG)
Configurations employing CNG assumed to include TEG dehydration and Acid gas treatment, followed by packaged compression units that also encompass loading and filling infrastructure for road transport loading. It should be noted that the greatest cost variation for any scenario employing CNG relates to logistics (number of trucks, virtual pipeline distance, truck cycle time, the allowable shift times and buffer storage at delivery location(s)).

8.5.3 Economic Parameters
Assumptions for the rough order outline of total installed costs are outlined below:

Pipeline Export
• Costs for TEG dehydration and, AGR units, i.e. gas processing are included. As with conventional
CSG export infrastructure, the technology does not vary significantly.

• Cost rates for gas processing facilities, excl. compression stations, was considered as $3 million
per TJ/day capacity, inclusive of owners’ costs.

• Pipeline costs can be taken on a per inch per kilometre basis, which was estimated at
$70000/in/km. Trunk lines were assumed to be 6 inch.

• Compression cost were considered as for high pressure, screw units for trunk systems that may
transport gas to a main transmission pipeline. Costs have been determined on a duty basis,
assuming two stage compression with pressure ratio of 10.

• Trunk lines from CMM generators to e.g. a mains transmission was assumed to be not greater
than 20km.

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Power Generation
Installed costs for power equipment were based on specific project experience with larger commercial installations ($1250-1500 / kWe for >5MWe units). A figure of 1750- $/kWe considers turnkey plant supply but only for the gas engine, genset and controls and other auxiliaries. It does not consider e.g.
combined heat and power integration. A gas engine efficiency of 42% was assumed based on the calculated thermal loads.

Micro LNG
Installed cost inclusive of pre-treatment and regasification was assumed as ~$2200 AUD/tonne LNG, excluding site storage units. Site storage is accomplished with bulk, vacuum insulated (VI) tanks that store cryogenic LPG under pressure (up to 9 barg).

Compressed Natural Gas
Package costs were estimated from a recent feasibility study for a mobile refilling station, processing
1-2 TJ/day. This package size was considered suitable for scaling purposes TEG and AGR unit treatment costs were applied as for pipeline export scenarios. Data for logistics was aggregated based on the following:

• Trailer Capacity – Single and articulated trailers are equipped with between 26500 – 65000 L water
capacity, which is equivalent to 180 – 400 GJ. The larger, articulated units (400GJ) were used as
a basis, with an estimated cost of ~AUD$750 000 each.

• Buffer Capacity – Buffer capacity was not considered for any virtual pipeline system.

OPEX
The elements of OPEX are highly variable across different technology platforms and potential future configurations for CMM capture. Quantitative estimates have not been made for chemical inventories, fuel, major equipment replacements, logistical costs, labour and maintenance. Instead, project data was examined to derive a generalised processing cost of 1$/GJ.

Summary
A summary of the various end user scenarios and related CAPEX/OPEX requirements are presented in
Table 25. Note that lifecycle costs will have a material influence on the viability of different hub configurations and further analysis is required to select optimum end user application.

In order to provide incremental costs for the extraction of mine gas, for comparison to forecasted gas prices, which are on a unit basis (i.e. $/GJ or $/MMBTU), the equivalent annual cost (EAC) was calculated for each configuration. EAC was presented in $/GJ.

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Table 25 – End user applications and CAPEX requirements
(Source: GHD Analysis)

Potential CNG Micro LNG Power Gen Pipeline export
Methane
Region Type
Capture CAPEX OPEX EAC CAPEX OPEX EAC CAPEX OPEX EAC CAPEX OPEX EAC
(TJ/d) Feas. Feas. Feas. Feas.
(M$) (M$/yr) ($/GJ) (M$) (M$/yr) ($/GJ) (M$) (M$/yr) ($/GJ) (M$) (M$/yr) ($/GJ)
Pre-
0.2 Yes 2.5 0.1 4.7 No - - - Yes 1.5 0.1 3.14 N/A - - -
North Drainage
Moranbah
Goaf 0 No - - - No - - - N/A - - - N/A - - -

Pre-
4.41 No - - - Yes 83 1.5 6.53 Yes 32.2 1.5 3.14 Yes 27.5 1.5 2.83
Moranbah Drainage
Central
Goaf 0.689 No - - - No - - - Yes 5 0.2 3.14 N/A - - -

Pre-
3.038 No - - - Yes 57.2 1.1 6.53 Yes 22.1 1.1 3.14 Yes 22.1 1.1 3.13
Drainage
Middlemount
Goaf 0.581 No - - - No - - - Yes 4.2 0.2 3.14 N/A - - -

Pre-
0.404 Yes 4.3 0.1 4.13 No - - - Yes 2.9 0.1 3.14 N/A - - -
Drainage
Blackwater
Goaf 0 No - - - No - - - N/A - - - N/A - - -

Pre-
0.128 Yes 2.1 0 5.93 No - - - Yes 0.9 0 3.14 N/A - - -
Drainage
Clermont
Goaf 0 No - - - No - - - N/A - - - N/A - - -

Pre-
0.148 Yes 2.2 0.1 5.48 No - - - Yes 1.1 0.1 3.14 N/A - - -
Drainage
Rolleston
Goaf 0 No - - - No - - - N/A - - - N/A - - -

Pre-
0.2 Yes 2.5 0.1 4.7 No - - - Yes 1.5 0.1 3.14 N/A - - -
Drainage
Moura
Goaf 0 No - No N/A - - - N/A - - - -

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8.6 Challenges
The Bowen Basin, which has traditionally focused on coal production, has the potential to bring more gas to Queensland’s domestic and export markets – by opening up areas for new CSG gas production and capturing unutilised gas from underground mines. However, the marked difference in CSG gas and incidental mine gas quality is a potential barrier to effectively scaling common use infrastructure.

Traditionally, mine operators have also been averse to either investing in new gas processing infrastructure or owning and operating that infrastructure. Generally, mine operators are supportive of power generation and moving surplus energy as “electrons” as opposed to “molecules”. The current business landscape therefore suggests that policy drivers, improvements to the regulatory frameworks and cross sector collaboration from both private and public sector players will be critical to the development of the Bowen Basin gas resources.

There are numerous challenges in increasing the beneficial use coal mine methane emissions, several of which have been identified in the preceding sections. The history of coal seam gas development in
Queensland had created some challenges in conflicting goals between coal mine operators and coal seam gas companies. Whilst there had been changes in Government legislation and working practices between the different industries, there remains a number of challenges that will need to be addressed in order to achieve a material increase in the beneficial use of coal mine methane emissions.

Key challenges identified during the study include the following:

• Limited active coal seam gas production in close proximity to existing mines – the extent of active
coal seam gas production covers a small area of the extent of mines in the basin, therefore there
is currently limited ability for mines to access coal seam gas production to take away coal mine gas.

• Mines between Moranbah and Blackwater do not have access to a gas pipeline – this would then
require other methods to capture coal mine gas for beneficial use, which typically involves the use
of complex specialist gas processing equipment.

• Variability of gas from a coal seam gas producers perspective – pre-drainage coal mine gas is
generally considered to be a variable source of gas, not something that would underpin a
development and used as a top up gas source.

• Cost of alternate uses – a common theme from consultation with the mining companies was that
beneficial use of coal mine gas was generally not economical if not in close proximity to a gas
processing facility.

• Power generation as a market source for coal mine gas is becoming more challenging due to
increasing penetration of renewables – this has shifted the operating profile of the power generation
facilities in the basin that currently use coal mine gas. This is resulting in more intermittent demand
for power generation and given the need to continuously drain the goaf is resulting in the gas to
be flared when the power generation isn’t running.

• The absence of strong Government requirements to ensure beneficial use of coal mine gas –
currently mine operators are not forced to productively use coal mine gas making it easy to default
to the simplest solution to ensure mine safety, which is flaring or venting.

• Overlapping tenure – described in detail below.

One of the most significant barriers to utilising coal mine gas is access to export pipelines, due to the typical lack of proximal export pipelines, and the lack of required gas infrastructure to meet pipeline quality and pressure requirements. For these reasons, it is typically not economic to capture coal mine gas and export to the commercial market.

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However, pipeline transport is not the only method of gas transport and delivery to end users or customers. Depending on scale of gas delivery and transport distance, there may be economic benefit in considering either compressed natural gas (i.e. trucked transport) or even small scale liquefied natural gas (LNG) plants.

8.6.1 Overlapping tenure and coexistence
Almost 90% of Queensland’s coal tenure and coal seam gas tenure is overlapped, which in the past has tended to lead to an adversarial outcome. Overlapping tenure is particularly evident in the Basin near Moranbah where there’s a concentration of overlapping granted Mining Leases (ML) and
Petroleum Leases (PL) (Figure 80).

Figure 80 – Overlapping ML and PL holders in the Bowen Basin
(Source: GHD Analysis)
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A revised framework for addressing overlapping tenure was incorporated into the Mineral and Energy
Resources (Common Provisions) Act 2014 (MERCPA). The ‘new’ overlapping tenure framework is a legislated default regime which applies where overlapping parties cannot otherwise agree.

A simultaneous operations zone is an area where coal and CSG production activities can co-exist. A key feature of the revised overlapping tenure framework is the requirement for a joint interaction management plan (JIMP) in various overlapping operating scenarios. A JIMP Industry Guide OLT-
Industry-Guide-final-Dec16-2.pdf (qrc.org.au) has been prepared by the Queensland Resources Council
(QRC) to assist coal and CSG businesses to meet the ‘new’ requirements.

In relation to the JIMP requirements under the respective safety legislation, the party responsible under that legislation to make a JIMP must make reasonable attempts to consult with the other party. The party responsible to make a JIMP must have regard to any reasonable provisions proposed by the other party(s) relating to the management of risks and hazards and either reach agreement about the content of the proposed JIMP or apply for arbitration.

The ‘new’ overlapping tenures legislative framework for coal and CSG tenure is governed by MERCPA.
Other legislation which applies to coal and CSG tenures includes the:

• Mineral and Energy Resources (Common Provisions) Regulation 2016;

• Mineral Resources Act 1989 (MR Act);

• Mineral Resources Regulation 2013;

• Coal Mine Safety and Health Act 1999;

• Coal Mine Safety and Health Regulation 2001;

• Petroleum and Gas (Production and Safety) Act 2004 (P&G Act);

• Petroleum and Gas (Production and Safety) Regulation 2004; and

• Petroleum Act 1923.

The overlapping tenure framework in Chapter 4 of MERCPA replaces the old framework in Chapter 8 of the MR Act and Chapter 3 of the P&G Act. Chapter 7, Part 4 of MERCPA provides transitional provisions applying to granted tenure (and some tenure applications) and existing agreements relating to the matters the subject to MERCPA at commencement (see Section 5). The ‘new’ framework generally applies to all forms of coal mining tenure and CSG tenure, with the exception of petroleum tenure under the Petroleum Act 1923.

From 27 September 2016, the new framework applies to holders of the following resource authorities where there is an overlapping area:

• Exploration permit for coal (EPC);

• Mineral development licence for coal (MDL (coal));

• Mining Lease (ML) for coal;

• Authority to prospect (ATP) for CSG; and

• Petroleum Licence (PL) for CSG.

The framework seeks to optimise the safe development of Queensland’s coal and CSG resources by:

• simplifying the pathway to and improving the certainty of the grant of overlapping tenure;

• incentivising negotiated arrangements for collaborative and cooperative concurrent production of
both resources in overlapping areas;
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• providing a default set of arrangements and dispute resolution processes to provide certainty to
arrangements for coordination of activities if the parties cannot agree between themselves;

• providing a structure for joint coordination and management of health and safety; and

• reducing administrative burdens, while preserving production rights already granted.

Chapter 4 of MERCPA details provisions for overlapping coal and petroleum resource authorities with
Section 102 outlining the main purposes as:

• facilitate the co-existence of the State’s coal and coal seam gas industries;

• ensure that participants in each of the industries co-operate to optimise the development and use
of the State’s coal and coal seam gas resources to maximise the benefit for all Queenslanders; and

• establish a statutory framework that applies if the participants do not otherwise agree.

The main purposes are achieved by:

• removing barriers to the grant of resource authorities for coal and coal seam gas production;

• allowing a right of way for coal production subject to notice and compensation requirements;

• imposing ongoing obligations on participants in each of the industries to exchange relevant
information; and

• providing for participants in each of the industries to negotiate arrangements as an alternative to
particular legislative requirements.

• As a minimum, overlapping resource authority holders under the framework will need to comply
with the mandatory requirements set out under section 117 of MERCPA. Detailed requirements
for ML and PL holders are outlined below.

For ML (coal) holders:

• giving an advance notice to an overlapping ATP or PL holder within 10 business days of making a
ML (coal) application (section 121);

• if overlapping an ATP holder and exceptional circumstances (i.e. extension of the notice period to
achieve full economic potential of CSG production) is established – a notice to the department about
the exceptional circumstances (section 127(8)(b));

• if overlapping a PL – have an agreed joint development plan in place within the statutory timeframes
and notifying the department of the plan (section 130);

• ensure an agreed joint development plan with a PL holder is consistent with any initial development
plan or later development plan under the MRA (section 132);

• notify the department of any changes to an agreed joint development plan that result in cessation,
or significant increase or reduction, of activities by the ML (coal) holder or PL holder (section 133);

• exchange required information with the overlapping ATP or PL holder (section 154); and

• comply with Ministerial directions about agreed joint development plans and requests for
information (sections 157-160).

For PL holders:

• giving a petroleum production notice to the holder of an overlapping EPC, MDL (coal), or ML (coal)
within 10 business days of making a PL application (section 141);

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• if overlapping a ML (coal) – have an agreed joint development plan in place within the statutory
timeframes and notifying the department of the plan (section 142);

• ensure an agreed joint development plan with a ML (coal) holder is consistent with any initial
development plan or later development plan under the P&G Act (section 145);

• notify the department of any changes to an agreed joint development plan that result in cessation,
or significant increase or reduction, of activities by the PL holder or ML (coal) holder (section 146);

• exchange required information with the EPC, MDL (coal) or ML (coal) holder (section 154); and

• comply with Ministerial directions about agreed joint development plans and requests for
information (sections 157-160).

In an overlapping area that is subject to a ML, a gas party which holds petroleum exploration tenure or a PL has a right to be offered, on reasonable terms, any incidental coal seam gas (ICSG). ICSG is defined under the Mineral Resources Act 1989 as coal seam gas that is mined, or proposed to be mined by the mining lease holder under the following circumstances (Section 318CM):

• the mining happens as a necessary result of coal or oil shale mining carried out under the mining
lease;

• the mining is necessary to ensure a safe mine working environment for coal or oil shale mining
under the mining lease; or

• the mining is necessary to minimise the fugitive emissions of methane during the course of coal
mining operations.

Holders of overlapping resource authorities are encouraged to seek legal advice on the impacts of the
MERCPA framework and provisions for ICSG under the MR Act 1998 on their resource projects.

8.7 New fugitive emissions – Basin development
Whilst the capture of CMM as part of the development of the Bowen Basin will assist in reducing
Queensland’s fugitive emissions, the development of new CSG production in the Basin will add additional fugitive emissions from these development activities. As such, a model has been constructed to determine the likely volumes of additional new emissions from Basin development.

The development emissions were estimated using the emissions guidelines contained within the most recent NGER report. The estimation of the development emissions provides an outline of the volume of emissions incurred as fugitive emissions from CSG operations.

The fugitive emissions were modelled using a low, mid and high case scenario to give a three banded estimate for the low mid and high production emissions cases. The three bands represent the uncertainty inherent in the production volumes as well as produced water variation and transport emissions uncertainty.

8.7.1 Methodology
Fugitive emissions were modelled for all four production scenarios (refer Section 7.4 for scenario details).

Construction emissions
Construction emissions were calculated by approximating a weighted average for the expected emissions in CO2-et per dollar of CAPEX by combining the average emissions per dollar GDP for
Australia, for the construction industry specifically, and the oil and gas industry. The value obtained was
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then used to estimate the construction emissions for the development of the Bowen basin at an initial
CAPEX of AUD $4 bn to give approximately 1.3 million tonnes of CO2 equivalence. These calculations are outlined in detail in the emissions model.

Operations emissions
Modelling fugitive greenhouse gas emissions from the development of the basin was achieved by using the estimate calculations outlined in the current National Greenhouse and Energy Reporting (NGERs) report. Fugitive emissions were approximated by the calculation and summation of the expected emissions from production, processing, transport, produced water, flaring, and venting for a variety of different production scenarios. It was assumed by the model that storage emissions would be negligible as no storage expansion to accommodate Bowen basin gas is anticipated.

The calculation of operating emissions was carried out using the below equations and inputs:

Production Emissions =

Processing Emissions =

Transport Emissions =

Produced Water Emissions =

Flaring Emissions =

Venting Emissions = Eij = Qi x 0.0198 x 22.5

Where:

Eij = The total emissions for the specified emissions source in tonnes of CO2 equivalence

EFij(w,k,s) = The emissions factor relevant to the emissions source as specified in NGER datasheets

Qi = The volume of gas produced in tonnes

Wi = the volume of water in megalitres

Sij/SDij = a constant relating the proportion of methane in produced gas and the default share of emissions derived from NGER datasheets.

8.7.2 Results
The total emissions are below 10Mt CO2-et over the life of the project.

Using this estimate, we can see that the 12 Mt total emissions from the basin development (high case in central scenario) would require only a 4% reduction in overall underground coal mine fugitive emissions to achieve emissions ROI (4% of mid case >300Mt unabated underground coal mine emissions).

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14,000,000 2,000,000

Annual Emissions (tonnes CO2-e / year)
1,800,000
12,000,000
1,600,000
Total Emissions (tonnes CO2-e)

10,000,000 1,400,000

1,200,000
8,000,000

1,000,000

6,000,000
800,000

4,000,000 600,000

400,000
2,000,000
200,000

0 0
2021

2023

2025

2027

2029

2031

2033

2035

2037

2039

2041

2043

2045

2047

2049

2051

2053
Annual Emissions - Scenario 4 Annual Emissions - Scenario 1 Annual Emissions - Scenario 2
Annual Emissions - Scenario 3 Total Emissions - Scenario 1 Total Emissions - Scenario 2
Total Emissions - Scenario 3 Total Emissions - Scenario 4

Figure 81 – Basin development emissions by scenario
(Source: KPMG analysis)

As has been demonstrated by the fugitive emission modelling, the reduction in fugitive emissions from utilising CMM capture, even if only a small portion of the total, will far outweigh the GHG emissions impact of developing the Basin as a CSG play. This is largely due to methane having a GWP100 of 28 and hence capturing and combusting it will have a net positive effect on the emissions of the project despite the emissions required to develop the Basin.

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9. Infrastructure options
9.1 Approach
As detailed in Section 7, there are a number of pathways to economically produce natural gas from multiple regions in the Basin that would ultimately underpin the construction of a gas pipeline connection to the ECGM.

Whilst a new gas pipeline isn’t the largest component of costs to develop the Bowen Basin, stakeholder reflections suggest that lack of infrastructure has been a key contributing factor to the delayed development of the Basin and will remain a key barrier into the future. Without the construction of a connecting pipeline to the ECGM, the Blackwater and Moranbah areas of the Basin are not likely to encourage investment and will not result in any material gas development occurring.

In order to facilitate the production scenarios described in Section 7.0, pipeline infrastructure options and industry requirements have been identified. The gas infrastructure options considered included gas processing facilities and export pipeline routes to connect the gas production in the Basin to the ECGM and beyond.

The key consideration was for sizing for gas process facilities and gas pipelines, and potential routes for connection to the ECGM. Location of gas processing facilities will be proximate to the gas source in the areas of main development, and in this study are considered nominal in location within sub-areas of the study. As described in Section 7, these sub-areas are Moranbah, Blackwater and Mahalo.

9.2 Industry proposed Bowen Basin pipelines
As part of the development of the Bowen Basin to date, many proponents have identified potential pipeline solutions. The following proposed pipelines vary in project maturity; however, they are at the early stages of development, and have not made material progress in recent years:

Arrow Energy Bowen Pipeline
Figure 82 illustrates the proposed route as part of Arrow’s Bowen Pipeline Project. This proposed pipeline connects Arrow’s land interests north of Moranbah to an LNG export facility at Gladstone. It proposes diameter of up to DN1050 (42 inch) with capacity to supply approximately 1,500 TJ/d at a maximum operating pressure of 10.2 MPa.

The route was originally developed by Enertrade in 2006 and included the development of an
Environmental Impact Statement (EIS) for the “Central Queensland Gas Pipeline”. Enertrade was acquired by Arrow Energy/AGL in 2007 along with this pipeline route.

Subsequently, Arrow Energy completed an EIS for the “Arrow Bowen Pipeline Project” in 2012, which was approved by the Queensland Government in March 2013 and the Commonwealth Government in
October 2014.

A pipeline licence for the Arrow Bowen Pipeline was granted in 2017 for a term of 50 years, however no construction has commenced, and the project appears to have been put on hold.

Arrow Energy’s pipeline is the most progressed of all the proposed pipelines.

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Figure 82 Arrow Bowen Pipeline Preliminary Route
(Source: Arrow Energy (2017). Environmental Impact Statement: Arrow Bowen Pipeline Project (Executive Summary)

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APA Group Galilee Pipeline
This proposed pipeline connects gas exploration permits, held by Vintage Energy and Comet Ridge
Galilee Pty Ltd, to users in Moranbah. As shown in Figure 83, the pipeline route traverses approximately
240km from the Galilee Basin, west of Clermont, and terminates just east of Moranbah.

A memorandum of understanding (MOU) was signed between APA, Comet Ridge and Vintage in May
2019 outlining the concept of the project. In August 2019, APA were granted a pipeline survey license by the Queensland Government. APA continues to investigate potential capacities and market scenarios for the pipeline, as such, the pipeline has not been sized, and its proposed capacity is unknown. Further development of this project requires a financial commitment by Comet Ridge and Vintage Energy Ltd.

Figure 83 APA Group Galilee Pipeline and project area
(Source: Comet Ridge (2019). Galilee Basin – Galilee Moranbah Pipeline Update. ASX Announcement.)

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Blue Energy Pipeline
A pipeline connecting Blue Energy’s landholdings in Moranbah to the gas hub of Wallumbilla has been proposed. This option is not well progressed; however Blue Energy have suggested a multi-user, approximately 500km pipeline from Moranbah to Wallumbilla to connect to the Wallumbilla Gladstone
Pipeline (WGP) owned by APA. The proposed connection could deliver up to 300 TJ/d into the east coast gas network.

Figure 84 Proposed expansion of Northern Gas Pipeline (Jemena).
(Source: Blue Energy ASX Market Announcement 2020)

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Jemena Expansion of Northern Gas Pipeline
Jemena plans to extend their existing Northern Gas Pipeline (NGP), which connects Warrego in the
Northern Territory to Mt Isa in Queensland. Completed in 2019, the NGP’s current capacity is 90 TJ/d.
Jemena’s planned expansion could see this increase to up to 1000 TJ/d, through an extension from
Mount Isa to Wallumbilla at the southern end and Tennant Creek to Darwin at the northern end (refer
Figure 85).

Although this proposed pipeline would supply gas into Wallumbilla, with a potential lateral connection to the Galilee Basin, a link to the Bowen Basin is currently not included.

Figure 85 Proposed expansion of Northern Gas Pipeline (Jemena).
(Source: Industry Queensland (2020). Galilee gas deal firms Jemena's pipeline extension plans)

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9.3 Concept Study Options
9.3.1 Pipeline route options
Pipeline route options have been developed at a high-level considering a number of criteria as described in Table 26. The routes developed as part of this Study should be considered indicative of likely corridors for a pipeline, it is important to understand that this assessment is provided to confirm that reasonable pipeline corridors exist, to determine the likely length of pipelines to enable estimated pipeline diameters and costs to be developed, and to provide an understanding of key options in macro-level pipeline routing for the Bowen Basin.

Table 26 – Route considerations
(Source: GHD Analysis)

Criteria Description

Terrain The terrain traversed by the pipeline can introduce additional design
complexity and significantly affect the cost of construction and project
schedule. Ideal terrain consists of soft soils and flat, sparse landscapes, as is
typical of central Australia. Terrain that is preferably avoided includes
mountainous areas, rocky soils, wet soils or bodies of water, contaminated or
corrosive soils, areas susceptible to landslides/seismic activity,
Constructability Pipeline constructability is strongly dictated by the terrain, however additional
factors such as access for construction vehicles and proximity to towns has
been considered.
Land access A combination of public and private land may be required to be traversed by
the pipeline. Additional land access is also required for the construction right
of way. Landowner approval is required for the entire pipeline route. Also, the
pipeline route should avoid land subject to native title, cultural heritage or
environmental constraints (refer sections 10.3.2-10.3.7 of this report). Existing
assets, such as power lines, should be avoided where possible due to land
access and design issues.
Land use Current and future land has been considered, where possible avoiding areas
subject to development.
High consequence areas The pipeline should ideally avoid high consequence areas, defined in AS 2885
(Pipelines-Gas and liquid petroleum) as Residential, High Density, Industrial,
Sensitive (such as schools, aged care and hospitals) and Environmental. There
are specified design requirements if high consequence areas are unavoidable,
however these introduce additional cost to the project as well as increasing
project risk.
Proximity to gas producing In the case of a multi-user pipeline, it is beneficial to route the pipeline nearby assets and users both suppliers and users of the gas, to minimise the length of required lateral
pipelines.
Length Theoretically, the shortest pipeline is the most cost effective, with less
pressure drop and materials required for construction. However, due to the
factors above the most direct route is usually not entirely feasible, and
therefore pipeline length must be optimised alongside the other factors.

Furthermore, indicative routes were considered focusing on the following parameters:

• Start location – This was assumed as connecting to the existing Moranbah Gas Process Facility with
a separate connection to the NQGP;

• End locations, focused on connecting to the ECGM;

• Likely coal seam gas production areas within the basin;
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• Existing coal mine operations for access to incidental mine gas;

• Environmental no-go zones;

• Geography – avoiding or minimizing exposure to areas such as:

o mountainous terrain

o major water courses or major flood plan areas

o existing mine operations

o towns

o National Parks and State Forests

• Pipeline length – minimisation of the pipeline length, whilst consideration of the above items.

These factors were considered most important when considering the maximum utility of coal seam gas production as well as maximising the likelihood of recovery of incidental mine gas. That is, what routing will provide the greatest benefit to achieve the objectives of the scope of work over the life of the basin.
It is noted that a pipeline proponent may take a different view for various commercial reasons, and this can be observed in Section 9.2, with some of the differences when comparing the routes below with those previously proposed by potential proponents for Bowen Basin pipelines.

As illustrated in Figure 86 and summarised in Table 27, a number of pipeline options were identified which support the potential development cases described in Section 7. These routes are considered the main options available and should be considered as indicative corridors. It is expected that corridor refinement will occur in subsequent phases of Basin development. The options considered covered the east, central and western extents of the basin. The routes are described in more detail in the following sections.

Table 27 Identified Pipeline Options

(Source: GHD Analysis)

Option Description Pipeline Length Applicable Development Case
(km)

Option 1 Moranbah to Gladstone 415 Blackwater region

Option 2A To Rolleston (West), tie into QGP and 340 Mahalo region
GTP Whole of Basin
Option 2B To Rolleston (East), tie into QGP and 390 Mahalo region
GTP Whole of Basin
Option 3 To Moura, tie into QGP and GTP 350 Mahalo region
Whole of Basin
Option 4 NQGP 391 Moranbah

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Figure 86 - Identified Pipeline Options

(Source: GHD Analysis)

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Route Option 1 – Moranbah to Gladstone
This route largely follows the same route proposed by Arrow for their proposed LNG export pipeline.
The route tracks to the east of Basin and connects into the gas transmission pipeline infrastructure in the Gladstone region, the pipeline corridor is assumed to end in the Aldoga area to the west of
Gladstone. There is the ability to connect to the pipelines to the LNG facilities as well as the QGP, which delivers gas to a range of customers in the Gladstone region and via lateral pipelines to Rockhampton in the north and Maryborough in the south.

Figure 87 - Option 1 - Moranbah to Gladstone
(Source: GHD Analysis)

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Route Option 2A – Moranbah to Rolleston (West)
This route tracks along the west of the Basin and is the most direct route to joint into the existing transmission pipelines that transit near the town of Rolleston. This route avoids the mountain ranges that are between Moranbah and Middlemount, running near the town of Emerald. Whilst this route is the shortest, it is west of the existing coal mines and potential coal seam gas resource in the order of
20 to 30 km for the first half of the route. The route picks up the prospective Mahalo and Mahalo North areas.

Figure 88 - Infrastructure Option 2A – To Rolleston (West)

(Source: GHD Analysis)
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Route Option 2B – Moranbah to Rolleston (East)

This route tracks through the centre of the Basin to the Blackwater area, and then turns westward to route past the prospective Mahalo and Mahalo North areas before connecting into the existing transmission pipelines that transit near the town of Rolleston. This route is 40 km longer than the most direct route, and is likely to be the most complex route, as it will need to consider many mine and other gas leases, and existing infrastructure that service the mine operations.

However, as this option traverses more potential gas reserves particularly in the Blackwater region, and offers the greatest potential CMM capture, the upside is considered to outweigh the risk when considering the objectives of this study.

Although processing CMM for pipeline export is an unlikely use case when compared to power- generation, this route option presents the best opportunity to do so compared to other route options.
Additionally, improving the pre-drainage of open cut mines would be more likely if there were a local pipeline to access, as is provided by this option.

Therefore, this route is the preferred route by this study.

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Figure 89 - Infrastructure Option 2B – To Rolleston (East)
(Source: GHD Analysis)

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Route Option 3 – Moranbah to Moura

This route tracks through the centre of the basin to the Blackwater area, and then stays on reasonably constant trajectory toward the east side of the basin before connecting into the existing transmission pipelines that transit to the north of the town of Moura. This route is 10 km longer than the most direct route, the southern half of this route is not expected to be a prospective for gas sources as Route
Option 2B as there are limited mine or petroleum leases between Blackwater and Moura.

Figure 90 - Infrastructure Option 3 – To Moura
(Source: GHD Analysis)
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Option 4 – No new pipeline
This route is included for completeness, this is the existing route of the QGP. This route is on the western side of the Basin and the existing petroleum and mine leases. It is expected that it would require lateral pipelines to connect any new gas production developments to the north of Moranbah.
The lateral pipelines could be between 10 km to 40 km in length.

Figure 91 - Option 4 – No new pipeline
(Source: GHD Analysis)

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9.3.2 Preliminary route assessment
The selection of a particular pipeline route from one point to another requires a multi-criteria assessment to optimise the many constraints. Route selection is ultimately an iterative process requiring consultation between landowners, regulatory bodies, pipeline owner, engineers, constructors and other project stakeholders. However, to inform the outcomes of this Study, a Strategic Merit Test (SMT) was undertaken. The SMT was used to filter options according to their ability to meet the Study’s objectives for the development of the Basin. A SMT is not intended to be comprehensive, but is an initial check of project options for strategic merit that:

“Rules an option in or out at an early stage of the assessment process; and identifies those options that should proceed to the next stage of the appraisal, options that require further work and those that should be abandoned because they are inconsistent with the jurisdiction’s objectives and strategies”

Figure 92 below summarises the results of the SMT. The assessment criteria were selected to reflect the ability of the pipeline route to address the Government’s objectives for the Basin of:

• Improving surface economic viability of gas production and providing gas to market to deliver shared
benefits for the region and the State as a whole;

• Delivering efficient, multi-user gas transport infrastructure that will unlock gas resources;

• Enhanced commerciality of gas field developments in the Basin;

• Future-proofing gas supplies in Queensland; and

• Better management of incidental coal mine gas.

Figure 92 – Strategic Merit Test

Gas to market
Due to the need to service the expected shortfall of gas supplies into the ECGM by the mid-2020s, the assessment was based on connecting the Bowen Basin to the ECGM. Whilst forecasts from AEMO can and do move around with time, given they are a snapshot of a dynamic market, the overall conclusions from our analysis are that there is a trend of supply/demand gaps emerging beyond the end of this decade, and that more gas is needed based on current demand forecasts.

Option 1 would be more effective for export of gas via LNG through its connection to Gladstone.
Options 2A, 2B and 3 with a connection to Wallumbilla, would be more effective for supply to the
ECGM.
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There is a higher capex involved for Option 2B but there is a greater upside with more gas being able to access the pipeline. Option 2B would be able to capture more of the gas suitable for pipeline injection from Moranbah, Blackwater and Mahalo regions, when compared to Option 2A. Option 2A presents a similar opportunity, however, it is expected that it would be more difficult economically to access gas resources in the Blackwater region.

Although, it is noted that once a connection is made into a pipeline, there are commercial ways to get contractual gas flows to the customer within the ECGM or to LNG export (location-based gas swaps).

Unlocking gas resources
The assessment was based on the number of gas permits the pipeline route supports.

When considering the options, Option 1 with a connection to Gladstone does not effectively capture the majority of gas permits in the Basin, supporting only the unlocking of the Moranbah region.
Furthermore, it would require a significant gathering network and large processing facilities in
Moranbah.

Options 2A and 2B with a connection to Wallumbilla support a whole-of-Basin solution, passing close to many existing exploration permits across both the Blackwater and Mahalo regions. Due to the close proximity of the existing exploration permits, these options also require a less significant gathering network, with several smaller processing facilities for local tie-in to the pipeline.

Although Option 3 provides a connection to Wallumbilla from Moranbah, as there are limited mine or petroleum leases between Blackwater and Moura, the southern half of this route is not expected to be as prospective for gas sources as Route Option 2B.

Capturing incidental coal mine gas
Options 2A and 2B run in close proximity to the existing exploration permits and maximise the utility of methane from coal in the Basin, from both mining operations and coal seam gas production. Option 2B provides the closest access to the majority of the prospective resource and is considered the route which maximises the capture of incidental coal mine gas. As described above, the southern half of
Option 3 is due to the limited mine or petroleum leases between Blackwater and Moura.

Due to its alignment, there is limited opportunity for Option 1 to capture incidental coal mine gas.

Supporting regional development
By supporting the development of the whole Basin, Options 2A, 2B and 3 offer a range of regional development opportunities. By only supporting the development of the Blackwater region and its supply of gas predominately to the LNG export market, Option 1 is considered to result in minimal regional development opportunities.

When considering the Government’s objectives for the Basin as part of this Study, based on the above
SMT, Option 2B delivers the greatest alignment to these strategic outcomes.

9.3.3 Pipeline sizing methodology
The sizing basis used for the gas pipelines used the typical approach applied to sizing gas pipelines and relied on experience gained over several decades, including specific experience with coal seam gas.
The assessment assumed that a gas compression facility is require at the end of the Bowen Basin
Pipeline, this is to enable gas to be injected into the existing pipelines that are connected to the East
Coast Gas Market.

Key parameters used in the sizing including the following:

• Pipeline surface roughness consistent with typical practice in Australia – this is used to determine
the pressure loss in the pipeline
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• Maximum gas velocity limit at the pipeline outlet consistent with typical practice in Australia – this
a key design limit used in pipeline sizing

• A pipeline Maximum Allowable Pressure of 10.2 MPag – This pressure is more typical for gas
transmission pipelines in coal seam gas application and enables a materially lower gas compression
ratio at the gas processing facilities.

• Gas composition was typical coal seam gas composition for Queensland.

Bowen Pipeline Technical Parameters
The preliminary technical details for the new pipeline corridor options, for a range of possible flowrates, are shown in Table 28.
Table 28 - Indicative Pipeline Technical Parameters
(Source: GHD Analysis)

Inlet
Length Outlet Pressure
Route Option Pressure Flow (TJ/d) Diameter
(km) (MPag)
(MPag)

50 DN250
100 DN350
Moranbah to 150 DN450
Gladstone 415 15.3 7.0
(Option 1) 200 DN500
250 DN550
300 DN600

Moranbah to Rolleston 50 DN250
340
(West) (Option 2A) 100 DN400

Moranbah to Rolleston 150 DN450
390 10.2 5.0
(East) (Option 2B) 200 DN550

Moranbah to Moura 250 DN600
350
(Option 3) 300 DN650
Moranbah to
Townsville
391 15.3 (max) 5.0 108 TJ/d DN 300
(Option 4)
(note 1)
1. Option 4 refers to the existing NQGP, and no new pipeline is proposed for this option.
The maximum allowable operating pressure for the proposed Arrow Bowen Pipeline from Moranbah to
Gladstone was presumed to be 15.3 MPag.

Operating pressures considered for proposed pipeline routes between Moranbah and Rolleston were indicative and were predominantly based on Queensland Gas Pipeline (QGP) operating data. A preliminary value of 10.2 MPag was considered matching that of typical QGP operating conditions.

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9.4 Commercial
9.4.1 Approach to estimating
Estimation of capital costs for the infrastructure has used a factored approach, which is consistent with the industry approach for concept studies, where costs are used to inform options and the likely overall costs for a project.

The basis used for this report uses the following rates for each the following elements of the gas production and pipeline infrastructure. The assumed configuration of the gas producing assets was on a fit-for-purpose basis, where engineering specifications are such that the asset delivers a reasonable level of reliability and complies with the minimum industry standards. The rates used are considered as representative of efficient cost rates that would be observed under reasonable market conditions for construction, i.e. an average level of resource project construction across Australia.

The unit rates for capex calculations were as follows:

1. Cost rates for well connection costs which include flowlines and well pad facilities were considered
as $1 to 1.5 million per well connection (note this is additional to the well drilling costs stated in
Section 7.1.2).

2. Cost rates for gas processing facilities were considered as $3 to $4 million per TJ/day capacity.

3. Cost rates for pipelines were considered as $70,000 per inch per kilometre.

9.4.2 Capital Expenditure
Estimated capital expenditure (Capex) for various identified pipeline options are presented below.
Table 29 - Option 1 – Moranbah to Gladstone Gas Infrastructure
(Source: GHD Analysis)

Parameter Moranbah + Blackwater

Flowrate 225 TJ/d (150 TJ/d Moranbah + 75 TJ/d Blackwater)
~ 1,700 wells & gathering network
1 x new gas processing facilities
Required Infrastructure
Expansion of MGP
DN500, 415 km pipeline operating at 15.3 MPag
Wells/gathering: $1-1.5M per well
Estimated Capital Expenditure Processing facilities: $700M
Pipeline: $580M
Development Timeline
5 years
(best case)
Viability of wells in central Bowen is unknown
Final ¾ of pipeline route does not utilize gas or mining
Risks
assets
No incremental development possible – all or nothing
Notes:

1. Compression has only been allowed for at the GPFs.
2. Blackwater gas is assumed from the norther area of Blackwater closest to the pipeline route
3. Pipeline capacity could be expanded in the future up to 400 TJ/d by adding mainline compressor stations.

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4. Of the 200 TJ/d from the Moranbah region as stated in the production scenarios (refer Figure 6), 50 TJ/d has
been assumed to be transmitted North via the NQGP, with the remainder being transmitted via the new
pipeline to Gladstone.

Table 30 - Option 2A – To Rolleston (West) Gas Infrastructure
(Source: GHD Analysis)

Parameter Mahalo Mahalo + Moranbah
300 TJ/d (Mahalo 150 TJ/d +
Flowrate 180 TJ/d
Moranbah 150 TJ/d)
~ 2,000 wells & gathering network
~ 1,158 wells & gathering network
3 new gas process facilities and
2 x new gas processing facilities
Required Infrastructure MGP expansion
End of line compression (~7 MW)
End of line compression (~ 8MW)
DN400, 140 km pipeline operating at
DN550, 340 km pipeline operating at
10.2 MPag
10.2 MPag
Wells/gathering: $1-1.5M per well Wells/gathering: $1-1.5M per well
Estimated Capital Expenditure Processing facilities: $630M Processing facilities: $1,155M
Pipeline: $160M Pipeline: $520M
Development Timeline
4 years 6 years
(best case)
Would need to oversize initial Viability of wells in central Bowen is
southern pipeline (to DN550), or loop unknown, pipeline would need to
in the future, or add additional future extend to Moranbah for proven
Risks compression, to unlock Moranbah. resources
Additional upfront cost on oversized Route does not optimize proximity to
pipeline adds ~40% to pipeline cost mines / gas resources in
only. Middlemount & Blackwater areas
Notes:

1. Compression has only been allowed for at the GPFs and end of line to tie into QGP.
2. Pipeline capacity could be expanded in the future up to 400 TJ/d by adding mainline compressor stations.
3. Of the 200 TJ/d from the Moranbah region as stated in the production scenarios (refer Figure 6), 50 TJ/d has been assumed
to be transmitted North via the NQGP, with the remainder being transmitted via the new pipeline to Gladstone.

Table 31 - Option 2B – To Rolleston (East) Gas Infrastructure
(Source: GHD Analysis)

Parameter Mahalo Mahalo + Blackwater + Moranbah
375 TJ/d (Mahalo 150 TJ/d +
Flowrate 180 TJ/d Blackwater 75 TJ/d + Moranbah 150
TJ/d)
~ 2,400 wells & gathering network
~ 1,158 wells & gathering network
4 x new gas processing facilities and
2 x new gas processing facilities
Required Infrastructure MGP expansion
End of line compression (~7 MW)
End of line compression (~ 9MW)
DN400, 140 km pipeline operating at
DN550, 390 km pipeline operating at
10.2 MPag
10.2 MPag
Wells/gathering: $1-1.5M per well Wells/gathering: $1-1.5M per well
Estimated Capital Expenditure Processing facilities: $630M Processing facilities: $1,225M
Pipeline: $160M Pipeline: $600M
Development Timeline
4 years 6 years
(best case)
Would need to oversize initial Viability of wells in central Bowen is
southern pipeline (to DN550), or loop unknown, pipeline would need to
in the future, or add additional future extend to Moranbah for proven
Risks compression, to unlock Moranbah. resources
Additional upfront cost on oversized Constructability of pipeline route
pipeline adds ~40% to pipeline cost through Middlemount & Blackwater
only. due to mines
Notes:

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1. Compression has only been allowed for at the GPFs and end of line to tie into QGP.
2. Pipeline capacity could be expanded in the future up to 400 TJ/d by adding mainline compressor stations.
3. Of the 200 TJ/d from the Moranbah region as stated in the production scenarios (refer Figure 6), 50 TJ/d has been assumed
to be transmitted North via the NQGP, with the remainder being transmitted via the new pipeline to Gladstone.

Table 32 - Option 3 - To Moura Gas Infrastructure
(Source: GHD Analysis)

Parameter Blackwater + Moranbah
Flowrate 225 TJ/d (Blackwater 75 TJ/d + Moranbah 150 TJ/d)
~ 1,600 wells & gathering network
Required Infrastructure 2 x new gas processing facilities and MGP expansion
End of line compression (~ 8MW)
DN500, 350 km pipeline operating at 10.2 MPag
Wells/gathering: $1-1.5M per well
Estimated Capital Expenditure Processing facilities: $700M
Pipeline: $490M
Development Timeline
6 years
(best case)
Viability of wells in central Bowen is unknown, pipeline would
need to extend to Moranbah for proven resources
Risks
Constructability of pipeline route through Middlemount &
Blackwater due to mines
Notes:

1. Compression has only been allowed for at the GPFs and end of line to tie into QGP.
2. Pipeline capacity could be expanded in the future up to 400 TJ/d by adding mainline compressor stations.
3. Of the 200 TJ/d from the Moranbah region as stated in the production scenarios (refer Figure 6), 50 TJ/d has been assumed
to be transmitted North via the NQGP, with the remainder being transmitted via the new pipeline to Gladstone.

Table 33 - Option 4 - No new pipeline
(Source: GHD Analysis)

Parameter Moranbah

Flowrate 50 TJ/d
Required Infrastructure 265 wells & gathering network
Upgrade of Moranbah Gas Processing facility
No new pipeline – use NQGP Pipeline
No end of line compression
Estimated Capital Expenditure Wells/gathering: $ 1-1.5M per well
Processing facilities: $175M
Pipeline: Nil
Development Timeline 3 years
(best case)
Risks Lack of gas demand in Townsville

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9.4.3 Operating Expenditure
Annual operating expenditure (Opex)for the gas infrastructure is based on high-level benchmarks that are used in the industry. For this level of assessment is it typical to use a percentage of capital cost as the annual operating expenditure estimation. These cost are all inclusive, and cover items such as:

• Field labour; • Utilities;

• Vehicles and machinery; • Support staff;

• Maintenance and consumables; • Insurance; and

• Energy (electricity or gas) for powering • Overheads.
facilities and compression;

These operational expenditure rates are as follows:

• Gas production systems annual operating expenditure, inclusive of well pads, gathering system,
gas process facility and produced water handling – 5% to 10% of gas production system initial
Capex (excludes sustaining well connections).

• Gas pipeline annual operating expenditure – 1% to 2% of pipeline Capex.

It is noted that there are many factors that can change the annual operating expenditure, however the amounts defined above are considered appropriate for an efficient operator.

9.4.4 Sensitivities
Key sensitives include the following capex items:

• Number of wells to be connected;

• Gas process facility complexity;

• Distance of gas source from gas pipeline; and

• Pipeline route length.

The most significant sensitivity is the number of wells to be connected, driven by uncertainty in well productivity, as this will materially alter the cost of the overall basin development. This cost includes the wells to be drilled, well pads and gathering system to connect the well pad to the gas process facility. Whilst the unit cost of wells is known with a reasonable level of certainly, and each well and associated connecting will have a cost variation likelihood, given the large quantity of well connections it is typical the aggregated potential cost variation is materially less than the unit average. It is the number of wells required to produce an aggregated gas flow rate that will produce the largest cost change, given this is the highest area of uncertainty. This is a cost sensitivity that is highest in coal seam gas production, when compared to other forms of onshore gas production, given the typical range of flow per well.

The other key capex items will have sensitivities; however these are likely within a range in the order of 30% around the estimated numbers. Given these costs are less than half of the total costs of the basin development, the sensitivity is substantially less than the productivity of the wells.

Opex is generally not a material sensitivity for gas developments given the percentage it contributes to total project lifecycle costs in the order of 15% to 20%, therefore a material change in annual opex generally results in a modest change in the project lifecycle costs.

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9.4.5 Enablers and challenges
The following table summarises the key enablers and challenges for the identified pipeline route options.
Table 34 - Enablers and Challenges
(Source: GHD Analysis)

Infrastructure Option Enablers Challenges
Final ¾ of pipeline route does not optimize
Option 1 access to gas or mining assets
No incremental development possible – all
Moranbah to Gladstone Proven gas resources & well viability
or nothing
Highest capital expenditure relative to
flowrate.
Route does not optimize proximity to
mines / gas resources in Middlemount &
Option 2A Blackwater
Enables staged development, requiring
To Rolleston (West) Would need to oversize initial southern
less upfront capital
pipeline (to 22 in.) to unlock full future
potential, or install future mainline
compression, or loop pipeline.

Option 2B
Enables staged development, requiring
To Rolleston less upfront capital Constructability of pipeline constrained
(East) Provides mines access to gas through mining operations & leases
transmission infrastructure

Option 3 Enables staged development, requiring Constructability of pipeline constrained
less upfront capital through mining operations & leases
To Moura
Provides mines access to gas Southern section to Moura does not
transmission infrastructure unlock any new gas resources

Option 4 Lack of gas demand in Townsville
Lowest capital investment
No new pipeline Future expansion requires new pipeline
Proven gas resources & well viability
Does not improve capture of coal mine
Shortest development timeline
gas – separate infrastructure required

Key insights from the table above include the following:

• There are a number of ways to route a pipeline from the Bowen Basin to connect into the East
Coast Gas Market, there are pros and cons of each option.

• The likely cost variation, for a like for like pipeline, is broadly a percentage of the route length
variation. Given the maximum variation in length of the options is in the order of 20%, then the
range of capital cost variation will be in this range.

• The most easterly and westerly routes have the least ability to enable the maximum utility of coal
seam gas production and use of incidental mine gas pre-drainage, due to proximity.

• Option 2A and 2B enables staged development in a South to North manner, on the basis that the
Mahalo and Mahalo North projects are developed. This could provide a staged development, to
enable southern section of the basin to be developed earlier than may occur with a full basin
pipeline. None of the other identified options appear to provide this flexibility.

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10. Approval requirements
Project approvals can be considered a function of the nature, extent and magnitude of proposed project activities, associated disturbance footprint and impact. There are corollary approval requirements which also need to be satisfied in order to enter/access land to undertake the proposed project activities.

Regardless of the corridor option nominated for the proposed Bowen Basin Gas Pipeline, numerous
Tier 1, 2 and 3 planning and environmental approvals, at the Commonwealth and State level, will need to be obtained for the project.

Broadly speaking, Tier 1, 2 and 3 approvals can be described according to the following:

• Tier 1: Major approvals required to enable the overall project e.g. Environmental Approval by State
and Commonwealth Governments, Petroleum & Gas Lease, Native Title consent

• Tier 2: Approvals relating to specific project elements with long durations and requiring a high level
of project definition e.g. Land use (development) consent, resource entitlements, permits for
operational works, and permits for removal of vegetation

• Tier 3: Construction approvals e.g. registration certificates, licence to store flammable or
combustible goods on premises, navigational aids approvals, etc

Tier 1 approvals are typically obtained first as they incorporate much of the supporting information for
Tier 2 and 3 approvals.

10.1 Key Legislation and Approval Options
The following sections outline the typical project approval pathways for major energy and resource projects. As individual project design and scale are clarified, and inputs from agencies received, the approvals required will need to be reassessed.

Projects of this nature and scale would typically opt for declaration as a “Coordinated Project” under the State Development and Public Works Organisation Act 1971 (SDPWO Act) and will undertake an
EIS under the Queensland and Commonwealth Government bilateral arrangement for environmental assessment. This pathway tends to offer the most efficient and streamlined approach for major project approvals.

Refer to Appendix C for the breakdown on the potential approval requirements.

Approvals Process Flow
A high-level project approval process, likely to be relevant to a project of this nature, is shown in Figure
93. Approval processes may be able to be run concurrently with other project aspects but the benefit and practicality of this needs to be assessed based on the proposed project staging, selected approvals pathway and the project delivery timeframes.

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Figure 93 Approvals Pathway Flow Diagram
(Source: GHD Analysis)

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Designated Corridor
There is potential for the Queensland Government to designate an infrastructure corridor to fast-track development within the Basin. This infrastructure corridor would enable not only pipeline development, but utilities development as well including gas, power and water.

The coordination and declaration of a State Development Area (SDA) would provide many benefits with regards to the establishment of a gas pipeline in the Bowen Basin including:

• Provides greater certainty about approval processes

• Ensures the land was safeguarded from inappropriate uses

• Offers coordination with the private landholders including consultation to determine the preferred
corridor alignment and negotiation of an easement

• Provides acquisition of an easement through the privately owned land and provision of a license to
the LNG proponents for the construction and operation of the pipeline

• Minimisation of impacts to landholders and the environment through efficient use of land

• Minimises risks of project delays from third party legal challenges.

10.2 Likely Suite of Approvals Required
A significant number of environmental and planning approvals are required for major petroleum and gas projects in Queensland to proceed, with the most critical approval being the EIS. An effective and proactive Government engagement program is essential also to manage approvals and mitigate the potential for approval delays. The complexity of major petroleum and gas projects also requires an effective interface between the proponent, community consultation team, environmental specialists and the engineering teams. This is necessary to manage approvals issues that may arise.

Table 35 below lists the indicative key legislative requirements triggered by works to support major petroleum and gas projects in Queensland, noting this list is not exhaustive. The exact number, type and nature of the approvals required for a project will not be completely known until site selection occurs.
Table 35 Indicative Legislative Requirements
(Source: KPMG Analysis)

Legislative Requirement Relevant Legislation Administrator

Commonwealth Approvals

Approval of a controlled action Environment Protection and Biodiversity Department of
Conservation Act 1999 Agriculture, Water
and the Environment
(DAWE)

Permission to impact on land where Native Title Act 1993 Native Title Tribunal native title has not been extinguished

Permission to intervene in matters where Aboriginal and Torres Strait Islander Heritage DAWE traditional cultural heritage interests are Protection Act 1984 considered to be at risk

Reporting under National Greenhouse and National Greenhouse and Energy Reporting Act Clean Energy
Energy Reporting Scheme (NGERS) Regulator

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Legislative Requirement Relevant Legislation Administrator

State Approvals

Coordinator-General’s EIS evaluation State Development and Public Works Coordinator General report Organisation Act 1971

A Cultural Heritage Management Plan Aboriginal Cultural Heritage Act 2003 Department of
(CHMP) or native title agreement Environment and
Science (DES)

Development Permit for Operational Coastal Protection and Management Act 1995, DES and relevant
Works for work within a Coastal State Coastal Management Plan, Planning Act local council
Management District 2016 and Planning Regulation 2017

Approval for the removal or placement of Coastal Protection and Management Act 1995, DES quarry material below high-water mark State Coastal Management Plan, Planning Act
2016 and Planning Regulation 2017

Approval to damage vegetation on State Coastal Protection and Management Act 1995 DES coastal land

Permit for the handling, storage and Dangerous Goods Safety and Management Act Department of manufacture of hazardous materials, and 2001 Emergency Services dangerous goods

Notice prior to carrying out work affecting Electricity Act 1994 Relevant Electricity electricity entity's works Entity

Undertaking a prescribed activity as per Environmental Offsets Act 2014 DES the for which there will be a significant residual impact on one or more prescribed environmental matters

Environmental authority for undertaking Environmental Protection Act 1994 and DES an environmentally relevant activity Environmental Protection Regulation 2019

Development Permit for a Material Environmental Protection Act 1994, DES
Change of Use of premises for Environmental Protection Regulation 2019 and environmentally relevant activities Planning Act 2016

Development Permit for a Material Environmental Protection Act 1994 and Planning DES
Change of Use of premises for Act 2016 development on contaminated land

Disposal permit to remove and treat or Environmental Protection Act 1994 DES dispose of contaminated soil from land

Development Permit for Operational Fisheries Act 1994 and Planning Act 2016 Department of
Works for constructing or raising Agriculture and waterway barrier works Fisheries (DAF)

Development approval for Operational Fisheries Act 1994 and Planning Act 2016 DAF
Works for removal, destruction or damage to a marine plant

Permit to get or sell forest products or Forestry Act 1959 and Land Act 1994 DAF quarry materials

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Legislative Requirement Relevant Legislation Administrator

Permit to occupy and clear vegetation on Land Act 1994 State Land Asset
State Land Management Unit
within Department of
Resources

Permit to take protected plants (clearing Nature Conservation Act 1992 and Regulations DES permit)

Petroleum Pipeline License (PPL) Petroleum and Gas (Safety and Production) Act Department of
2004 Resources (DoR)

Development Permit to undertake Queensland Heritage Act 1992 and Planning Act DES development on a registered Queensland 2016 heritage place

Approval to enter or interfere with a Queensland Heritage Act 1992 DES protected heritage area

Development Permit for a Material State Development and Public Works Coordinator-General
Change of Use for gas transportation Organisation Act 1971, Development Scheme for infrastructure the Gladstone State Development Area

Development Permit for a Material State Development and Public Works Coordinator-General
Change of Use for Materials Organisation Act 1971, Development Scheme for
Transportation and Services Infrastructure the Stanwell-Gladstone Infrastructure Corridor
State Development Area

Owners Consent Planning Act 2016 DES

Road Corridor Permit / Ancillary Works Transport Infrastructure Act 1994 Department of and Encroachment Permit Transport and Main
Roads (DTMR)

Traffic Control Permit Transport Infrastructure Act 1994 DTMR

Written approval to interfere with a Transport Infrastructure Act 1994 DTMR railway – Wayleave agreement

Development Permit for Operational Vegetation Management Act 1999 DES
Works for clearing native vegetation

Clearing Notification Vegetation Management Act 1999 DES

Development Permit for Operational Water Act 2000 and Planning Act 2016 Department of
Works for taking or interfering with water Regional for overland flow including using a Development, watercourse pump, storing, diverting, Manufacturing and damming or removing quarry material Water (DRDMW) from a watercourse

Water Licence Water Act 2000 DoR

Riverine Protection Permit Water Act 2000 and Regulations DRDMW

Local Approvals

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Legislative Requirement Relevant Legislation Administrator

Development Permit for a Material Relevant local government planning scheme, Relevant local
Change of Use for temporary worker Planning Act 2016 and Planning Regulation 2017 Council accommodation camps under a Planning
Scheme

Development Permit for Operational Relevant local government planning scheme, Relevant local
Works under a Planning Scheme Planning Act 2016 and Planning Regulation 2017 Council

Development Permit to undertake Planning Act 2016 and Planning Regulation 2017 Relevant local development on a registered local Council heritage place

Permits under Local Laws Local Government Act 2009 Relevant local
Council

Development Permit for Building Work Building Act 1975 and Regulations, Planning Act Relevant local council
2016 and Planning Regulation 2017 or private building
certifier

Temporary road closure – issue of road Local Government Act 2009 (and other relevant Relevant local license acts e.g. Plumbing and Drainage Act 2002) Council

10.3 Key approval considerations
As presented in Table 35, a number of approvals are required under Queensland and Commonwealth legislation before the construction and operation of petroleum and gas projects can commence.

Environmental and social risks associated with a project could delay delivery and present financial risks.
Delays to the granting of approvals and permits can also result from either slow Government response times or from requests for additional information regarding likely project constraints. Legal challenges can also occur and delay time to securing approval.

Key approval considerations that have the potential to impact a project schedule, particularly for major petroleum and gas projects in Queensland, are outlined below.

10.3.1 Water
Work that may interfere with or impact on water courses, particularly within the bed and banks, would trigger the requirements of the Water Act 2000 and, as necessary or desirable, would need to be discussed with the Department of Resources. Activities involving excavation, filling or the destruction of vegetation in a watercourse would require a riverine protection permit.

Additionally, proponents for a CSG or large mining project that are likely to have a significant impact on a water resource will need to refer the project to the Commonwealth to determine whether the project is considered a controlled action under section 68 of the EPBC Act.

The Significant Impact Guidelines 1.3: Coal seam gas and large coal mining developments – impacts on water resources state that an action is likely to have a significant impact on a water resource if there is a real or not remote chance or possibility that it will directly or indirectly result in a change to:

• The hydrology of a water resource; or

• The water quality of a water resource,

• That is of sufficient scale or intensity as to reduce the current or future utility of the water resource
for third party users, including environmental and other public benefit outcomes, or to create a
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material risk of such reduction in utility occurring. A significant impact on water resources may be
caused by one development action relating to a CSG project or large coal mine, or the cumulative
impact of such actions.

10.3.2 Land acquisition
Acquisition of land from a number of landholders would likely be required for the Bowen Basin Gas
Pipeline project. This presents a risk as the Project may encounter opposition from landholders. Risks can be minimised through maintaining effective communication with Government representatives and affected landholders throughout the approvals process. Early submission of permit applications, compliance with Government requirements and effective stakeholder engagement would also assist in minimising permit risks. Commencement of the land acquisition process as early as possible is recommended.
Interference with landholder activities would also need to be investigated as part of an EIS. Each affected landholder would need to be consulted as part of the EIS/approvals process to discuss his/her specific requirements, establish compensation agreements and mitigate potential impacts to local land tenure.

10.3.3 Overlapping tenure
Almost 90% of Queensland’s coal and coal seam gas tenure is overlapped, which in the past has led to an adversarial outcome to the benefit of no one. A revised framework for addressing overlapping tenure was incorporated into the Mineral and Energy Resources (Common Provisions) Act 2014.
The new overlapping tenure framework is a legislated default regime which applies where overlapping parties cannot otherwise agree. The framework seeks to optimise the safe development of
Queensland’s coal and coal seam gas resources by:

• Simplifying the pathway to and improving the certainty of the grant of overlapping tenure

• Incentivising negotiated arrangements for collaborative and cooperative concurrent production of
both resources in overlapping areas

• Providing a default set of arrangements and dispute resolution processes to provide certainty to
arrangements for coordination of activities if the parties cannot agree between themselves

• Providing a structure for joint coordination and management of health and safety

• Reducing administrative burdens, while preserving production rights already granted.

Overlapping tenure holders who are subject to the overlapping tenure regime in Chapter 4 of the Mineral and Energy Resources (Common Provisions) Act 2014 are subject to mandatory requirements to exchange all information reasonably necessary to allow them to optimise the development and use of coal and CSG resources and to meet to discuss this information.

10.3.4 Coexistence issues
A simultaneous operations zone is an area where coal and CSG production activities can co-exist. A key feature of the revised overlapping tenure framework is the requirement for a joint interaction management plan (JIMP) in various overlapping operating scenarios.
In relation to the JIMP requirements under the respective safety legislation, the party responsible under that legislation to make a JIMP must make reasonable attempts to consult with the other party. The party responsible to make a JIMP must have regard to any reasonable provisions proposed by the other
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party(s) relating to the management of risks and hazards and either reach agreement about the content of the proposed JIMP or apply for arbitration.

10.3.5 Stakeholder engagement
The approvals process and project more broadly would involve liaising with a broad range of stakeholders, with a number of potential risks related to specific stakeholder types.

The complexity of identifying all traditional owners and other indigenous parties with interests in the lands that would be affected could be a major risk. A number of existing Native Title claims are likely to exist over the lands covered by the project. Additional indigenous groups with interests other than those who have made Native Title claims may appear and additional claims may be triggered as the project becomes more public. Therefore, Native Title negotiations would require careful planning early in the project to identify the best way to achieve successful land access outcomes and timely project approvals.

Other risks relate to engagement and communication with communities who would be affected by the influx of construction workers. Profiles of each community would need to be developed to identify the specific risks and issues each community may identify regarding the project.

Another stakeholder risk is from green group activism. Over recent times, green groups have been successful in disrupting, delaying and even preventing major energy and resource projects from proceeding through extensive social media campaigns and formal legal challenges. Legal challenges have been known to delay energy and resource projects for several years, and in some circumstances, have led to their ultimate refusal. Understanding and engaging with all key relevant stakeholders as early as possible in the project lifecycle is recommended.

10.3.6 Native title
Potential exists to impact upon lands, items or artefacts of indigenous significance. In addition, components of the project may impact Native Title and Cultural Heritage values. The project would require extensive engagement with indigenous groups, traditional owners and Native Title holders.

As part of the approvals process, the impact of the project on indigenous cultural heritage values would be undertaken. As part of the CHMP, an indigenous cultural heritage survey would be undertaken to identify significant Aboriginal objects and/or areas. The management of indigenous cultural heritage impacts would be detailed in either a Native Title agreement with traditional owners or a CHMP. The development of the Native Title agreements or CHMP would be negotiated with all relevant stakeholders’ representatives. As a minimum requirement, the impact assessment management and protection strategies would need to satisfy the statutory responsibilities and duty of care under the
Aboriginal Cultural Heritage Act 2003 (Qld) and the Aboriginal and Torres Strait Islander Cultural Heritage
Protection Act 1984 (Cth).

10.3.7 Environmental constraints and offsets
Project infrastructure would be spread across a large geographical area, potentially consisting of rural and previously undisturbed land. Clearing of vegetation would likely be required for the project.
Endangered and of concern regional ecosystems, endangered ecological communities, essential habitat and threatened plants are likely to be identified in some areas affected by the project. Therefore, the project does have potential to significantly impact on threatened species and ecosystems.

Offsetting of impacts to threatened species and ecological communities could be a costly and lengthy process requiring ongoing management throughout the life of the project and potentially beyond. Site selection, project planning and effective mitigation measures would minimise the risks associated with clearing of vegetation and associated offsetting requirements.
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10.4 Fatal Flaws – Environmental No-Go Zones
A high-level desktop review of the possible corridor options has been undertaken and there have been several key areas of constraint identified as follows:

Moranbah to Rolleston
• Norwich Park Nature Refuge (MNES and MSES);

• Peak Range National Park (MNES and MSES); and

• German Creek Nature Refuge (MSES).

Moranbah to Gladstone
• Goodedulla National Park (MNES and MSES);

• Junee National Park (MNES);

• Great Barrier Reef Marine Park (MNES);

• Rainbow Mountain Nature Refuge (MSES);

• Bouldercombe Gorge Conservation Park and Resources Reserve (MSES); and

• Fitzroy River Fish Habitat Area A (MSES).

10.5 Recent EIS Trends
Based on a desktop review of recent EIS’s prepared for major petroleum and gas projects in
Queensland, a summary of trends is provided in Table 36. The table below provides a breakdown of recent EIS’ prepared for similar projects, outlining the timing between EIS preparation, submission and approval, and any challenges identified.
Table 36 - Recent EIS Trends
(Source: GHD analysis)

Project / Proponent EIS Approvals Trend

Arrow Bowen Pipeline The Arrow Energy Pty Ltd ‘Arrow Bowen Pipeline Project’ involved the construction
Project and operation of a buried high pressure coal seam gas transmission pipeline from
Arrow Energy Pty Ltd approximately 90 km north of Moranbah, to approximately 22 km west of Gladstone
(total length of approximately 580 km).
Arrow prepared an EPBC Act Referral. The referral was submitted to the
Commonwealth in July 2012 and was assessed by preliminary documentation. The
referral was approved in October 2014 with conditions.
The project was assessed by preliminary documentation as the only MNES impacted
by the project was listed threatened species and communities.
An Initial Advice Statement (IAS) was prepared describing the project and application
for the preparation of a voluntary EIS and submitted to the Chief Executive of the
former Department of Energy, Resources and Mining (DERM) (now Department of
Resources). DERM assessed the application and notified Arrow in February 2011 of
approval.
Arrow prepared an EIS, which was submitted in February 2012 and approved by the
Queensland Government approval in March 2013.
The Moranbah to Gladstone option follows a similar route to the Arrow Bowen
Pipeline Project and is likely to intersect similar MNES and MSES.

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Project / Proponent EIS Approvals Trend
Queensland Curtis LNG The Queensland Gas Company ‘Queensland Curtis LNG Project’ involved the
Project expansion of current gas operations, construction of approximately 730 km network
Queensland Gas of gas pipelines, as well as an LNG plant and export facility.
Company Ltd and BG An EPBC Act Referral was prepared in June 2008, with the project being deemed a
International Ltd controlled action to be assessed by an EIS.
An IAS was prepared and submitted in June 2008. and a bilateral EIS was prepared
and submitted by October 2009. The project was then approved under a bilateral
agreement under the EPBC Act with conditions in October 2010.
The project was assessed under a bilateral EIS between Commonwealth and State
as a result of the following:
A portion of the pipeline was located between the mainland and Curtis Island, within
the boundary of the Great Barrier Reef World Heritage Area/ National Heritage
Place/Commonwealth marine area
Impacts to listed threatened ecological communities, listed threatened species and
migratory species
Australia Pacific LNG The project involved the development of gas fields in the Surat Basin, alongside the
Project construction and operation of a 450 km gas transmission pipeline and an LNG facility.
Origin Energy and An IAS was submitted, and the project was declared a significant project by the
Conoco-Phillips Queensland Coordinator-General, for which an EIS was required.
An EPBC Act Referral was submitted in July 2009 to the Commonwealth and was
determined a controlled action to be assessed by an EIS.
The project was assessed under a bilateral EIS between Commonwealth and State
as a result of the following:
A portion of the pipeline was located between the mainland and Curtis Island, within
the boundary of the Great Barrier Reef World Heritage Area/ National Heritage
Place/Commonwealth marine area
Impacts to listed threatened ecological communities, listed threatened species and
migratory species
The bilateral EIS was approved with conditions in February 2011.

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11. The most likely scenario
11.1 The need
There is a confirmed need for the securing of additional domestic gas supplies to supplement demand by the mid-2020s, and the Bowen Basin is the prime candidate.
Forecasts consistently predict a shortfall of gas supplies into the ECGM by the mid-2020s, starting with peak demand periods (winter) and extending to net annual shortfalls. This will drive upwards pressure on domestic gas prices and downward pressure on consumption, and thus economic activity in gas- intensive industries.

As a result of the analysis undertaken as part of this Study, there is a there for the development of additional gas production capacity to supplement the predicted shortfall of gas in the ECGM.

Whilst other prospective basins exist and could also be developed to provide gas into the ECGM, the
Bowen Basin is considered to be in prime position to supply this shortfall due to the level of existing infrastructure, existing production and extensive exploration and appraisal activity.

11.2 The supply scenario
It is economically achievable to unlock production from the Basin in volumes that wil provide meaningful additional gas supplies to market. No one scenario is a clear stand-out, and it is possible that a combination of both production from
Mahalo & Moranbah, with potential production from Blackwater, wil all contribute to unlocking the Basin.
Based on assessment of global energy demand, a netback price point of approximately AU$7.00 to
$7.50 / GJ at Wallumbilla has been calculated as part of this Study and is considered a reasonable middle-point for long term gas price for the ECGM, under balanced ECGM supply and demand conditions. Where supply is tight the ECGM prices will be elevated, with the GSOO predicating tight supply conditions to persist in the near to medium term. The economic viability of the Bowen Basin development has been based on this forecast ECGM gas price to provide a reasonable and realistic assessment of economic recovery.

Moranbah region
In the Moranbah region, a target rate of 170 TJ of gas per day was used. Modelling indicates that this target can be achieved with drilling and completing 319 wells over the ramp-up phase of development.
The well count could include existing wells once prior volume commitments have been fulfilled. To continue the plateau of 170 TJ of gas per day, additional wells are drilled as needed over the next 15 to
20 years. It is assumed that 50 TJ of gas per day will be sent to the domestic market in Townsville, and
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the remaining 125 TJ of gas per day will be transported south via a new pipeline. It is noted that the
Moranbah region has several areas available for development with higher production potential than represented with the high case type curve wells, however the production model has been kept purposefully conservative given the concept level of this Study.

Blackwater region
The Blackwater region has the least amount of CSG production and pilot data and is considered to have the highest risk of development. A target of 70 TJ/day was used. Modelling indicates that this target can be achieved with 205 wells drilled and completed starting in 2030. Additional wells are drilled and completed as needed to maintain the 70 TJ of gas per day target over the next 15 to 20 years. This delay allows for further delineation and data gathering in the Blackwater region and also provides time to establish a firm gas supply in the Moranbah and Mahalo regions to provide economic support for pipeline investment.

Mahalo region
In the Mahalo region, a target rate of 170 TJ of gas per day was used. Modelling indicates that this target can be achieved with drilling and completing 319 wells over the ramp-up phase of development.
To continue the plateau of 170 TJ of gas per day, additional wells are drilled as needed over the next
15 to 20 years. There are existing wells in the Mahalo region that could contribute to the total gas volume if prior volume commitments are fulfilled. The majority of gas volumes from this scenario are available for a pipeline going to southern markets via the ECGM. Similar to the Moranbah region scenario, the Mahalo region also has an area of development that the high-side type curve well could exceed. Mahalo & Blackwater scenario
• 175TJ/d to 250TJ/d
300 • 1,503 wells at peak
• 1,758PJ total production

Mahalo region scenario
250 • 180TJ/d plateau
• 16-year plateau
• 1,158 wells at peak
• 1,378 PJ total production
200
Gas production (TJ/d)

Moranbah region scenario
150 • 200TJ/d plateau
• 7-year plateau
• 1,059 wells at peak
• 1,326PJ total production
100

Blackwater region scenario
50
• 77TJ/d plateau
• 9-year plateau
• 632 wells at peak
• 390PJ total production
0
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2047
2048
2049
2050
2051

Figure 94 – Bowen Basin production profiles (mid-case) – all scenarios
(Source: NSAI Analysis)
*Note the graph represents modelled production which may differ from the target values.

The production scenarios modelled, based on the inputs and assumptions developed through existing knowledge of the Bowen Basin, publicly available data and stakeholder feedback, result in a number of
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pathways to economically produce natural gas from multiple regions in the Basin. The estimated achievable production volumes would contribute meaningful additional gas supply to the ECGM over a significant period.

The actual pathways to development may differ from these scenarios as technology improves, costs reduce, and further exploration and appraisal programs are prosecuted (particularly in the central region of the Bowen Basin between Moranbah and Blackwater). However, it is clear from the analysis conducted, that it is achievable to unlock production from the Basin in volumes that will provide meaningful additional gas supplies to the ECGM, consumers in North Queensland (particularly
Moranbah and Townsville) and potentially to the Gladstone LNG plants for export to trading partners in
Asia.

Notably, the analysis indicates that a larger play encompassing the Blackwater and Mahalo regions is needed to underwrite the development of the Basin. However, confidence in the reserves contained within the Blackwater region is limited due to low level of exploration that has occurred in this area.

Only supporting the smaller play of Moranbah to the north will not be enough to unlock the development of the whole Basin.

11.3 The role of coal mine methane
The reduction of emissions resulting from the capture and use of even a small portion of CMM far outweighs the cost of the additional new emissions from developing the basin’s CSG reserves.
Analysis undertaken as part of this Study indicates that the development of the Basin is expected to generate total emissions below 10Mt CO2-et over the life of the project. Using this estimate, we can see that the 12 Mt total emissions from the basin development (high case in central scenario) would require only a 4% reduction in overall UG coal mine fugitive emissions to achieve emissions ROI (4% of mid case >300Mt unabated UG coal mine emissions).

However, currently, mine operators have been averse to either investing in new gas processing infrastructure or owning and operating that infrastructure. Generally, mine operators are supportive of power generation and moving surplus energy as “electrons” as opposed to “molecules”. The current business landscape therefore suggests that policy drivers, improvements to the regulatory frameworks and cross sector collaboration from both private and public sector players will be critical to the development of the Bowen Basin gas resources.

Strategies for improved future utilisation, and therefore enablement of production and beneficiation of
CMM, are likely to be crafted around the following key focus areas:

• Overlapping tenements: New frame works for coal and CSG overlapping tenures must continue
to strive for maximum flexibility for resource authority holders, inclusive of the ability for relevant
parties to mutually agree on non-regulated arrangements that may fall outside legislative or default
requirements.

• Subsidisation: Power station and/or other gas beneficiation facilities will have a greater chance of
development through participation in emerging or potential future emissions subsidy schemes.

• Transmission Networks: Upgraded transmission system may encourage or enable larger power
plants and drive common use infrastructure (e.g. gathering and transmission pipelines to centralised
power plants).
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• Ventilation air methane: Mines could be incentivised to reduce VAM from established baseline
emissions through either emissions crediting or direct regulation.

• New Markets: New energy supply chains could be considered utilising either CSG and low-quality
gas associated with its production or incidental mine gas that has been treated to suitable quality,
although not necessarily pipeline specification gas.

• Infrastructure: Access to pipelines. One of the most significant barriers to utilising pre-drainage
coal mine gas is access to export pipelines, due to the typical lack of proximal export pipelines, and
the lack of required gas infrastructure to meet pipeline quality and pressure requirements. For these
reasons, it is typically not economic to capture coal mine gas and export to the commercial market.

• Gas Quality Requirements: CMM is typically highly variable in quality and flow, hence it can be a
challenge to deliver consistently economic gas to market at suitable quality.

• Emerging Technology: Developing and incorporating the use of emerging technology, such as
membrane separation of methane to improve concentration to useable levels, has the potential to
change the dynamics of the CMM utilisation in the Basin.

Traditionally, mine operators have been averse to either investing in new gas processing infrastructure or owning and operating that infrastructure. Generally, mine operators are supportive of power generation and moving surplus energy as “electrons” as opposed to “molecules”. The current business landscape therefore suggests that policy drivers, improvements to the regulatory frameworks and cross sector collaboration from both private and public sector players will be critical to the development of the Bowen Basin gas resources.

11.4 Infrastructure requirements
Delivery of infrastructure is the key enabler to the development of the basin.
However, the optimal solution may look substantial y different to what different stakeholders may expect.
The analysis undertaken as part of this Study indicates that the existing infrastructure in the north is sufficient to cater for the expected demand with little supporting infrastructure required, however, with limited existing infrastructure in the central region, large gas reserves not connected to the ECGM and a new pipeline connection is warranted.

As detailed in Section 7, there are a number of pathways to economically produce natural gas from multiple regions in the Basin that would ultimately underpin the construction of a gas pipeline connection to the ECGM.

Whilst a new gas pipeline isn’t the largest component of costs to develop the Bowen Basin, stakeholder reflections suggest that lack of infrastructure has been a key contributing factor to the delayed development of the Basin and will remain a key barrier into the future. Without the construction of a connecting pipeline to the ECGM, the Blackwater and Moranbah areas of the Basin are not likely to encourage investment and will not result in any material gas development occurring.

As outlined in Section 9, there are several likely options for pipeline routes that could connect the
Blackwater and Moranbah regions to the ECGM:

• Routes developed as part of this Study: Option 1, 2a, 2b, 3; and

• Routes that have been proposed by industry.
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A strategic merit test (SMT) was undertaken using the Government’s objectives for the Basin as part of this Study of:

• Improving surface economic viability of gas production and providing gas to market to deliver shared
benefits for the region and the State as a whole;

• Delivering efficient, multi-user gas transport infrastructure that will unlock gas resources;

• Enhanced commerciality of gas field developments in the Basin;

• Future-proofing gas supplies in Queensland; and

• Better management of incidental coal mine gas.

These findings are summarised as follows:

Figure 95 – Strategic Merit Test

Option 2B (refer Figure 96) supports a “whole of Basin” solution. The route enables a staged development of the pipeline, with the first stage a connection from the Mahalo region to Wallumbilla with a future extension to Moranbah. This staged approach has the benefit of supplying gas into the
ECGM with less upfront capital investment required, creating confidence for industry to invest, whilst providing time for the certifying of sufficient reserves in the Blackwater region before a connection to
Moranbah is constructed. Building a shorter pipeline initially, de-risks the pipeline investment, as it requires less upfront capital and is based on more well proven assets in the Mahalo region.

The first stage of the pipeline should be “oversized” such that it would not become a future bottleneck, however expansion is possible in the future using additional compression as well as initially oversizing the diameter. The first stage of the pipeline considering Mahalo only is likely to supply ~150 TJ/d. The second stage connecting Blackwater and Moranbah could contribute an additional 225 TJ/d, for a total of 375 TJ/d. Therefore sizing the initial pipeline for the future flow would require an approximately 22- inch pipeline instead of 16 inch for Mahalo only. The cost implication of this oversizing would be an additional 40% on the initial ~140km pipeline, or in the order of ~$64M. In terms of which option is best considering additional diameter vs compression, it is likely a lower investment risk to achieve additional capacity via compression rather than additional diameter. However, a more detailed assessment would be required to confirm this and would also depend on what options are offered by a pipeline proponent.

Option 2B also maximises the utility of methane from coal in the basin, from both mining operations and coal seam gas production as it provides the closest access to the majority of the prospective resource. However, further investigations into the constructability of the pipeline through mining operations and leases need to be undertaken.
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With any pipeline asset development, the configuration and routing of the Bowen Basin pipeline will be dependent on which party or parties take the commercial risk to invest into the asset. Government and industry have differing priorities and objectives driving investment decisions. There are always trade- offs that occur within this, and for fully commercial entities the focus is on maximising the return and reducing the risks for an investment over a defined time period. Whereas governments have a different investment perspective and consider the broader economic benefit over a longer period of time, including direct and indirect benefits that include potential of growth in energy intensive downstream industry and regional growth.

A key role for Government in subsequent phases of the development of the Basin is to clearly articulate to industry their objectives for the development of the Basin and measures to help mitigate risks in the construction of the pipeline.

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Figure 96 – Option 2B
(Source: GHD analysis)

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11.5 Timing considerations
Timing is critical for the development of the Basin, with many drivers influencing timelines
Getting the timing right for the development of the Basin will largely determine the resulting benefits to Queensland. If the Basin is development is too fast, it may suit industry but not be in the best interests of the State. If the development is too slow, other Basins such as the Beetaloo in the Northern
Territory may overtake and erode some of Queensland’s benefits.

There are many factors that need to be considered in timing implications, however an overriding factor is the forecast supply shortage in the ECGM. Given this, and the relative timing and potential volume of gas when compared to other prospective basins that could supply Eastern Australia, the Bowen
Basin has an import role to play in the medium-term energy security of Australia.

As described above, there is an anticipated need for additional gas into the ECGM by the mid-2020s, and the Bowen Basin is well positioned to provide a portion of the forecast shortfall. This implies that for a pipeline to be able to supply the market, the pipeline development would likely need to have FID within 24 months’ time. Additionally, there would need to have been sufficient development of reserves such that there is sufficient confidence that a pipeline investment is warranted from an economic benefit perspective.

The analysis undertaken as part of this Study indicates that the ‘best case’ timeline for a material increase in gas production in the Basin is approximately 5 years, comprising of the following elements:

Figure 97 – Basin development timeline (best case scenario)

However, historical basin development and industry feedback indicate that the most likely timeframe for development of the Basin is 7 years. Government has an important role to play in creating confidence for industry to invest and navigating the competing timeline priorities. Triggers are available that could accelerate the development of the Basin such as championing the development of the Basin through the establishment of governance frameworks to enable better collaboration between all tiers of
Government and industry and streamlining approval pathways.

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11.6 Identified challenges and opportunities
Developing the Bowen Basin will be complex and challenging but it has the opportunity to improve Queensland’s productivity, liveability and environmental sustainability
As with the development of any gas basin, many challenges and opportunities are present. However, the analysis undertaken as part of this Study is that there is a clear need for the securing of additional domestic gas supplies and Queensland is in the optimal position to leverage that opportunity with the development of the Bowen Basin. Key to maximising the benefits to Queensland will be converting the challenges to opportunities.

Figure 99 highlights the key challenges and opportunities for the development of the Basin as part of this Study. As noted, development of the Basin can improve the prosperity of Queensland, most notably the regions. The supply of affordable gas is expected to stimulate industrial development, particularly in the northern regions such as Townsville. This will have flow on effects through to jobs and economic growth for the next generation.

Figure 98 – Key challenges and opportunities

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However, the key barriers that need to be overcome include:

A need to change the current state of play
• There is a need to increase the appetite to invest for incumbent players

• Creating a diverse and strong consumer demand for the gas for industry to underwriting a large-
scale development of upstream CSG reserves.

The Bowen is technically challenging
• Evidence from existing production and exploration wells demonstrate that the Bowen Basin coals
have lower permeability, are located deeper and are higher pressure than the Surat Basin coals.

• May require the use of enhanced recovery techniques such as hydraulic fracturing, which brings
with it a range of technical, social and environmental risks.

• Wells also need to target specific coal seam measures to ensure productivity.

• Sufficient reserves need to be certified in a timely manner.

Navigating a complex stakeholder landscape
• The Bowen Basin coal measures are shallower on the Eastern and Western flanks – these measures
are the ones that are being extracted by Queensland’s large coal mining industry.

• Beyond 800m depth, it is difficult to economically extract CSG – meaning that CSG development in
the Bowen Basin will require strong cooperation between CSG proponents and coal miners.

• Overlapping Tenure on the same acreage is possible and presents immense opportunity to capture
coal mine fugitive gas emission, but also introduces complexity.

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12. The role of Government
As discussed in Section 11, further unlocking of the Bowen Basin is considered economically feasible and has a clear role to play in securing domestic gas supplies. However, Government, across all levels, will need to play a pivotal role in facilitating the development of the Basin if it is to maximise its benefits for all Queenslanders.

12.1 Planning and policy
12.1.1 Existing policy guiding the Bowen Basin
Policy, across all tiers of government (Commonwealth, State and Local), outlines the Government’s strategic direction and goals to enable effective use and the coordination of resources. Typically,
Government promotes a desired future state which is delivered through planning, infrastructure and development.

Key planning and policy documents with tangible outcomes relevant to the Bowen Basin include:

• Australian Government’s Gas-Fired Recovery;

• National Gas Infrastructure Plan: Interim Report;

• Our North, Our Future: 2021-26;

• ACCC’s Gas Inquiry 2017-2025 ­ 2021 Interim Report;

• Gas Pipeline Decision Regulation Impact Statement (DRIS);

• The North Bowen and Galilee Strategic Basin Plan;

• Queensland’s COVID-19 Economic Recovery Plan;

• Queensland Draft State Infrastructure Strategy;

• Queensland Climate Transition Strategy;

• Queensland Climate Action Plan;

• Queensland Renewable Energy Zones; and

• Regional Plans: Central Queensland and Mackay, Isaac and Whitsunday.

Appendix B provides details on key planning and policy initiatives relevant to the development of the
Bowen Bain.

Working across numerous Government portfolios, these documents must be taken into consideration in order to sustainably develop the Bowen Basin whilst maximising the benefits it brings.

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12.1.2 Previous and current policy interventions
The regulatory and policy environment remains dynamic, with continuous policy reform being driven by a variety of Government levels and different agencies within each level. Following significant policy measures implemented in the wake of the 2016 gas price spikes, as illustrated in Figure 99, the policy space has remained fluid with many different reform projects proposed and with significant focus from political leaders around gas market reforms, especially in the context of a gas-fired economic recovery following the initial COVID-19 pandemic lockdowns.

Figure 99 Timeline of Government policy initiatives in the ECGM
(Source: KPMG analysis)

Refer to Appendix F for details on recent policy reform measures impacting the ECGM.

Looking ahead, current policy reforms focused on increased price and volume transparency, improved liquidity, greater accessibility to transportation, domestic reservations and marketing behaviours should be considered.

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12.2 Understanding industry challenges
Understanding industry’s varied perspectives on the development of the Bowen Basin and the policies and strategies that underpin it, is critical to ensure that the Basin is developed in a way that maximises the benefits for all Queenslanders.
Table 37 identifies six key themes presenting challenges currently faced by proponents developing within the Basin. Although the challenges are impacting each proponent at varying levels, they all have the common feature of impacting investment decision within the Basin. These insights were informed through comprehensive industry engagement undertaken as part of this Study.
Table 37 Key industry challenges
Theme Key challenges

Access to market Lack of transmission infrastructure

High capital cost barriers to entry due to technical challenges
Access to finance for smaller operators as lenders are increasingly
Access to finance
moving away from divesting in fossil fuels
Commercial regulation risk
Access to finance for gas customers due to unconfirmed gas supplies
Demand in the North Single customer demand increasing commercial risk for gas suppliers
to invest
Land access arbitration
Thresholds for pipeline approvals for frontier basins
Approval processes
State/Federal Government approval complexity
Increasing cost of approval processes
Perception of primacy of coal in the Basin (over gas)
Negotiation complexity for overlapping tenure
Coal/gas stakeholder interface
Low level of formal collaboration forums
Perceptions of fugitive emission value

Confidence in reserves Low quality/quantity of data in central region

When considering the role of Government in facilitating the development of the Basin, numerous levers could be considered to help mitigate the above identified challenges and lessons learnt. Potential areas of consideration are discussed in Section 12.3 below.

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Leveraging lessons from the development of the Surat

In addition to the above, there are several key lessons learnt from the development of the Surat that
should be considered when facilitating the development of the Bowen Basin (in the context of the
scale differences expected):

• Broad stakeholder engagement – A process that ensures broad stakeholder engagement
from the industry and not just an individual project developer would enable greater level of
collaboration, insight and facilitation of issue resolution.

• Encourage high-level participation of regional labour – An opportunity exists to
proactively utilise local skilled labour in favour of fly-in fly-out resources. There is a potential
opportunity to utilise skilled labour from the coal mining industry in the coal seam gas, which
may assist in increasing the understanding of gas companies to work with the mining
companies more effectively in utilisation of coal mine gas.

• Increase focus on common use assets – The development of a process to encourage
project participants to increase collaboration around common use assets and resources in
both the development stage and operations stage of the gas projects. Whilst this takes more
coordination, it should go some way to supporting more cost-effective outcomes and
improving stakeholder perceptions of the industry as a whole.

• Sharing of lessons learnt – Forums where industry participants and key stakeholders could
share lessons learnt for the future benefit of the industry would provide a valuable approach
that could minimise challenges, improve safety, and create improved stakeholder
relationships.

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12.3 Potential pathways to facilitate development of the Bowen Basin
12.3.1 The need for a strategic approach
As discussed in Section 4, the global energy market is in transition – over the past twelve months governments around the world have pulled economic levers to force transition away from polluting fuels. The Queensland Government, with an economy traditionally centred on mining, has also set a vision of a zero net emissions future that supports jobs, industries, communities and our environment which includes the commitments of:

• Zero net emissions by 2050;

• An interim target of at least 30% below 2005 levels by 2030; and

• Powering Queensland with 50% renewable energy by 2030.

This rapid domestic and global change is expected to see Queensland’s traditional mining economic base narrow. This is already creating an atmosphere of uncertainty for industry to invest and for communities to prosper.

However, as discussed in Section 4, gas is an important transition fuel and demand for its gas is expected to be strong during this transition period and beyond. The development of the Bowen Basin is therefore expected to:

• Stabilise domestic gas prices;

• Provide certainty for industry to invest; Benefits of a partnering approach
• Secure future royalties in a low carbon economy;
and • Shared understanding on planning
• Deliver significant regional development
and economic development
opportunities for communities through investment priorities
into regional supply chains, regional service hubs • Alignment between all tiers of
and direct employment opportunities. government creating private sector
confidence in partnership and
The development of the Bowen Basin will impact and
investment provide benefits across all tiers of Government and many portfolios and this study has demonstrated the • A commitment to Basin criticality of pipeline infrastructure to the further development priorities and delivery unlocking of the Basin. horizons
However, the unlocking of the Basin cannot be • A focus on transparent, outcomes delivered by Government alone, industry must play focused decision-making, their part. investment and policy

To strengthen the region’s economy and instil • Opportunities to leverage aligned co- confidence for industry to invest, an agreed narrative investment by all three tries of on how Queensland will navigate the energy transition government and the private sector combined with a strategic approach to planning and • An agreed program of infrastructure investment across all tiers of Government and industry and investments will be required. This approach will ensure that the that the benefits of individual initiatives across portfolios and industry will be maximised.

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12.3.2 Focus areas
To facilitate the development of the Bowen Basin to the benefit of all Queenslanders, and in response to stakeholder challenges, three key focus areas for Government are starting to emerge:

Figure 100 – Focus areas
Source: KPMG analysis

These focus areas straddle numerous portfolios across all tiers of Government, with numerous initiatives already underway that will inform and influence the development of the Basin.

In addition to the policy actions and initiatives already underway, Table 38 outlines considerations for the role of Government in the development of the Bowen Basin. Adoption of these roles is expected to enable the Government to be an informed leader in the development of the Basin, future proof the regions, mitigate risks and create confidence for industry to invest in the Basin. However, in this rapid transition to a clean growth economy, it is critical that Government remains flexible to the changing needs of Queenslanders and industry.

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Table 38 – Potential roles for Government
Role for Enabling Supporting Zero Net Growing our
Description
Government Infrastructure Emissions Regions

Implementing policy actions from
policy’s and strategy’s such as the
Ensuring
Climate Action Plan, State alignment
Infrastructure Strategy, Regional with contextual
Infrastructure Plans, Queensland   
Resource Industry Development policy settings
Plan. Development of a Bowen
Basin Strategic Plan

Forums and frameworks to
promote collaboration, share
lessons learnt, enable timely
Governance
decisions, and help navigate state 
and Commonwealth Government
approval complexity

Facilitating industry to provide
Enabling access to market. This study has
Infrastructure confirmed the criticality of pipeline   
infrastructure.

Enabling the regions to invest in
Training and
skills of the next generation of workforce development
workers and provide opportunities  
along the supply chain.

Encourage a diverse mix of
Investment suppliers and customers to de-risk attraction and upstream and midstream promotion investment, creating confidence
  
for industry to invest.

Facilitate further investigation in
Investment the Basin and adoption of new risk mitigation technology to develop confidence  
in reserves and flow rates.

Enable Government to be an
active participant through
Open-source
independent data collection, data publication
improving the perception of the  
value of incidental coal mine
methane gas

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13. Next Steps
Embracing the development of the Bowen Basin is expected to help drive Queensland’s economic recovery whilst transitioning to a low carbon, clean growth economy

There is clear potential for the Bowen Basin to be developed as a new upstream source of gas that, if connected to the ECGM, would help contribute to closing the projected gas supply-demand gap in
Eastern Australia, forecasted to start in the mid-2020s. The development of the Bowen Basin will impact and provide benefits across all tiers of Government and many portfolios and this Study has demonstrated the criticality of pipeline infrastructure to the further unlocking of the Basin. However, the unlocking of the Basin cannot be delivered by Government alone, industry must play their part.

Therefore, it is recommended that the proposed next step for the Bowen Basin is to undertake a
Structured Market Engagement process with potential pipeline developers and other identified stakeholders.
Structured Market Engagement Process
To encourage industry participation and create confidence for industry to invest, both the
Commonwealth and Queensland Governments must be an informed leader in the development of the
Basin. Key to testing and refining the role of Government in unlocking the Bowen Basin is a structured
Market Engagement Process with likely market participants and other identified stakeholders.

Key elements of the process could include:

• Identification of market participants: Confirm market participants and key stakeholders to ensure
equal opportunity to all.

• Refining the potential role for government: Build upon the current understanding from the
market to clearly identify where Government may best play a role in the short to medium term
supporting industry.

• Testing potential government processes: Test and refine, through market feedback and
collaboration with DISER, a commercial model and process for potential Government support
(financial and/or in-kind) and roles and responsibilities to support collaborative feasibility
development.

• Identifying key thresholds: Identify, in consultation with market participants, key hold points and
thresholds that would need to be satisfied for investment decisions.

• Establishing indicative timetables and cost of development: Establish, in consultation with
market participants, a reasonable timetable, indicative cost for feasibility development and key
milestones therein.

This Study has identified several market participants and some of their drivers. The Structured Market
Engagement process will build upon this knowledge and would incorporate the more traditional next step of a feasibility study by building an understanding of the commerciality of the pipeline from the market’s perspective. This approach is anticipated to improve private sector confidence in the establishment of the Basin, resulting in in significant time savings through:

• A shared understanding on planning and economic development priorities;

• A commitment to Basin development priorities and delivery horizons;

• A focus on transparent, outcomes focused decision-making, investment and policy; and

• Identification of opportunities to leverage aligned co-investment by all three tries of government
and the private sector.
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Appendix A: Glossary
Acronyms/initialisms
ACCC Australian competition and consumer commission

ACQ annual contract quantity

C&I commercial and industrial

CFC chlorofluorocarbon

CTP capacity trading platform

CSG coal seam gas

DTS Declared transmission system

E&P exploration and production [companies]

FEED front end engineering and design

FID final investment decision

GHG greenhouse gas

GEMS Greenhouse Energy Minimum Standards

GPG gas powered generation/generator

GSA gas supply agreement

GSOO AEMO’s Gas Statement of Opportunities

GSSA Gas Storage Service Agreement

GTA gas transportation agreement

GWP global warming potential

MACC marginal abatement cost curve

MDQ maximum daily quantity

MOU memorandum of understanding

NEM National Electricity Market

NGL National Gas Law

NGR National Gas Rules

RTO regenerative thermal oxidation

SPAs sale and purchase agreements

STTM short-term trading market

VAM ventilation air methane

WAP weighted average price

WORM Western Outer Ring Main

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SIS Surface-in Seam

UGS underground gas storage

2C Contingent resources

2P proved and probable reserves

Units
PJ petajoules (1 PJ = 1 thousand TJ = 1 million GJ)

TJ terajoule (1 TJ = 1 thousand GJ)

GJ gigajoule (1 GJ = 1 thousand MJ)

Btu British Thermal Units

Mt million tonnes

MW megawatts

MTPA million tonnes per annum

CO2-e carbon dioxide equivalent

Queensland licenses/terminology
ATP authority to prospect

PCA potential commercial area

PL petroleum lease

PPL petroleum pipeline licence

Industry bodies
AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

APPEA Australian Petroleum Production and Exploration Association

GMRG Gas Market Reform Group

Queensland gas projects/fields/wells
APLNG Australia Pacific LNG

GLNG Gladstone LNG

MGP Moranbah Gas Project

QGC QGC LNG

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Queensland gas pipelines
CGP Carpentaria Gas Pipeline (Mt Isa to Ballera)

DDP Darling Downs Pipeline

EGP Eastern Gas Pipeline

GMP Galilee Moranbah Pipeline

GTP Mainland Gas Transmission Pipeline (Fairview to Curtis Island/Gladstone)

NQGP North Queensland Gas Pipeline (Moranbah to Townsville)

NGP Northern Gas Pipeline (Tennant Creek NT to Mt Isa QLD)

QGP Queensland Gas Pipeline (Wallumbilla to Gladstone and Rockhampton)

RBP Roma to Brisbane Pipeline

SWQP South West Queensland Pipeline

WGP Wallumbilla Gladstone Pipeline

Gas Hubs
WSH Wallumbilla Supply Hub

MSH Moranbah Supply Hub

Definitions

Term Definition

2C contingent resources Best estimate of contingent resources – equivalent to 2P
reserves, except for one or more contingencies or uncertainties
currently impacting the likelihood of development. Can move to
2P classification once the contingencies are resolved.
2P reserves The sum of proved and probable estimates of gas reserves. The
best estimate of commercially recoverable reserves, often used
as the basis for reports to share markets, gas contracts, and
project economic justification
Anticipated supply Considers gas supply from undeveloped reserves or contingent
resources that producers forecast to be available as part of their
best production estimates provided to AEMO
basin A geological formation that may contain coal, gas, and oil.
coal seam gas (CSG) Gas found in coal seams that cannot be economically produced
using conventional oil and gas industry techniques. Also referred
to in other industry sources as coal seam methane (CSM) or coal
bed methane (CBM).
Committed supply Considers developments or projects which have successfully
passed a financial investment decision (FID), and are progressing
through the engineering, procurement, and construction (EPC)
phase, but are not currently operational.
consumption The measure of gas usage over time, typically one year. When
forecasting, the consumption represents the total demand for
energy over the given period.

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Term Definition
contingent resources Gas resources that are known but currently considered
uncommercial based on one or more uncertainties (contingencies)
such as commercial viability, quantities of gas, technical issues, or
environmental approvals.
conventional gas Gas that is produced using conventional or traditional oil and gas
industry practices.
demand Capacity or gas flow on an hourly or daily basis, or the electrical
power requirement met by generating units.
developed reserves Gas supply from existing wells.
domestic gas Gas that is used within Australia for residences, businesses,
power generators, etc. This excludes gas demand for LNG
exports.
gas-powered generation (GPG) The generation of electricity using gas as a fuel for turbines,
boilers, or engines.
global warming potential (GWP) A measure of how much energy the emissions of 1 ton of a gas
will absorb over 100 years, relative to the emissions of 1 ton of
CO2. The larger the GWP, the more that a given gas warms the
Earth compared to CO2. GWPs provide a common unit of
measure, which allows analysts to add up emissions estimates of
different gases and allows policymakers to compare emissions
reduction opportunities across sectors and gases.
probable reserves Estimated quantities of gas that have a reasonable probability of
being produced under existing economic and operating
conditions. Proved-plus-probable reserves added together make
up 2P reserves
production In the context of defining gas reserves, gas that has already been
recovered and produced
prospective resources Gas volumes estimated to be recoverable from a prospective
reservoir that has not yet been drilled. These estimates are
therefore based on less direct evidence than other categories.
proved and probable See 2P reserves
reserves Reserves are quantities of gas which are anticipated to be
commercially recovered from known accumulations.
reservoir In geology, a naturally occurring storage area that traps and holds
oil and/or gas. Iona Underground Storage (UGS) is also referred to
as a reservoir for gas storage.
resources More uncertain and less commercially viable than reserves. See
contingent resources and prospective resources.
undeveloped reserves Gas supply from wells yet to be drilled.

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Appendix B: Planning and Policy
Australian Government’s Gas-Fired Recovery 14
To assist in Australia’s economic recovery from the COVID-19 pandemic, on 15 September 2020 the
Australian Government announced the Gas-Fired Recovery as part of the JobMaker plan.
The 2021-22 Federal Budget allocates $58.6m over four years to support Australia’s gas-fired recovery. 15,16 Of that amount, $38.7m is allocated to support critical gas infrastructure projects to help alleviate the potential gas shortfall on Australia's east coast. $5m has been allocated for this Concept
Study. 17 Table 39 presents the measures outlined in both the September media release and 2021-22
Budget.
Table 39: Gas-fired recovery measures relevant to Queensland
(Source: KPMG Analysis)

Key Area Initiative Cost

Unlocking gas New gas supply targets with states/territories and enforcement of gas
supply license “use-it or lose-it” requirements
Strategic Basin Plans to unlock five key gas basins starting with the $28.3m for plans
Beetaloo (NT) and North Bowen (QLD) basins ($5m for Bowen)
Funding for gas industry field appraisal trials in the North Bowen and $15.7m
Galilee Basins
New agreements with the three east coast LNG exporters to avoid any
gas supply shortfall – Heads of Agreement 2020
Support for CSIRO’s Gas Industry Social & Environmental Research $13.7m
Alliance
Exploring options for a prospective gas reservation scheme.
Delivering an Identification of priority pipelines and critical infrastructure as part of an $5.6 for the final
efficient inaugural National Gas Infrastructure Plan (NGIP) plan
pipeline and
transport Future Gas Infrastructure Investment Framework to support $3.5m
market consideration of critical gas projects identified by future NGIPs
Reform of pipeline infrastructure regulation
Development of a dynamic secondary pipeline capacity market
Empowering Establish an Australian Gas Hub at Wallumbilla (QLD) $6.2m
gas customers
Voluntary industry-led code of conduct
Review the calculation of the LNG netback price, with the ACCC
Use the NGIP to develop customer hubs or a book-build program for a
more transparent and competitive process
Source: (Morrison, 2020), (Taylor, 2021) & (Pitt, 2011)

Unlocking the North Bowen and Galilee: The Strategic Basin Plan 18
As part of the Gas-Fired Recovery, the Australian Government identified the North Bowen and Galilee
Basins as one of five strategic basin areas. To further operationalise the programs and priorities canvassed in the Gas-Fired Recovery, the Australian Government has released a Strategic Basin Plan

14 (Morrison, 2020)
15 (Australian Government, 2021)
16 (Australian Government, 2021)
17 (Taylor, 2021)
18 (Australian Government, 2021)
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for the North Bowen and Galilee Basins. This plan allocates $20.7m of direct investment, as well as leveraging over $400m in research and infrastructure upgrades.
The Plan outlines a vision for the basins: “Creating jobs and driving economic growth by unlocking the full potential of the North Bowen and Galilee basins”. It identifies immediate actions that the Australian
Government will progress to contribute to realising this vision, as well as next steps which will be informed by data gathered by the immediate actions. One of these immediate initiatives is to model a possible future gas pipeline, which is explored in this Concept Study. These initiatives are detailed in
Table 40.
Table 40: North Bowen and Galilee Strategic Basin Plan initiatives

Initiative Total Cost Timing

Immediate actions

Gas well trials to crack complex geological challenges and establish cost- $15.7m 2021-22
effective gas flows across four sites within the basins.
Pipeline preparations to establish an optimal route and capacity for a $5m (co- 2021-23
possible future gas pipeline and understand the regional benefits of commitment with
this work. QLD Government)
Funding for Geoscience Australia and the CSIRO to establish $14m 2021-24
environmental evidence to support regulatory processes across strategic
basins, including the North Bowen and Galilee.
Funding to continue the CSIRO’s GISERA research in these basins and $13.7m 2021-24
across Australia.
Road upgrades throughout the region which will support supply chains, $370m 2021-
trade and project construction across multiple sectors. onwards
Next Steps
Together with the Queensland Government, consideration of the 2023-
outcomes from gas well trials and pipeline preparations to support the onwards
development of the National Gas Infrastructure Plan.
Prioritisation of regulatory applications by Commonwealth regulators to 2022-
reduce costs that may otherwise cause lengthy delays. onwards
Strengthened training and education opportunities to ensure workers in 2024-
the region have the skills to support gas projects. onwards
Working with governments to realise opportunities for gas to help unlock 2024-
downstream and manufacturing opportunities in central and northern onwards
Queensland.
Source: (Australian Government, 2021)

National Gas Infrastructure Plan: Interim Report 19
In May 2021, the Department of Industry, Science, Energy and Resources published an interim report ahead of the full National Gas Infrastructure Plan. It forecasts medium-term gas supply shortfalls and lays out a blueprint up until 2027 that identifies the highest priority infrastructure investments needed to address the threat of shortfall and ensure continued reliable and affordable gas supply.
The Interim Report identifies four critical infrastructure projects to address the forecast gas shortfall:

• two gas storage projects at Golden Beach and Iona in Victoria

• expansion of the South West Victorian pipeline

19 (Department of Industry, Science, Energy & Resources, 2021)
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• a new import terminal (the Port Kembla, NSW project is at the most advanced planning stage).

The Interim Report assumes that 33 PJ of new supply can be made available to domestic customers if required by LNG producers. It however does not include ‘discovery fields’ including the Beetaloo and
North Bowen basins at this stage.
When released, the full Plan will present a blueprint for the development of the east coast gas market out to 2040, which encompasses the planned actions to unlock the five strategic basins identified in the Gas-Fired Recovery (including the North Bowen Basin). The Plan will effectively form an analogue to AEMO's Integrated System Plan, for the gas sector instead of the electricity sector.

Our North, Our Future: 2021-26 20,21
Delivered as part of the 20-year framework in the 2015 Our North, Our Future: White Paper on
Developing Northern Australia, the next five-year plan for Northern Australia was announced in May
2021 and will be released later in 2021. It aims to bolster and support the Gas-Fired Recovery.

The 2021-22 Federal Budget allocates $189.6m over five years, which includes funding for a $111.9m
Northern Australia Development Program that provides co-investment funding and advice to businesses. This may be relevant in the commercial development of the North Bowen Basin.

ACCC’s Gas Inquiry 2017-2025 ­ 2021 Interim Report 22
The 2021 Interim Report confirmed that forecast supply is expected to meet domestic and export demand in 2021 for the east coast gas market. However, it forecasts a supply shortfall from 2P resources from 2026, or as early as in 2024 for the southern states without the development of speculative resources or an LNG regasification terminal.

To address medium-term shortfalls, pipeline transportation or an LNG import terminal are warranted.
To address long-term shortfalls (2028 onwards), Narrabri, the northern Bowen Basin and the Galilee
Basin are all promising options to bring online.
The Report maintains that pipeline operators are still engaging in monopoly pricing that consumers ultimately pay for. The ACCC first made this assertion in April 2016 in its Inquiry Into The East Coast
Gas Market.
It also notes that as of 30 June 2020, Queensland’s Surat and Bowen basins held 30,520 PJ of 2P reserves, and that the three Queensland LNG producers either directly or indirectly control over 80% of Queensland’s 2P (proven and probable) reserves and over 50% of 2C (contingent) resources.

Gas Pipeline Decision Regulation Impact Statement (DRIS) 23,24
On 3 May 2021, the Federal Energy Ministers 25 announced reforms to improve the gas pipeline regulatory framework and address monopoly pricing by pipeline operators.
The recommended option was Option 3B which provides for the regulation of all pipelines, with two tiers: a stronger form of regulation and a lighter form for new (greenfield) pipelines which can obtain an exemption. This option expands the status quo/current scope of pipeline regulation in which only some pipelines are regulated (‘scheme’). It also requires all pipelines to now provide third party access, and

20 (Department of Industry, Science, Energy & Resources, 2021)
21 (Australian Government, 2021)
22 (Australian Competition & Consumer Commission, 2021)
23 (Energy Ministers, 2021)
24 (Taylor, 2021)
25 Minister for Energy and Emissions Reduction, Minister for Resources and Water, Minister for Industry, Science and Technology and Assistant Minister for Industry Development
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publish more information/data, and prohibits service providers from increasing the charges payable by existing shippers to cross-subsidise the development of new capacity.
The reforms are expected to:

• lower transportation costs

• improve access to pipelines

• lower search and transaction costs

• provide a range of other significant cost savings investment and efficiency benefits

• materially reduce the risks associated with the regulatory framework

• facilitate more effective competition in gas transportation and in upstream and downstream
markets.

Net economy-wide benefits of the reforms are expected to be between $235m and $1.18b.
The reforms are now being developed into a draft legislative amendment package, with consultation and agreement of the Energy National Cabinet Reform Committee to follow before an amendment to the National Gas Law and National Gas Rules. If passed into legislation, these reforms could influence the investment decisions of private gas pipeline developers in the Bowen Basin.

Queensland’s COVID-19 Economic Recovery Plan 26
Queensland’s COVID-19 Economic Recovery Plan encompasses a suite of initiatives that forms the
Queensland Government’s response to the COVID-19 pandemic and resulting economic impacts.
The Plan presents a vision which includes protecting the health of every Queenslander, creating jobs, and working together to create the conditions for future success. It identifies six key focus areas to deliver this vision:
• Safeguarding our Health
• Backing small business
• Making it for Queensland
• Building Queensland
• Growing our regions
• Investing in skills.
The Plan also allocates $5m to complement Commonwealth funding for the Bowen Basin pipeline concept/pre-feasibility study. Specifically, this funding features in the Central Queensland and
Mackay-Whitsunday Regional Economic Recovery Plans. 27,28
This Bowen Basin Gas Pipeline concept study forms part of Queensland’s COVID-19 Economic
Recovery Plan and aims to contribute to the recoveries of both the regions and the state. It will explore options to unlock the Bowen Basin’s gas supply and whether they can contribute to the
Plan’s vision of creating the conditions for future success, in terms of Queensland’s energy and economic future.

26 (Palaszczuk & Dick, 2020)
27 (Queensland Government, 2020)
28 (Queensland Government, 2020)
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Queensland Draft State Infrastructure Strategy 29
The Queensland Government’s State Infrastructure Strategy forms the overarching framework for infrastructure development in Queensland; it sets state-wide priorities and planning direction, which will then inform the regional infrastructure plans that are currently being developed for Queensland’s seven regions. Over the next twenty years, the Strategy aims to deliver on its vision:
“We will drive collaborative state infrastructure planning to boost productivity, grow our
economy and create jobs. Infrastructure planning and delivery will leverage opportunities to
improve the liveability of our communities and capitalise on innovation to build a strong,
sustainable and resilient Queensland.”
The objectives that the plan targets in order to realise this vision include:

• Encourage jobs, growth, and productivity
• Develop regions, places and precincts
• Enhance sustainability and resilience
• Adopt smarter approaches.
This study explores options to unlock gas supply in the Bowen Basin in such a way that would generate economic benefits and jobs for Queensland. As such, it aligns with the first objective of the
Strategy (Encourage jobs, growth, and productivity).

Queensland Climate Transition Strategy 30
In the Queensland Climate Transition Strategy, the Queensland Government outlines a state target of zero net emissions by 2050, with an interim target of 30% reduction in emissions on 2005 levels by
2030. The Strategy outlines the actions that the Queensland Government will progress in order for
Queensland to realise these targets.
One key focus of the Bowen Basin Gas Pipeline concept study is to explore ways to better manage incidental coal mine gas, in order to both increase the overall productivity of coal mining from an energy source perspective as well as to decrease fugitive emissions from an environmental perspective. In decreasing fugitive emissions, a solution in the Bowen Basin could contribute to achieving Queensland’s emissions reduction targets.

Queensland Climate Action Plan 31
The Queensland Climate Action Plan represents a collection of plans, actions and projects (planned and in progress) that contribute to Queensland’s renewable energy and emissions reduction targets, and the transition to a more sustainable economy.
Among the 370 project case studies referenced, the Bowen Basin Gas Pipeline concept study is listed as an action being undertaken to drive climate action. As identified, the concept study explores options that could contribute to achieving Queensland’s emissions reduction target.

Queensland Renewable Energy Zones 32
In May 2021, the Queensland Government declared three renewable energy zones in Queensland
(QREZs) that are particularly to being conducive to renewable resource development, as identified by
AEMO (see Figure 101). The Queensland Government has allocated $145 million to undertake strategic [electricity] network investments, streamline the development of new renewable energy projects and increase the supply of renewable energy. The majority of this development will be solar and wind farms, and electricity transmission network solutions.
It is appropriate to consider the Bowen Basin Gas Pipeline concept in the context of the QREZs, especially the Central QREZ, because both aim to address Queensland’s energy future. Specifically,

29 (Department of State Development, Infrastructure, Local Government and Planning, 2021)
30 (Department of Environment & Heritage Protection, 2017)
31 (Department of Environment and Science, 2021)
32 (Department of Energy & Public Works, 2021)
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electricity generation and transmission play a downstream role for any gas resources that are intended for electricity generation. Developing the Bowen Basin’s gas reserves to provide more electricity into the NEM will require considering the downstream infrastructure needed and the role that QREZs can play in enabling this.

Figure 101 Map of Queensland REZs
Source: (Department of Energy & Public Works, 2021)

Queensland Resources Industry Development Plan (QRIDP) 33
The Queensland Government is currently developing a Queensland Resources Industry Development
Plan (QRIDP) with a draft plan scheduled for release in late 2021 before the final plan’s publication in
2022. It aims to outline a long-term strategic vision for Queensland’s resources industry as well as a roadmap to realise this vision. Key focus areas will include:
• removing barriers to resources industry growth
• helping regional communities recover from the impacts of COVID-19
• responsibly unlocking Queensland’s precious resources.

Central Queensland Regional Plan 34
Released in 2013, the Central Queensland Regional Plan covers the following LGAs:

• Banana Shire Council
• Central Highlands Regional Council
• Gladstone Regional Council
• Livingstone Shire Council
• Rockhampton Regional Council
• Woorabinda Aboriginal Shire Council.

33 (Queensland Government, 2021)
34 (Department of State Development, Infrastructure & Planning, 2013)
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The Plan aims to provide “strategic direction and policies to deliver regional outcomes which align with the state’s interests in planning and development”. The two regional outcomes identified in the Plan are:

• Agriculture and resources industries within the Central Queensland region continue to grow with
certainty and investor confidence.
• The growth potential of towns within the Central Queensland region is enabled through the
establishment of Priority Living Areas. Compatible resource activities within these areas which are
in the communities’ interest can be supported by local governments.
While the Plan does not reference gas supply or development specifically, it does highlight the regional issue of land use competition between the agricultural and resources sectors. It also places value on promoting the liveability of communities, economic growth and environmental sustainability.
This Concept Study explores opportunities for the development of Bowen Basin gas reserves to contribute to the region’s economic growth and also to environmental sustainability through fugitive emissions reduction.

Mackay, Isaac and Whitsunday Regional Plan 35
Released in 2012, the Mackay, Isaac and Whitsunday Regional Plan covers the following LGAs:

• Mackay Regional Council
• Isaac Regional Council
• Whitsunday Regional Council.
The Plan sets a regional vision for 2031:

“The Mackay, Isaac and Whitsunday region is a vibrant, progressive region where the values of
the community and industry are respected and in balance with the natural environment. The
region’s natural assets and abundant resources will be responsibly managed for the benefit of
residents, visitors and future generations. It achieves its potential with a range of industries,
employment and learning opportunities for everyone. The region has a resilient and inclusive
community that respects and offers diversity and choice, and where residents and visitors enjoy
a healthy, active and safe lifestyle.”
The Plan also provides policy direction in order for the regional vision to be realised, organised into ten desired regional outcomes. Three of these outcomes are directly relevant to this Bowen Basin Concept
Study:

• Outcome 1: The region grows and changes in a sustainable manner generating prosperity,
maintaining and enhancing quality of life, minimising the use of resources, providing high levels of
environmental protection, reducing greenhouse gas emissions, and increasing resilience to natural
hazards and the anticipated effects of climate change.

• Outcome 6: A thriving regional economy that is sustainable, resilient and robust, and advances the
prosperity and liveability of communities across the region.

o Policy 6.5.3: Identify and support new sectors that have the potential for future growth
associated with the resource sector such as mine rehabilitation and carbon dioxide emissions
capture
o Policy 6.5.6: Ensure sufficient supply of minerals, gas and extractive resources are available for
future use, and their extraction, processing, transport and downstream value-adding contribute
to the local economy

35 (Department of Local Government & Planning, 2012)
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• Outcome 9: The region’s communities have access to well-planned, coordinated, accessible,
sustainable and reliable infrastructure.

o Policy 9.3.4: The use of gas distribution networks are optimised and expanded, and, where
viable, the use of gas as an additional energy source is encouraged for new developments.
This Concept Study assesses opportunities to reduce emissions through productive use of incidental coal mine gas, which aligns with Outcome 1 and Policy 6.5.3. This Concept Study also explores options to increase gas supply through the development of gas reserves in the Bowen Basin, and associate infrastructure – this would advance the achievement of Policy 6.5.6 and Policy 9.3.4. Finally, this
Concept Study explores the opportunity for any investment or development of the Bowen Basin to contribute to the Region’s economic recovery and growth, which would broadly contribute towards
Outcome 6.

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Appendix C: Approval Options
The following sections detail a breakdown on the potential approval requirements for the development of the Basin.

Environmental Protection & Biodiversity Conservation Act 1999
The Environment Protection and Biodiversity Conservation Act 1999 (Cwth) (EPBC Act) is the
Commonwealth Government’s central environmental legislation.

The EPBC Act provides protection for Matters of National Environmental Significance (MNES) against actions that have or are likely to significantly impact any MNES. An action that has or is likely to significantly impact an MNES is known as a ‘controlled action’. Under the EPBC Act, to undertake a controlled action without approval from the Minister is prohibited.
There are currently nine MNES protected under the EPBC Act, including:

1) Listed threatened species and ecological communities

1) List migratory species

2) Wetlands of international importance

3) The Commonwealth marine environment

4) World Heritage properties

5) National Heritage places

6) Nuclear actions

7) Great Barrier Reef Marine Park

8) Protection of water resources from coal seam gas development and large coal mining development
(otherwise referred to as the water resource trigger).

The Department of Agriculture, Water and Environment (DAWE) recommends that a project carry out a self-assessment as the first step in determining if referral and assessment under the EPBC Act is required. The purpose of the self-assessment is to determine if the project will or is likely to significantly impact an MNES.
Should the self-assessment identify the potential for a significant impact to any MNES, referral to the
Commonwealth is required. Alternatively, if the self-assessment identifies that the action will not or is unlikely to have a significant impact on any MNES, a referral to the Commonwealth is not required by law.

It is highly likely that a gas development in the Bowen Basin would trigger a controlled action under the
EPBC Act, at the very least for listed threatened species and ecological communities, and for protection of water resources from coal seam gas development.

Declaration as a Coordinated Project under the State Development and Public Works
Organisation Act 1971
A proponent of a project with one or more of the following characteristics may apply to have it declared a 'coordinated project' with the State of Queensland:

• Complex approval requirements, involving local, state and federal governments;

• Significant environmental effects;
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• Strategic significance to the locality, region or state, including for the infrastructure, economic and
social benefits, capital investment or employment opportunities it may provide significant
infrastructure requirements; or

• Significant infrastructure requirements.

The Queensland Coordinator-General chooses the weight attributed to each of the above factors in making the decision to declare a project a co-ordinated project. The Coordinator-General is not bound to declare a project a coordinated project because it satisfies one or more of these characteristics.
In making the declaration decision, the Coordinator-General must consider:

• Detailed information about the project given by the proponent in an Initial Advice Statement;

• Relevant planning schemes or policy frameworks of a local government, the State or the
Commonwealth;

• Relevant State policies and Government priorities;

• A pre-feasibility assessment of the project, including how it satisfies an identified need or demand;

• The capacity of the proponent to undertake and complete the environmental impact statement (EIS)
or impact assessment report (IAR) for the project; and

• Any other matter considered relevant.

There are two types of coordinated project declaration:

• Requiring an EIS

• Requiring an IAR

Details of the usual scope of an EIS and an IAR are outlined below. Generally, the IAR is a more straightforward assessment aimed at projects whose potential impacts are well understood and predictable. The declaration of a ‘coordinated project’ in accordance with the SDPWO Act, means that the procedures to secure the required project approvals would be simplified and ‘fast-tracked’ as a result of the ‘whole of government’ approach that attends such a declaration.

Scope of an EIS
The EIS is prepared in accordance with the terms of reference for the EIS. The EIS provides a comprehensive description of:

• The state of environment in the area of the project

• All potential environmental impacts of the project, including spatial and temporal considerations, as
well as direct, indirect, reversible, irreversible, interactive, synergistic and cumulative effects
resulting from the construction, commissioning, operation and decommissioning phases of the
project.

• Proponent proposals to avoid, minimise, mitigate and/or offset those potential impacts.

Scope of an IAR
An IAR process may be used if the Coordinator-General is satisfied that the environmental effects of the project do not (having regard to their scale and extent) require assessment through the EIS process.
It may be used for well-defined, low-medium risk projects where the likely impacts are highly predictable and the proponent's well-defined proposals to avoid, minimise, mitigate and/or offset those impacts are accepted best-practice in that industry.
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The IAR:

• Has no formal terms of reference; and

• Is focused mostly on the:

o Locations that may be subject to adverse impacts if not appropriately managed
o Potential impacts that are either uncertain, or proposed mitigation measures that depart from
accepted management practices or standard conditions for that industry.

Advisory Agencies
The Office of the Coordinator-General manages the State Government's evaluation of the project.
A wide range of Government departments (known as 'advisory agencies') are responsible for reviewing the draft EIS or IAR and will involve the likes of Department of Resources, Department of Environment and Science, Department of Agriculture and Fisheries, and Department of Transport and Main Roads.

Other Approval Processes Suspended
The coordinated project process replaces the information and referral stages of a related assessment under both the Queensland Planning Act 2016 and an environmental authority under the Environmental
Protection Act 1994.

The decision stage under both of these Acts commences when the Coordinator-General's evaluation report on the EIS or IAR is provided to the relevant assessment.

Option to Apply for Declaration as a Prescribed Project
A proponent of a Coordinated Project may also apply to have the project declared a “prescribed project” pursuant to section 76e of the SDPWO Act (Qld). The application to have a project declared a prescribed project is made through the office of the Co-ordinator General. The Office of the Co-ordinator General assesses the merit of the application and makes a recommendation to the minister. The formal declaration is ultimately made by the Minister by Gazette notice.

The declaration as a “Prescribed Project” provides a number of benefits including enabling the
Coordinator General, if necessary, to intervene in state and local government approval processes to assist and ensure timely decision-making for the prescribed project.

The Office of the Coordinator-General can overcome unreasonable delays in obtaining project approvals by:

• Acting as a point of contact for the proponent within Government to streamline Government
communications;

• Coordinating local and State Government agencies regarding statutory approvals required for the
project; and

• Facilitating discussions and information exchanges between the proponent and other stakeholders
(e.g. local authorities and State Government agencies).

A prescribed project declaration is most effective when used to obtain the final approvals after Tier 1 approvals have already been provided by the Coordinator-General or another authority.

The types of projects that may be declared prescribed projects include:

• Works a 'local body', the Coordinator-General, or other person is directed to undertake under the
SDPWO Act

• A project in a state development area.
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• An infrastructure facility (as defined in the SDPWO Act – see below).

• A project declared a 'coordinated project'.

• Another project the minister considers is economically or socially significant to Queensland or the
region in which the project is to be undertaken or affects an environmental interest of Queensland
or a region.

SDPWO Act definition of infrastructure facility includes any of the following: a road, railway, bridge or other transport facility a jetty or port an airport, landing strip or spaceport an electricity generation, transmission or distribution facility a storage, distribution or gathering or other transmission facility for:
i) oil or gas; or

ii) derivatives of oil or gas a storage or transportation facility for coal, any other mineral or any mineral concentrate a dam, water storage facility, pipeline, channel or other water management, distribution or reticulation
facility a cable, antenna, tower or other communication facility infrastructure for health or educational services.

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Appendix D: CMM treatment for utilisation
Gas dehydration
Gas dehydration is one of the main functions of any gas processing hubs. It is important to remove water from the gas due to the following:

• Under certain conditions gas can combine with liquid or free water to form solid hydrates that can
plug valves fittings or scale pipelines, leading to unsafe situations or higher-pressure drops in
transmission systems

• Water vapour can condense in pipelines, especially at higher pressures, causing slug flow and
possible erosion and corrosion

• Water vapour increases hydraulic loading and decreases the heating value of the gas

• Downstream customers’ feed gas specification(s) typically require a feed gas of specific heating
value and zero free water, although water saturated gas can be tolerated

• Water vapour is most commonly removed via liquid desiccant (i.e. physical solvent) processes such
as glycol dehydration. Glycol dehydration is most prevalent in the Queensland coal seam gas
industry, although other technologies are commercially available.

Mine capture gas can contain appreciable amounts of acid gas impurities, such as H2S, COS and CO2.
The presence of these “sour” impurities in the presence of water saturated gas can lead to higher corrosion potential in mechanical equipment, displaces hydraulic capacity in process systems and also reduces heating value of the gas. Generally, treatment processes are adsorption of absorption based.
Adsorption refers to physical processes wherein impurities are concentrated on the surface of a solids.
These types of processes are usually for trim or residual impurity treatment only. Bulk or large-scale acid gas removal is accomplished through chemical absorption processes and may be once through wash systems or more complex, multistep processes with regeneration steps. Most gas processing plants utilise a process with selective absorption of contaminants into a liquid solvent (such as ethanolamine), which is passed counter-current to the gas in an absorber column. Other technology options, for example those based on physical rather than chemical absorbents, (Selexol® or Rectisol®), will not be discussed here.

For mine gas collection systems used to collect post drainage or goaf gas, the concentration of oxygen and nitrogen can be significant. Some amount of airflow migrates to the goafs during the routine ventilation of underground mines and due to their porosity and migration through goafs and back to long wall faces, goaf gas will contain a mixture of methane, oxygen, carbon dioxide and nitrogen. The main commercial technology for oxygen removal is based on catalytic oxidation in a reactor, while nitrogen removal is commonly done through cryogenic separation or pressure swing adsorption. Some adsorption and membrane-based processes have shown to be effective, but they are limited in commercial application

Acid Gas Removal
Mine gas, like natural gas or CSG, while predominantly hydrocarbon in nature can contain appreciable amounts of acid gas impurities, such as H2S, COS and CO2. The presence of these “sour” impurities in the presence of water saturated gas can lead to higher corrosion potential in mechanical equipment.

There are a few variables in treating acid gas:

• Types and concentrations of contaminants in the gas;

• Degree of contaminant removal desired;

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• Selectivity of acid gas removal required (i.e. lower proportions of sulphur in mine gas, compared to
conventional gas resource, may affect process design);

• Temperature, pressure, volume, and composition, of the gas to be processed;

• Carbon dioxide–hydrogen sulphide ratio in the gas; and

• Requirement for sulphur recovery – not likely for mine gas acid treatment of gas to be vented to
atmosphere if within air quality regulations(s). Alternatively, sulphur guard beds to be employed for
extraction of sulphur from off-gas.

If a gas contains appreciable amounts of other sulphur components different sweetening methods and/or solvents may need to be considered, which can affect process economics. Note that most mine gas in regional Queensland does not actually exhibit high levels of sulphur, meaning that acid gas plants should be designed with selectivity towards CO2.

Generally, treatment processes are either adsorption or absorption based. Adsorption refers to physical processes wherein impurities are concentrated on the surface of a solids. These types of processes are usually for trim or residual impurity treatment only. Bulk or large-scale acid gas removal is accomplished through chemical absorption processes and may be once through wash systems or more complex, multistep processes with regeneration steps. Most gas processing plants utilise a process with selective absorption of contaminants into a liquid solvent (such as ethanolamine), which is passed counter current to the gas in an absorber column. This section will only discuss the more common, amine-based processes. Other technology options, for example those based on physical rather than chemical absorbents, (Selexol® or Rectisol®), will not be discussed here.

Depending on the composition and operating conditions of the feed gas, different amines can be selected to meet the product gas specification. Amines are categorized as being primary, secondary, and tertiary depending on the degree of substitution of the central nitrogen by organic groups. Primary amines react directly with H2S, CO2, and carbonyl sulfide (COS). Some licensed processes combine amine and inorganic solvents in proprietary mixes. Depending on choice of solvent, varying degrees of pre-treatment and operational controls (e.g. heat integration) may be required to limit solvent degradation, which can occur at elevated temperatures or in the presence of certain additional impurities (e.g. dissolved oxygen). The build-up of heat stable salts can also lead to increased makeup requirements for the solvent.

The principal reaction occurs when the lean solvent solution enters the absorber through which the sour gas is bubbled. Purified gas leaves the top of the tower, and the rich amine solution leaves the bottom of the tower with the absorbed acid gases. The degree of sweetening achieved is largely dependent on the number of trays or the height of packing available in the absorber. The rich solvent enters a stripper regenerator tower where heat and/or lower pressure drives the acid gases from the solution. The regenerated amine solution, restored to its original condition, leaves the bottom of the regenerator tower while acid gases are released from the top of the regenerator.

Amine based processes can be energy intensive but relaxing the specification on acid gas levels in the purified product gas can reduce energy and capital intensity. Most processes are near identical, although consultation with specialist providers or licensors is recommended to define optimal plant configurations. Operational experience has also shown that amine gas treatment is a fouling service with particulate/salt formation. Therefore, some plants will employ different degrees of filtration steps.

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Figure 102 – Generalised Amine based Acid Gas Treatment with Flash Vessel
(Source: Handbook of Natural Gas Processing. Speight et al. (2006).

Oxygen Removal
Generally, coal seam gas does not contain appreciable amounts of oxygen, other than what may ingress in low pressure collection systems. However, for mine gas collection systems used to collect post drainage or goaf gas, the concentration of oxygen and nitrogen can be significant. Some amount of airflow migrates to the goafs during the routine ventilation of underground mines and due to their porosity and migration through goafs and back to long wall faces, goaf gas will contain a mixture of methane, oxygen, carbon dioxide and nitrogen. A very real hazard associated with mining operations is the spontaneous eruption of underground fires, with consequent release of toxic and asphyxiant gases, which illustrates that combustible atmospheres and measurable concentrations of oxygen can be present in coal mine gas. Often mines employ a range of methods to control goaf gas flow and is driven by health and safety.

The main commercial technology for oxygen removal is based on catalytic oxidation in a reactor. Some adsorption and membrane-based processes have shown to be effective, but they are limited in commercial application. The catalytic removal of oxygen from a methane stream requires the gas to be passed over a catalytic bed at an elevated temperature where the oxygen reacts with a small portion of the methane gas to produce water and CO2. A minimum concentration of oxygen is required to ensure sufficient temperature in the reactor unit, which in turn ensures proper conversion of oxygen to water and CO2. At lower concentrations of oxygen supplementary heating (e.g. via an electric or fired heater) may be required. Oxygen removal units are normally designed for 0.2 – 3% (m/m%) concentration in the feedgas. Some literature 36 suggests that oxygen can be reduced to below 10 parts per million (by volume, ppmv).

Nitrogen Removal/Rejection Units (NRUs)
Nitrogen must be removed from natural gas to reduce transportation volumes, increase heating value and to meet pipeline specifications. NRUs are most applicable for post- drainage, mine gas systems and are not required for conventional CSG operations. It should be noted that pipeline gas specifications can allow for up to 7 mol percent of inert gas.

36 Rhodes, Z., (2008) “O2 Removal Key To Tower Mine Project”, American Oil and Gas Reporter, Is.
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Cryogenic NRUs are fairly common installations at large capacity plants, and they are often coupled with hydrocarbon (i.e. C2+ sales gas) recovery units at LNG facilities. In the case of coal mine methane gas, with practically no economically recoverable C2+ components, a standalone, auto-refrigeration rejection unit is more suitable and would offer the highest recovery of methane. Cryogenic NRUs do however require heavy metal removal (e.g. mercury) and have stringent specifications on moisture and
CO2 content. A standard cold box unit will produce methane purity in excess of 95%, up to 98%. With additional processing equipment, a small portion of liquid nitrogen can also be produced, which may be sold onto local market or stored for utility purposes.

In recent times there has been a large amount of research and development effort in the commercialization of physical separation processes for NRUs, using membranes or molecular swing adsorption technologies. The market need for cheaper NRU technologies is also increasing due to the proportion of lower quality reserves in the total gas mix. Future production is also likely to increase from smaller, more remote fields as production from established high quality fields begins to decline.
Therefore, technologies that can treat smaller gas streams, with relatively low energy requirements, will begin to compete well with cryogenic NRUs. Pressure swing adsorption (PSA) units are currently the most commercially advanced alternative to cryogenic units. Note that a detailed section study for choice of NRU technology is appropriate in subsequent phases of project development, particularly given the advancement of membrane technologies over the last >5 years.

Molecular sieve or PSA units are termed a physical process because nitrogen, and other components, are physically adsorbed to a molecular sieve or zeolite adsorbent bed while passing methane. In a typical application feed gas is compressed from low pressure to ~700 kPag using an oil flooded screw compressor and fed to a PSA vessel. The unit is operated cyclically, with a number of vessels operating in a controlled sequence to deliver a constant flow of product gas.

It is typical for a PSA unit to require about 100 kPa for pressure drop. Depending on downstream operations, the product gas will then enter a multistage, reciprocating compressor for pipeline transmission. It is worth noting that some technology suppliers have shown success in meeting pipeline gas specifications with both high levels of CO2 and Nitrogen in feed gas, especially where both inerts are in the same relative quantity (e.g. ~10mol% CO2, 10mol% N2). The main disadvantage with such a physical system is that during the purge sequence a high vacuum must be achieved to provide effective desorption from the adsorbent. This requires a vacuum pump or other vacuum system. In the absence of a perfect vacuum, there will always be “slip” of the inert molecules to the product gas. Generally, recovery of methane is limited to about 95-97%, which at commercial scale can be significant given that cryogenic units can achieve recoveries greater than 99.5%.

Typically, these units are sold as skid mounted packages and therefore may be modularized to suit application. In the absence of sour gas contaminants, the molecular sieve technology is well suited to replace amine plants and cryogenic NRUs.

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Appendix E: Socio-demographic baseline
The study area used to establish the baseline includes the following five LGAs, based on the study area defined in Queensland Treasury’s Bowen Basin Population Report (see Figure 103).

• Whitsunday (R) 37

• Isaac (R)

• Central Highlands (R)

• Woorabinda (S) 38

• Banana (S) 39

Figure 103 - Queensland Treasury’s Bowen Basin population report (2020) study area
Source: (Queensland Treasury, 2021)

1. Population
Table 41 presents an overview of the study area’s population and trends over time. Currently, there are estimated to be 86,636 residents across the study area, which represents less than 1% of the
Queensland population. The largest shares of these residents can be found in Whitsunday (41%) and
Central Highlands (33%). Woorabinda accounts for only 1% of the study area’s population.

Over the past 11 years, the study area’s population has grown at 0.3% per annum on average, slower than the Queensland average (1.6% p.a.). The study area had an annual growth rate of over 1% up until
2012, after which the study area’s population began to grow at a slower rate before experiencing negative annual growth between 2014 and 2018, which is reflected in the five year moving average in

37 In 2008, the Shire of Bowen and the Shire of Whitsunday merged to form the Whitsunday Region. The
Queensland Treasury report uses the old Shire of Bowen boundaries, excluding the Shire of Whitsunday area.
This study will include the entire Whitsunday Region.
38 The Queensland Treasury report excludes the Aboriginal Shire of Woorabinda. It is included in this study area.
39 (R) indicates a region, (S) indicates a shire.
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Figure 104. This slowing growth was predominantly driven by Isaac and Central Highlands experiencing the largest decreases in annual growth rate. As these are the two LGAs with the highest concentrations of mining operations (see Figure 107), the decrease in population growth rate is likely partly attributable to the end of the late 2000s mining boom. In the past few years, the annual population growth rate across the study area has increased.

Over the next 11 years to 2031, the study area is expected to add 7,375 residents giving an average annual rate of 0.7%, again slower than Queensland (1.7% p.a.). Most LGAs will likely see their growth rates increase, except for Woorabinda whose population is expected to decrease. (-0.8% p.a.). Banana is also expected to see population decline but at a slower rate (-0.4% p.a.).

Over the past eleven years, the populations of the four regional LGAs with predominantly primary industry have hardly grown compared to Whitsunday, which has a high concentration of tourism. This trend is expected to continue into the future.
Table 41 - Estimated resident population and projections.
(Source: KPMG Analysis)

Estimated resident Compound average
population annual growth rate

2009 2020 2031 2009 – 2020 2020– 2031

Whitsunday 31,838 35,927 41,072 1.1% 1.2%

Isaac 22,237 20,987 22,709 -0.5% 0.7%

Central Highlands 28,714 28,727 29,319 0.0% 0.2%

Woorabinda 934 995 910 0.6% -0.8%

Banana 14,941 14,065 13,518 -0.5% -0.4%

Study area 83,723 86,636 94,011 0.3% 0.7%

Queensland 4,328,771 5,176,186 6,206,566 1.6% 1.7%
Sources: ABS.Stat, 2021, ERP by LGA (ASGS 2020), 2001 to 2020; Queensland Government Population
Projections, 2018 edition (medium series).

4.0%

3.0%

2.0%

1.0%

0.0%
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
-1.0%

-2.0%

-3.0%
Whitsunday Isaac Central Highlands Woorabinda
Banana Core Study Area Queensland
Figure 104 - Population annual growth rate, 5 year moving average.
(Source: KPMG Analysis)

Source: ABS, 2021, Estimated Resident Population by Local Government Area (ASGS 2020), 2001 to 2020.
Table 42 presents an overview of the study area’s Indigenous population and trends over time. As of the 2016 Census, the study area was home to 5,077 residents that identified as Indigenous (Aboriginal,
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Torres Strait Islander or both), representing 5.2% of the study area’s total population. The study area’s average proportion is higher than the Queensland average (4.0%), as is each LGA except Isaac (3.6%).
Woorabinda, as an Aboriginal Shire, has a significant Indigenous population (94.1%).

In line with the overall Queensland trend, the proportion of Indigenous residents in the study area has increased since 2006. This is mirrored in each LGA except Woorabinda.
Table 42 - Indigenous population, Census data.
(Source: KPMG Analysis)

2006 2011 2016
Indigenous % of Indigenous % of Indigenous % of
population Total population Total population Total

Whitsunday 1,131 3.9% 1,338 4.3% 1,639 4.9%

Isaac 418 2.1% 599 2.7% 744 3.6%

Central Highlands 892 3.4% 1,018 3.5% 1,209 4.3%

Woorabinda 803 94.7% 880 93.2% 905 94.1%

Banana 460 3.1% 583 4.0% 580 4.1%

Study area 3,704 4.1% 4,418 4.5% 5,077 5.2%

Queensland 127,584 3.3% 155,823 3.6% 186,489 4.0%

2. Age Distribution
The figure above illustrates trends over time for select age categories, by proportion of the total population.

Figure 105: Subsets of the population by age categories.
50%

40%

30%

20%

10%

0%
Whitsunday (R) Isaac (R) Central Woorabinda (S) Banana (S) Study Area Queensland
Highlands (R)
2009 0-14 2019 0-14 2031 0-14
2009 15-29 2019 15-29 2031 15-29
2009 30-64 2019 30-64 2031 30-64
2009 65+ 2019 65+ 2031 65+
Sources: ABS. 2010. 3235.0 Population by Age and Sex, Regions of Australia, Table 6. Estimated Resident
Population by Age, Queensland, Persons – 30 June 2009; ABS. 2020. 3235.0 Regional Population by Age and
Sex, Australia, Table 3. Estimated Resident Population by Age, by Local Government Area, Persons – 30 June
2019; Queensland Government. 2018. Population projections, 2018 edition - medium series.

Children (0-14)
The study area’s share of children (22.4%) is higher than the Queensland average (19.4%). Woorabinda has the highest share (33.2%) while Whitsunday has the lowest (17.9%).
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Over the past ten years, this share has marginally increased over the study area (0.2 percentage points from 22.2%), while the Queensland average has decreased (0.7pp from 20.1%). The only two LGAs which did not experience an increase were Woorabinda (2.0pp decrease) and Banana (1.9pp decrease).

Over the next ten years, the share of under-14-year-olds is expected to decrease across the study area
(2.0 percentage points to 20.4%), faster than the Queensland average (1.1pp to 18.3%). Banana is expected to see the largest decrease (3.5pp).

Young workers and school-leavers (15-29)
The study area’s share of 15 to 29-year-olds (18.3%) is lower than the Queensland average (20.2%).
Woorabinda has the highest share (27.7%) while Banana has the lowest (16.6%).

Over the past ten years, this share has decreased over the study area (4.1 percentage points from
22.4%), while the Queensland average has similarly decreased (1.3pp from 21.6%). The only LGA to not experience a decrease was Woorabinda (0.4pp increase).

Over the next ten years, the share of young workers and school-leavers is expected to increase across the study area (1.2 percentage points to 19.5%), whereas the Queensland average is likely to decrease
(1.0pp to 19.2%). Central Highlands is expected to see the largest increase (3.0pp), while Whitsunday is only expected to grow marginally (0.1pp).

Prime and mature working population (30-64)
The study area’s share of prime and mature working-aged residents (47.7%) is higher than the
Queensland average (44.6%). Isaac has the highest proportion (50.0%) and Woorabinda has the lowest
(33.8%).

Over the past ten years, this proportion has not changed across the study area, while the Queensland average decreased (1.4pp from 46.0%). Whitsunday saw a substantial decrease (2.3pp), and Isaac,
Central Highlands and Woorabinda increased by between one and two percentage points.

Over the next ten years, this subset’s share of the total population is expected to decrease across the study area (3.3 percentage points to 44.4%), slower than the Queensland average (1.3pp decrease).
This is mirrored in each LGA, most substantially in Central Highlands (3.7pp decrease).

Senior population (65+)
The study area’s share of over-65-year-olds (11.7%) is lower than the Queensland average (15.7%).
Whitsunday contains the largest share (15.7%) and Woorabinda has the lowest (5.4%).

Over the past ten years, this proportion has increased across the study area (3.4 percentage points from 8.2%), faster than the Queensland average (2.8pp from 12.9%). All LGAs echoed this increase, with the largest occurring in Whitsunday (4.2pp).

Over the next ten years, the senior subset of the population is expected to continue to increase across the study area (4.0 percentage points to 15.7%), faster than the Queensland average (3.5pp to 19.2%).
This trend is expected to happen in each LGA, at the fastest rate in Banana (5.9pp).

Overall trends
The Bowen Basin is home to proportionally more children and prime and mature working-aged residents than Queensland. Conversely, the area has a smaller share of young workers and senior residents than the Queensland average. This may indicate that people move to the Bowen Basin for work; it may also indicate that there is a trend of outward migration upon reaching school-leaving age (for tertiary education or urban career paths) and retirement age.

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Over the next decade, the area is expected to largely follow predicted state-wide trends such as an ageing population, although notably may face a more-substantial decrease in working-age residents.
This may have implications for the labour market and for industry in the Bowen Basin into the future.

3. Labour Force
Table 43 presents an overview of labour force statistics for the study area. As of March 2021, the labour force across the study area was 60,488 people. The participation rate of the labour force (aged 15 and over) as of June 2019 was 73.1%, significantly higher than the Queensland average of 52.1%.
Woorabinda had the highest rate (87.2%) while Whitsunday had the lowest (66.7%).

In March 2021, there were 57,742 employed people in the study area, giving an overall unemployment rate (4.5%) much lower than the Queensland average (7.3%). Isaac had the lowest unemployment rate
(2.0%) while Woorabinda had the highest (7.3%).

Over the 12 months to March 2021, unemployment rates increased in both the study area (0.4 percentage points) and Queensland (1.2 pp). This 12-month period covers the onset of the COVID-19 pandemic and accompanying economic downturn, which can help explain the state-wide trend.
Whitsunday faced the largest increase across the study area (1.0pp), in line with the broader
Queensland average, while the other LGAs were far less impacted or even, in the case of Woorabinda, even decreased (-1.1pp). Whitsunday’s position as an outlier in terms of unemployment can be seen in
Figure 106, in which it is the only LGA which has a range of unemployment rate greater than 2.0 percentage points (~6.0pp). Whitsunday’s increase in unemployment in the 12 months to March 2021 may be attributable in part to its larger sector concentration of (and reliance) tourism – noting that lockdown restrictions and social gathering requirements apply strongly to tourism, whereas mining was far less affected.
Table 43 - Summary of labour force characteristics, March 2021.
12 month
Labour Participation Unemployed Unemployment
unemployment
force rate* persons rate
rate ∆

Whitsunday 21,366 66.7% 1,425 6.7% 1.0pp

Isaac 12,987 76.6% 264 2.0% -0.1pp

Central Highlands 17,131 77.7% 717 4.2% 0.1pp

Woorabinda 592 87.2% 43 7.3% -1.1pp

Banana 8,412 74.8% 297 3.5% 0.2pp

Study area 60,488 73.1% 2,746 4.5% 0.4pp

Queensland 2,713,872 52.1% 197,348 7.3% 1.2pp
*Participation rate for working age population 15 years and older as at June 2019.
Sources: Australian Government’s Small Area Labour Markets (SALM) publication, March Quarter 2021;
ABS, 3235.0 Regional Population by Age and Sex, Australia, June 2019.

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Figure 106 - Unemployment rate.
9.0%

8.0%

7.0%

6.0%

5.0%

4.0%

3.0%

2.0%

1.0%

0.0%
Mar-16 Mar-17 Mar-18 Mar-19 Mar-20 Mar-21

Whitsunday Isaac Central Highlands Woorabinda Banana Queensland

Note: Data is not available for Woorabinda prior to March 2020.
Source: National Skills Commission. 2021. Small Area Labour Markets (SALM), March quarter 2021

Table 44 outlines employment statistics for subsets of the population as of the 2016 Census. Across the study area, 65.0% of residents aged 15 to 24 years old) participate in the labour market, comparable to the overall total participation rate (64.7%). Both the youth and total participation rates are higher for the study area than for Queensland (64.4% and 61.0%, respectively). Woorabinda has a particularly low youth participation rate (23.3%).

The youth unemployment rate of the study area (10.0%) was higher than the overall total unemployment rate (5.6%), with Woorabinda having the highest rate (33.3%). The study area’s youth unemployment rate was lower than the Queensland average (15.8%).

Across the study area, 57.5% of First Nations people participated in the labour market, below the overall total participation rate (64.7%). The study area’s participation rate was higher than the Queensland average (54.7%). Isaac has the highest participation rate (72.7%) while Woorabinda has the lowest
(32.9%).

The study area’s Indigenous unemployment rate (16.2%) was much higher than the overall total rate
(5.6%). However, all LGAs from the study area had a lower Indigenous unemployment rate than the
Queensland average (20.1%).
Table 44 - Labour market subsets, 2016 Census.
Youth Labour Market Indigenous Labour Market Total Labour Market

Participation Unemploy- Participation Unemploy- Participation Unemploy-
rate ment rate rate ment rate rate ment rate

Whitsunday 65.0% 9.5% 60.0% 19.1% 60.7% 6.7%

Isaac 63.6% 9.5% 72.7% 10.0% 67.1% 4.9%

C Highlands 66.2% 10.9% 62.5% 15.0% 67.5% 5.5%

Woorabinda 23.3% 33.3% 32.9% 19.2% 36.5% 17.2%

Banana 69.5% 9.0% 60.9% 17.0% 67.2% 4.0%

Study area 65.0% 10.0% 57.5% 16.2% 64.7% 5.6%

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Youth Labour Market Indigenous Labour Market Total Labour Market

Participation Unemploy- Participation Unemploy- Participation Unemploy-
rate ment rate rate ment rate rate ment rate

Queensland 64.4% 15.8% 54.7% 20.1% 61.0% 7.6%
*Participation rate for working age population 15 years and older as at 2016 Census
Source: ABS, 2016 Census of Population and Housing.

4. Industry (place of usual residence)
There were 98,000 workers who lived in the study area as of the 2016 Census. Whitsunday had the most (34.5%; 33,782 workers) while Woorabinda had the fewest (1.0%; 960 workers).

As demonstrated in Figure 107, the most common industry was Mining, employing approximately one in five workers across the study area (20.4%; 9,122 workers) and almost two in five workers in Isaac
(38.7%; 3,759 workers) – far higher than the Queensland average (2.4%). Woorabinda does not employ any local residents in mining. Within the Mining industry, Coal Mining employs the vast majority of workers (8,309 workers), while Oil & Gas Extraction employs the fewest (95 workers).

Mining was followed by Agriculture, Forestry & Fishing (12.6%), Accommodation & Food Services
(9.6%) and Retail Trade (8.1%) in terms of employment.
Figure 107 - Top ten industries by employment, place of usual residence, 2016 Census.

Mining

Agriculture, Forestry and Fishing

Accommodation and Food Services

Retail Trade

Education and Training

Health Care and Social Assistance

Construction

Transport, Postal and Warehousing

Public Administration and Safety

Other Services

0% 10% 20% 30% 40%
Proportion of local workforce

Whitsunday (R) Isaac (R) Central Highlands (R)
Woorabinda (S) Banana (S) Core Study Area
Queensland

Note: Excludes the industry categories of Inadequately Described, Not Stated and Not Applicable. ABS does not separate out data for the tourism industry.
Source: ABS, 2016 Census of Population and Housing .
As at June 2016, there were a number of residents within the study area employed in industries directly relevant to the development of a gas pipeline. 5.8% were employed in the Construction industry (2,597
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workers), which predominantly driven by the Construction Services subsector (1,588 workers), followed by Building Construction (501 workers) and Heavy & Civil Engineering Construction (381 workers).

5. Industry (place of work)
There were 59,653 jobs (people who were employed) in the study area as of the 2016 Census. The largest proportion of these was in Isaac (33.6%; 20,034 jobs) and the smallest proportion was in
Woorabinda (0.4%; 265 jobs).

As illustrated by Figure 108, the Mining industry represents the largest share of jobs across the study area (34.6%; 19,981 jobs), with three out of every five jobs in Isaac being in mining (61.0%; 11,919 jobs). Woorabinda does not have any mining jobs. Within the Mining industry, Coal Mining supports the vast majority of jobs (18,072 jobs), while Non-Metallic Mineral Mining & Quarrying supports the fewest
(95 jobs). Oil & Gas Extraction accounts for 152 jobs across the study area.

Outside of Mining, jobs are predominantly supported by Agriculture, Forestry & Fishing (9.8%),
Accommodation & Food Services (8.3%) and Retail Trade (6.4%).
Figure 108 - Top ten industries of employment, place of work, 2016 Census.

Mining

Agriculture, Forestry and Fishing

Accommodation and Food Services

Retail Trade

Education and Training

Construction

Health Care and Social Assistance

Transport, Postal and Warehousing

Public Administration and Safety

Manufacturing

0% 10% 20% 30% 40% 50% 60% 70%
Proportion of jobs

Whitsunday (R) Isaac (R) Central Highlands (R)
Woorabinda (S) Banana (S) Core Study Area
Queensland

Note: Excludes the industry categories of Inadequately Described, Not Stated and Not Applicable. ABS does not separate out data for the tourism industry.
Source: ABS, 2016 Census of Population and Housing .

6. Occupation (place of usual residence)
As shown in Figure 109, Technicians & Trades Workers (18.0%) and Machinery Operators & Drivers
(16.6%) were the most common occupations for residents of the study area, which is reflective of the
Bowen Basin’s high concentration of primary industry.

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The study area had higher proportions of these occupations than the Queensland average (14.5% and
7.0%, respectively). This was mirrored in every individual LGA except for Woorabinda, which instead had a very large proportion of Community & Personal Service Workers (31.2%) – far higher than state and study area averages. The study area also had significantly lower proportions of Professionals and
Clerical & Administrative Workers.
Figure 109 - Local workers’ occupation (place of usual residence), 2016 Census.
35%

30%

25%

20%

15%

10%

5%

0%
Technicians Machinery Managers Labourers Professionals Clerical and Community Sales Workers
and Trades Operators and Administrative and Personal
Workers Drivers Workers Service
Workers
Whitsunday (R) Isaac (R) Central Highlands (R) Woorabinda (S)
Banana (S) Core Study Area Queensland

Note: Excludes the occupation categories of Inadequately Described, Not Stated and Not Applicable.
Source: ABS 2016 Census of Population and Housing.

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Appendix F: Recent Policy Reform
The following sections detail the key policy reform measures recently introduced that affect the functioning of the ECGM.

Australian Domestic Gas Security Mechanism (ADGSM)
In response to price increases during 2016 and 2017, the ADGSM was established as a temporary supply security measure to cease on January 1, 2023. The ADGSM is intended to ensure sufficient supply of natural gas to meet the forecast needs of energy users in Australia. It aims to do so by limiting exports of LNG during a domestic shortfall year and establishing a licensing regime whereby the
Resources Minister may grant Export Permission to LNG exporters. Since the introduction of the
ADGSM, LNG exporters have increased supply to the domestic market and are currently, in aggregate, net contributors to the domestic market.

A Government review in 2020 recommended retaining the ADGSM until the scheduled 2023 cessation, amending the guidelines to include reference to the ACCC’s LNG netback price series in estimating a potential shortfall. This stops short of introducing direct price controls in the ECGM, but it does link the
ADGSM to LNG netback prices.

Heads of Agreement
On two occasions, a Heads of Agreement (HoA) has been signed by the Australian Prime Minister and representatives of the three east coast LNG exporters (APLNG, GLNG, QGC) to ensure these producers make available a secure supply of gas to the east coast market. Under the agreement, LNG exporters committed to offer uncontracted gas to the domestic market before selling this gas internationally. The
HoA expired at the end of 2020 with a new one signed in January 2021. The Australian Government has said it wants to ‘strengthen’ the HoA with east coast LNG exporters and include a reference to
LNG netback pricing.

Domestic Gas Reservation Scheme
Whilst the ADGSM functions somewhat as a domestic gas reservation scheme, the Australian Federal
Government has announced its intention to explore options for a national domestic gas reservation scheme. This may take the form of acreage reservation, preferential reservation, blanket reservations or case-by-case assessments. As the states hold jurisdiction over onshore petroleum resources, any
Federal Government scheme would need to be implemented with support of the states. There is no national domestic reservation scheme in Australia at the moment, however there are existing schemes that utilise different approaches across various states, particularly in Queensland and Western Australia.

Queensland
Through its regulation of petroleum leases, the Queensland Government imposes a condition on certain tenements that any petroleum developed on the leased acreage must be sold and used only in Australia.
Recently, the Queensland Government included a specific requirement for gas produced to be supplied to domestic manufacturing consumers. This approach will not impact the market materially because it will just displace existing supply to these consumers.

The Queensland Government commissioned an independent review of this policy in 2019. The final report released in February 2020 found that stakeholders broadly accepted the policy but noted there was room for improvement around adaptability, efficiency and transparency, and provision of information to market participants.

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Western Australia
Western Australia adopts a policy that requires LNG producers to reserve the equivalent of 15% of LNG production for the domestic market. LNG producers can obtain project approval by proving they will reserve gas for the market, develop the necessary infrastructure, and show diligence and good faith in marketing the gas. The policy has been in place for a number of years and is flexible with respect to exact timing, price, and sale conditions.

We understand that the Western Australian domestic gas reservation policy has been relatively successful in terms of supporting the domestic market and not being a significant impost on LNG producers. One of the reasons for this is that in Western Australia the natural gas industry is predominately offshore, with conventional wells extracting large reserves of gas and without the complications of CSG production. The Western Australian Government and the projects negotiate timing for domestic gas flows in a way that meets the objectives of the domestic market and LNG exporters.

Queensland Petroleum Royalty Review
The Queensland Government announced major changes to how petroleum royalties will be calculated from October 1, 2020. Under the review, royalties are now calculated based on applying a tiered royalty rate to the volume of petroleum produced for each class of gas, rather than the previous system of
12.5% of wellhead value of petroleum disposed. The change was in response to producers and industry participants voicing concerns about the complexity of the prior regime and successful court challenges to a previous royalty decision. A different royalty rate will be prescribed for each petroleum classification and will remain unchanged for five years. The royalty changes may have implications for existing contracts which may have anticipated the wellhead value model continuing.

Gas Fired Recovery
The Australian Federal Government announced a ‘Gas-Fired Recovery’ scheme in September 2020 as part of the COVID-19 economic recovery plan. One objective of the scheme is to increase the supply of gas in the market by setting new gas supply targets with states and territories and unlocking five key gas basins in the Northern Territory and Queensland at a cost of $28.3M. The Government is also considering a reservation scheme to secure future gas supplies for domestic consumption only. A
$10.9M National Gas Infrastructure Plan has been proposed to identify priority pipelines and infrastructure. The intention is to deliver more gas at an affordable and internationally competitive price.
Prime Minister Scott Morrison stated that, “affordable gas will play a central role in re-establishing the strong economy we need for jobs growth, funding government services and opportunities for all”.

Industry bodies have raised concern over the proposed scheme. Australian Petroleum Production &
Exploration Association (APPEA) chief executive Andrew McConville said, “caution is needed when considering any regulatory interventions that could risk the attractiveness of Australia as an investment destination for oil and gas projects – these projects are essential for shoring up Australia's future gas supplies”.

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Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning

REFF – Project Proposal Form
Guidance Note:
Firstly, we are seeking suggestions on projects or activities that can support the program objectives via this
Project Proposal Form. Proposed projects should support at least one objective and at least one of the criteria
(refer page 3).

As part of our assessment process, we will also consider the following:
• If the proposed project can commence in the first half of 2024 and finish within 2 years.
• Deliverability will also be considered, including consideration of key risks, stakeholder views and the
capability and reputation of the entity delivering the proposal.
• If the proposed activity is ‘value for money”

Funding will be allocated to specific projects that will best support the region’s economy over the long term,
creating sustainable jobs and stronger, diverse economies. Some examples include:
• Projects that create new jobs (expansion of existing industry or investment attraction)
• Activities that strengthen existing regional supply chains
• Specific activities that support decarbonisation and the Queensland Energy and Jobs Plan
• Specific activities that build on or identify a region’s strengths, such as research and business cases.
• Specific precinct development to support a diverse economy.

Funding is unlikely to be allocated to projects that would normally be funded via other programs or organisations,
unless it provides an opportunity to leverage funding already allocated to the project and bring forward
implementation. The key consideration would be long-term benefit in terms of investment and jobs for the region.

Suggestions to consider before you complete the proposal form include:
• The first consideration should be given to the timeframe specifications - proposed projects would need to
commence within 6 months of contract and finish within two years.
• Define the problem, purpose, goals, objectives, and scope of the project in high level detail to explain
your project proposal. This is the initial stage of seeking project proposals, further details may be
requested if the project is potentially suitable for funding.
• Present your proposal with consideration to the criteria and objectives listed on page 2, ensuring that
your proposal meets one or more of the objectives/criteria.
• A full business case is not required, however if available, attach any supporting documentation that you
may have to support your proposal.
• State your plan or outline your project schedule, budget, and required resources to the best of your
ability. The department acknowledges this will likely need to be refined if the proposal progresses.
• We are happy to receive a project proposal on activities you feel government or others should implement
(you don’t have to be project lead).
• For partnerships, it is important that you have drafted your proposal in consultation with the agency or
business you are partnering with.
• Familiarise yourself with the REFF region, remember project proposals that benefit the region more
broadly will be looked upon favourably.

Please note that all Project Proposals are due to be submitted by 18 August 2023.

And finally, I would encourage you to email or pick up the phone and discuss your ideas with your local
DSDILGP contact. We are happy to talk through your ideas and help you to define and focus any project
proposals you may have.

Darling Downs South West: Jodie Weller, jodie.weller@dsdilgp.qld.gov.au, 0457 232 090 / 07 4616 7318
South Burnett: Fiona Bowden, Fiona.bowden@dsdilgp.qld.gov.au, 0411 075 413 / 07 4331 5610
Central Queensland: Chris Filby, Chris.filby@dsdilgp.qld.gov.au, 0436 689 844 / 07 4924 2903
Greater Whitsunday: Nikki Wright, Nikki.wright@dsdilgp.qld.gov.au, 0427 769 519 / 07 4898 6818
North West: Gavin Taylor, gavin.taylor@dsdilgp.qld.gov.au, 0417 349 476

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning

Project Identification

Project Title Carbon Capture & Storage in the Bowen Basin – Feasibility
Studies

Proponent Direct funding to the University of Queensland Centre for
Natural Gas, CO2CRC and/or Low Emissions Technology
Australia, ideally in partnership with ARENA

Region and (if appliable) location/s of Central Highlands Region and Isaac Region
Project

Project Background

Overview of the proposed project and Feasibility study to inform policy and decision makers as to whether current status (100 words or less) or not material carbon abatement is feasible through implementing
industrial-scale carbon capture and storage (CCS) in the Queensland
Bowen Basin.

Summary of what will be delivered (key Feasibility study to inform policy and decision makers as to whether actions and outcomes). Attach Project or not material carbon abatement is feasible through implementing
Plan (if available) industrial-scale carbon capture and storage (CCS) in the Queensland
Bowen Basin.
The feasibility study may result in a recommendation to undertake a
CCS pilot within the region, subject to community consultation, which
would deliver the following outcomes:
• Determine whether CCS, specifically within EPQ10, can be a
safe and viable option to avoid emissions of GHG emissions
to the atmosphere with direct capture and storage of a GHG
stream from industrial sources to assist in meeting global,
Commonwealth and Queensland GHG emission targets;
• Demonstrate whether over a three-year period the
continuous injection of a GHG stream, with monitoring to
occur prior to and continuously throughout the injection
period and for two years after injection has ceased, totalling 5
years of monitoring has any adverse impacts and is
successful;
• Seek to contribute to governmental and corporate pathways
to net zero emissions as part of its global climate change
policy by way of the potential to generate Australian Carbon
Credit Units under the Carbon Credits (Carbon Farming
Initiative) Act 2011 (CFI Act) if declared to be an eligible
offsets project under the CFI Act;
• Contribute to the global use of CCS as a viable method of
avoiding emissions of GHGs to atmosphere; and
• Provide critical data on GHG stream plume behaviour to
assist in the EIS assessment processes for approvals for

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning
future CCS projects in Queensland beyond the GHG
exploration permit stage under the GHG Storage Act.

What are the indicative Procurement to commence in May 2024 with delivery by the end of timeframes/milestones of the project? the 2024/2025 financial year.
(Include proposed state date, completion dates and any proposed stages. Note – any funding confirmation is not expected until
January 2024, with all projects required to commence within 6 months of approval)

Which organisation will be responsible Ideally ARENA, the University of Queensland Centre for Gas, for delivery of the project? CO2CRC and/or Low Emissions Technology Australia) would be
funded directly with Central Highlands Regional Council as a key
stakeholder.

Outline the capacity of this organisation Delivery of the feasibility study will be auspiced within the BAU of to deliver the project. Do they have Central Highlands Regional Council’s Principal Projects Advisor or confirmed delivery partners? If so, Development Corporation. Ideally, the project would be delivered in please identify these partners. partnership with ARENA.

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning
Project Alignment (Must meet at least one objective and one criteria)

Proposed alignment to Program objectives and criteria

Program objectives Yes No Summary rationale

Enhancing economic, social and environmental N
The feasibility study in itself will not enhance liveability
economic, social and environmental liveability,
however any project stemming from the study
may enhance these outcomes.
Identifying opportunities for sustainable regional Y
If carbon capture and storage was proven, growth and economic diversification
through the study, to be a viable solution, it
would identify opportunities for additional
economic diversification within the Central
Highlands and Isaac regions.
Supporting the transformation of regional Y
Existing studies, such as the University of communities to a low-emissions economy
Queensland ‘Surat Deep Aquifer Appraisal
Project (UQ-SDAAP): Scoping study for
material carbon abatement via carbon capture
and storage’, outlined the following benefits of
development of a carbon capture and storage
(CCS) hub:
1. Low-emissions baseload power: A
CCS Hub would gradually convert and
abate existing plants resulting, in up to
1.62 GW of installed, low-carbon, net
baseload power in the national
electricity market (NEM) for 30 years
or more (the reference case for UQ-
SDAAP was 13 Mt/yr for 30 years). It
could deliver annually up to 12,800
GWh of baseload power. For fully
retrofitted plants4, emissions intensity
would be an average of 135 kg
CO2e/MWh5 , and the base case
levelised cost of electricity (LCOE)
would be less than $70/MWh6 2
2. Material emissions reductions: On
current data, it seems likely that a hub
could safely capture and inject about
13 million tonnes per annum of CO2
for around 30 years, with indefinite
secure retention. UQ-SDAAP
scenarios have been modelled
conservatively. There is considerable
upside with some scenarios extending
the plateau for three or more decades
culminating in around 650 million
tonnes. If new data supports this, it
would require that future CO2 sources
would be “plumbed in”.
Notwithstanding this, even the “limited”
retrofit scheme can contribute
significantly beyond Australia’s current

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning
nationally determined contributions
(COP21 NDC commitments)
3. Regional employment: CCS could
create about 250 new regional jobs in
the retrofit and construction phase, as
well as either safeguarding, or even
extending the need for, approximately
500 existing regional jobs in the power
plants and adjacent mines. Indirect
employment multipliers in the local
economy have not been assessed in
this study, however previous work has
suggested this would be statistically
significant
4. Enabled low-carbon economy: The
creation of a CO2 transport and
storage hub infrastructure could
potentially enable additional,
traditionally high CO2 intensity
industries. This includes, but is not
limited to, the production of hydrogen
from coal or natural gas or a hybrid
approach with renewables.
If CCS in the Bowen Basin is determined to be
feasible, the feasibility study will support the
transformation of the Central Highlands to a
low-emissions economy – such options ought
to be explored as part of broader economic
diversification options to be considered within
the Central Highlands.

Program criteria

Responds to an issue or opportunity outlined in the N/A This criterion cannot be further expanded regional transformation strategy upon, noting that the regional transformation
strategy has not yet been delivered.

Supports long-term employment growth and N The feasibility study will not, in itself, lead to retention, through industry/business expansion, long-term employment growth, however any investment attraction or skills development project stemming from the study may enhance
these outcomes.

Provides specific opportunities to diversify the Y If carbon capture and storage was determined, economy through the study, to be a viable option within
the Bowen Basin, it would identify
opportunities for additional economic
diversification within the Central Highlands and
Isaac regions and would support job creation.

Facilitates the establishment of new industries in the Y If carbon capture and storage was determined, region through the study, to be feasible in the Bowen
Basin, it would facilitate the establishment of a
pilot project (subject to further funding) and a
potential CCS Hub within the region.

Strengthens existing regional supply chains N

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning
Develops business and industry capacity to operate Y
If a CCS pilot and eventual Hub was in a low-emissions or more diversified economy
determined to be feasible through the study,
existing metallurgical and thermal coal
industries (including steel production and
domestic energy production to supplement
baseload power) would be supported to
continue for the indefinite future.
Supports precinct development to assist in local N investment, diversity or decarbonisation

Supports Aboriginal & Torres Strait Islander N The feasibility study will not, in itself, lead to employment, skills development, business Aboriginal and Torres Strait Islander establishment or investment employment and skills development, however
any project stemming from the study may
enhance these outcomes.

Identifies or leverages a region’s strengths by way of Y The project will deliver a feasibility study which feasibility studies, business cases or targeted may complement the geological strengths of research the Central Highlands Region. In turn, this may
support the ongoing sustainability of the
metallurgical and thermal coal mining sectors
within the region, which are a major contributor
to regional employment.

Project Justification

What is the need or demand for this (or Developed as part of the Australian Government’s Technology problem the project is aiming to Investment Roadmap process, the Low Emissions Technology resolve)? Statement 2021 outlines priority technologies with the potential for
transformational economic and emissions outcomes, in Australia and
globally, including carbon capture and storage.
The University of Queensland Surat Deep Aquifer Appraisal Project
(UQ-SDAAP): Scoping study for material carbon abatement via
carbon capture and storage included a recommendation that “to
quantify the full potential for east-coast carbon abatement for an
orderly transition, a wider program of dynamic storage assessment in
other basins is required” – such basins include the Bowen Basin.
The International Energy Agency emphasises that a full suite of
technologies will be required to bring down emissions. They have
positioned CCS as a key strategy to abate long-lived, high-intensity,
stationary, industrial and power sector sources. Similarly, the recent
2018 Intergovernmental Panel on Climate Change "Special Report:
Global Warming of 1.5°C" which explored the impacts of global
warming at 1.5°C, identified CCS as a critical technology for
managing the transition to a more sustainable energy future.

What are the objectives and proposed Existing studies, such as the University of Queensland ‘Surat Deep benefits of the Project? Aquifer Appraisal Project (UQ-SDAAP): Scoping study for material
carbon abatement via carbon capture and storage’, outlined the
(Consider labour market impact, emissions
following benefits of development of a carbon capture and storage reduction, additional spend in region, social
(CCS) hub: inclusion, liveability, local supply chain opportunities, business or industry capacity

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning building, Aboriginal and Torres Strait 1. Low-emissions baseload power: A CCS Hub would gradually
Islander participation, support towards convert and abate existing plants resulting, in up to 1.62 GW precinct development or further investment, of installed, low-carbon, net baseload power in the national etc. electricity market (NEM) for 30 years or more (the reference
case for UQ-SDAAP was 13 Mt/yr for 30 years). It could
deliver annually up to 12,800 GWh of baseload power. For
fully retrofitted plants4, emissions intensity would be an
average of 135 kg CO2e/MWh5 , and the base case
levelised cost of electricity (LCOE) would be less than
$70/MWh6 2
2. Material emissions reductions: On current data, it seems
likely that a hub could safely capture and inject about 13
million tonnes per annum of CO2 for around 30 years, with
indefinite secure retention. UQ-SDAAP scenarios have been
modelled conservatively. There is considerable upside with
some scenarios extending the plateau for three or more
decades culminating in around 650 million tonnes. If new
data supports this, it would require that future CO2 sources
would be “plumbed in”. Notwithstanding this, even the
“limited” retrofit scheme can contribute significantly beyond
Australia’s current nationally determined contributions
(COP21 NDC commitments)
3. Regional employment: CCS could create about 250 new
regional jobs in the retrofit and construction phase, as well as
either safeguarding, or even extending the need for,
approximately 500 existing regional jobs in the power plants
and adjacent mines. Indirect employment multipliers in the
local economy have not been assessed in this study,
however previous work has suggested this would be
statistically significant
4. Enabled low-carbon economy: The creation of a CO2
transport and storage hub infrastructure could potentially
enable additional, traditionally high CO2 intensity industries.
This includes, but is not limited to, the production of hydrogen
from coal or natural gas or a hybrid approach with
renewables.

How will this project support economic Please see response provided under ‘What are the objectives and transition? (Consider how the project will proposed benefits of the Project?’ support project objectives including economic transformation into low emissions economy, diversification or long term sustainability)

How does this project align to Inquiry into Geosequestartion Technology
Queensland and Local Government
The then Premier Anna Blight made a submission to the inquiry policy and strategies? (Where possible,
outlining that CCS is one of the options for reducing atmospheric cite specific objectives in government policy
emissions of CO2, recognising that “the commercial development of
- e.g.: Queensland Energy and Jobs Plan)
CCS technology is fundamental to meeting the twin challenges of
significantly reducing GHG emissions, whilst sustaining economic
development that is underpinned by the State’s abundant coal
resources. As such the Queensland Government is leading Australia
in the promotion of clean coal technology (CCT) and associated CCS
as a key response to GHG induced climate change.”
Queensland Hydrogen Industry Strategy

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning
The Queensland Hydrogen Industry Strategy recognised the role of
CCS –“‘blue hydrogen is produced by incorporating carbon capture
and storage into the steam methane reformation production
processes. Blue hydrogen is seen as a step towards achieving net
zero”.
Central Highlands Regional Council Corporate Plan 2022-2027
The Central Highlands Regional Council Corporate Plan 2022-2027
includes a long term destination goal to ‘prepare for a low carbon
future and adapt to a changing climate’ – CCS may be a potential
way to achieve the long term destination goal, which will be explored
in the feasibility study project.
Technology Investment Roadmap
CCS was recognised within the former Federal Government’s
Technology Investment Roadmap as a priority technology.

Indicative number of jobs created or Based upon the Carbon Transport and Storage Corporation (CTSCo) retained, including: Pty Limited’s Surat Basin Carbon Capture and Storage Project, any
pilot subsequent to the feasibility study will result in:
• New direct jobs created (FTE)
• New indirect jobs created (FTE) • Up to 32 FTEs (all program phases).
• Jobs retained (FTE) • Approximately 5 FTEs (operational).
Details of new regional skills developed/utilised
Details of where direct or indirect jobs are retained or created

Project Cost and Funding

Total project cost ($) (Attach Project Unknown – further engagement with ARENA, the University of budget) Queensland Centre for Gas, CO2CRC and/or Low Emissions
Technology Australia would be required

Funding requested of government ($) Full funding

Contribution from Proponent or other N/A parties ($)

Delivery and Additional Information

Have you completed a risk assessment Key risks identified include: for the project? (Please attach) If not, please provide a summary of the key • Stakeholder concern in relation to injection of carbon waste project risks/assumptions and detail into aquifers.
how they are proposed to be mitigated? • Stakeholder concern in relation to groundwater impacts.
Such stakeholder concerns can be mitigated by some extent by
communicating that the intent of the feasibility will be, inter alia, to
determine these impacts prior to any pilot proceeding so that future
decisions are evidence-based.

CONFIDENTIAL
Department of State Development, Infrastructure, Local Government and Planning Development, Infrastructure,
Local Government and Planning

Which other parties will be impacted? Farmers, environmental organisations and agricultural peak bodies.
Have they been consulted? What views Such bodies could be consulted as part of the Feasibility Study.
and issues have they raised and how have these been addressed?

Detail what additional information that Nil can be provided if required.

CONFIDENTIAL

REFF – Project Proposal Form

Guidance Note:

Firstly, we are seeking suggestions on projects or activities that can support the program objectives via this Project Proposal Form. Proposed projects should support at least one objective and at least one of the criteria (refer page 3).

As part of our assessment process, we will also consider the following:

If the proposed project can commence in the first half of 2024 and finish within 2 years.

Deliverability will also be considered, including consideration of key risks, stakeholder views and the capability and reputation of the entity delivering the proposal.

If the proposed activity is ‘value for money”

Funding will be allocated to specific projects that will best support the region’s economy over the long term, creating sustainable jobs and stronger, diverse economies. Some examples include:

Projects that create new jobs (expansion of existing industry or investment attraction)

Activities that strengthen existing regional supply chains

Specific activities that support decarbonisation and the Queensland Energy and Jobs Plan

Specific activities that build on or identify a region’s strengths, such as research and business cases.

Specific precinct development to support a diverse economy.

Funding is unlikely to be allocated to projects that would normally be funded via other programs or organisations, unless it provides an opportunity to leverage funding already allocated to the project and bring forward implementation. The key consideration would be long-term benefit in terms of investment and jobs for the region.

Suggestions to consider before you complete the proposal form include:

The first consideration should be given to the timeframe specifications - proposed projects would need to commence within 6 months of contract and finish within two years.

Define the problem, purpose, goals, objectives, and scope of the project in high level detail to explain your project proposal. This is the initial stage of seeking project proposals, further details may be requested if the project is potentially suitable for funding.

Present your proposal with consideration to the criteria and objectives listed on page 2, ensuring that your proposal meets one or more of the objectives/criteria.

A full business case is not required, however if available, attach any supporting documentation that you may have to support your proposal.

State your plan or outline your project schedule, budget, and required resources to the best of your ability. The department acknowledges this will likely need to be refined if the proposal progresses.

We are happy to receive a project proposal on activities you feel government or others should implement (you don’t have to be project lead).

For partnerships, it is important that you have drafted your proposal in consultation with the agency or business you are partnering with.

Familiarise yourself with the REFF region, remember project proposals that benefit the region more broadly will be looked upon favourably.

Please note that all Project Proposals are due to be submitted by 18 August 2023.

And finally, I would encourage you to email or pick up the phone and discuss your ideas with your local DSDILGP contact. We are happy to talk through your ideas and help you to define and focus any project proposals you may have.

Darling Downs South West: Jodie Weller, jodie.weller@dsdilgp.qld.gov.au, 0457 232 090 / 07 4616 7318

South Burnett: Fiona Bowden, Fiona.bowden@dsdilgp.qld.gov.au, 0411 075 413 / 07 4331 5610

Central Queensland: Chris Filby, Chris.filby@dsdilgp.qld.gov.au, 0436 689 844 / 07 4924 2903

Greater Whitsunday: Nikki Wright, Nikki.wright@dsdilgp.qld.gov.au, 0427 769 519 / 07 4898 6818

North West: Gavin Taylor, gavin.taylor@dsdilgp.qld.gov.au, 0417 349 476

Project Identification

Project Title

Development of the Bowen Basin Gas Pipeline

Proponent

Private Sector/State/Federal Government

Region and (if appliable) location/s of Project

Isaac Region (specifically the Moranbah gas fields) and the Central Highlands Region (specifically the Blackwater and Mahalo gas fields) as below:

Project Background

Overview of the proposed project and current status (100 words or less)

Development of the Bowen Basin Gas Pipeline, consistent with the recommendation made within the KPMG Bowen Basin Concept Study produced for the Department of Resources in 2021, accessible here: https://www.resources.qld.gov.au/__data/assets/pdf_file/0008/1592855/bowen-basin-study-final-report.pdf

Summary of what will be delivered (key actions and outcomes). Attach Project Plan (if available)

The development of the Bowen Basin Gas Pipeline in accordance with the recommendation made within the KPMG Bowen Basin Concept Study will result in the provision of key export infrastructure to capture coal mine methane (CMM), which includes pre-drainage of SIS gas, open cut mine operational emissions, ventilation air methane and goaf gas. Delivery of the infrastructure will not only result in delivery of a transition fuel resource identified by Australia’s then Chief Scientist, Alan Finkel, as essential in the transition to renewables energy sources, to pick up where batteries and pumped hydroelectricity run short as existing coal-fired power stations close, but also will reduce emissions from coal mines, which have a substantial greenhouse footprint through fugitive emissions, which represent 11-15% of Queensland’s total emissions – this said in the context of a continued need for metallurgical coal nationally and internationally.

Following exhaustion of the gas fields (or otherwise cessation of extraction), the Bowen Basin Gas Pipeline infrastructure could be repurposed for the transport of hydrogen produced in inland locations to be exported or used for domestic power supply, including through repurposing coal-fired power station infrastructure in Gladstone to become hydrogen power plant. Hydrogen produced inland could utilise coal seam gas by-product water. Therefore, the infrastructure could support a whole lifecycle, beyond only natural gas and set Queensland up with infrastructure to support the transition to a net-zero emissions economy well into the future.

What are the indicative timeframes/milestones of the project? (Include proposed state date, completion dates and any proposed stages. Note – any funding confirmation is not expected until January 2024, with all projects required to commence within 6 months of approval)

The KPMG Report details that a Financial Investment Decision needs to be made sooner rather than later, together with sufficient development of reserves to supply the pipeline. The analysis undertaken by KPMG identified that the best case timeline for a material increase in gas production in the Bowen Basin is 5 years, comprising:

Project establishment and market conditions for commencement of development – unknown

Exploration and appraisal to firm up sufficient resource – approximately 2 years

Gas plant and Pipeline – typical duration for approvals, engineering, procurement and construction – 2 to 3 years

The KPMG Report identified that there are no major issues with existing support infrastructure to enable development and therefore attributed no material impact to timelines associated with this.

It is noted that the Federal Government, under the Strategic Basin Plan for the North Bowen Basin as part of the gas-fired recovery, allocated $20.7million of direct investment as well as leveraging over $400million in research and infrastructure upgrades to deliver on immediate actions – therefore some of this work is already partially complete.

It is anticipated that production could occur from the Mahalo fields earlier than the rest of the fields whilst the pipeline is being constructed and this is consistent with the staged approach recommended by KPMG as part of the recommended option – see sections 11.4 to 11.5 of the KPMG Report.

Which organisation will be responsible for delivery of the project?

Private Sector, State Government and Federal Government

All tiers of government will need to play a pivotal role in facilitating the development of the Bowen Basin if it is to maximise its benefits. To facilitate the development of the Bowen Basin to the benefit of all Queenslanders, and in response to stakeholder challenges, three key focus areas for government are starting to emerge:

Enabling infrastructure: Facilitating, through direct investment, subsidy, or other de-risking measures, the construction of common infrastructure to enable access to market, delivering affordable gas supplies, increasing competition, building international competitiveness and attracting private investment.

Supporting net zero emissions targets: Leading by example in reducing fugitive emissions, investing in exploration activities and technology to improve the scientific understanding of geosciences date needed by industry.

Growing our regions: Strengthening the regions’ economic by supporting ongoing jobs across supply chains, industries investing in skills for the development of next generation of workers and creation new economic opportunities through diversification of the regions’ economic base.

These focus areas straddle numerous portfolios across all tiers of Government, with numerous initiatives already underway that will inform and influence the development of the Bowen Basin. However, the unlocking of the Bowen Basin cannot be delivered by Government alone – industry must play their part.

A coordinated approach to planning and investment across all tiers of Government and industry will be required to ensure that the benefits of individual initiatives across portfolios and industry are maximised.

Outline the capacity of this organisation to deliver the project. Do they have confirmed delivery partners? If so, please identify these partners.

Unknown capacity. Capability of various proponents such as Santos, Arrow and APLNG to deliver gas pipeline approval and construction at a similar scale has been demonstrated in construction of the existing pipeline connecting the Surat Basin to Gladstone’s Curtis Island.

Project Alignment (Must meet at least one objective and one criteria)

Proposed alignment to Program objectives and criteria

Program objectives

Yes

No

Summary rationale

Enhancing economic, social and environmental liveability

Y

Developing the Bowen Basin Gas Pipeline and resources will be complex and challenging but has the opportunity to improve Queensland’s productivity, liveability and environmental sustainability.

As with the development of any gas basin, many challenges and opportunities are present. However the analysis undertaken as part of the KPMG study confirmed that there is a clear need for the securing of additional gas supplies and Queensland is in the optimal position to leverage that opportunity with the development of the Bowen Basin.

Economic, social and environmental benefits include:

New revenue stream to replace lower mining royalties in a post thermal coal world (and perhaps post metallurgical coal world, subject to the commercialization of green steel);

Secured supply of gas for domestic customers;

Stable and affordable energy prices – there is a strong relationship between economic growth and energy prices – other things being equal, high energy prices increase production costs and slow down economic growth

Providing certainty for industry to invest resulting in jobs and economic growth; and

Meaningful contribution to Queensland’s net zero targets by reducing fugitive gas emissions.

Identifying opportunities for sustainable regional growth and economic diversification

Y

Development of the Bowen Basin will improve the prosperity of Queensland, most notably the regions and will stimulate further industrial development in larger centres such as Gladstone, Mackay and Townsville. The KPMG Study states that the project will:

“Enable the regions to invest in skills of the next generation of workers and provide opportunities along the supply chain”; and

“Future proof the regions”.

The project would unlock a new basin and economic opportunity, not only in CMM gas, but also beyond that as a basin for hydrogen production and therefore the project would secure long term jobs spanning across gas and renewable energy industries.

In addition, development of the project would ensure that the metallurgical coal mining sector, crucial to royalties, is able to abate emissions and continue economic output to benefit the Isaac and Central Highlands regions directly through employment and supply chains and the broader Queensland economy.

Supporting the transformation of regional communities to a low-emissions economy

Y

The development of the Bowen Basin Gas Pipeline in accordance with the recommendation made within the KPMG Bowen Basin Concept Study will result in the provision of key export infrastructure to capture coal mine methane (CMM), which includes pre-drainage of SIS gas, open cut mine operational emissions, ventilation air methane and goaf gas. Delivery of the infrastructure will not only result in delivery of a transition fuel resource identified by Australia’s then Chief Scientist, Alan Finkel, as essential in the transition to renewables energy sources, to pick up where batteries and pumped hydroelectricity run short as existing coal-fired power stations close, but also will reduce emissions from coal mines, which have a substantial greenhouse footprint through fugitive emissions, which represent 11-15% of Queensland’s total emissions – this said in the context of a continued need for metallurgical coal nationally and internationally.

Following exhaustion of the gas fields or cessation of extraction, the Bowen Basin Gas Pipeline infrastructure could be repurposed for the transport of hydrogen produced in inland locations to be exported or used for domestic power supply, including through repurposing coal-fired power station infrastructure in Gladstone to become hydrogen power plant. Hydrogen produced inland could utilise coal seam gas by-product water. Therefore, the infrastructure could support a whole lifecycle, beyond only natural gas and set Queensland up with infrastructure to support the transition to a net-zero emissions economy well into the future.

Program criteria

Responds to an issue or opportunity outlined in the regional transformation strategy

This criterion cannot be further expanded upon, noting that the regional transformation strategy has not yet been delivered.

Supports long-term employment growth and retention, through industry/business expansion, investment attraction or skills development

Y

See ‘Identifying opportunities for sustainable regional growth and economic diversification’ and ‘Enhancing economic, social and environmental liveability’ above.

Provides specific opportunities to diversify the economy

Y

See ‘Identifying opportunities for sustainable regional growth and economic diversification’ above.

Facilitates the establishment of new industries in the region

Y

See ‘Identifying opportunities for sustainable regional growth and economic diversification’ and ‘Supporting the transformation of regional communities to a low-emissions economy’ above.

Strengthens existing regional supply chains

Y

The project would result in new energy supply chains utilising either CSG and low-quality gas associated with its production or incidental mine gas that has been treated to suitable quality, although not necessarily pipeline specification gas.

The project will also support jobs across supply chains both during construction and operation, as has been the case in the Surat Basin. With the Glencore Oaky Creek Mine coming to a close at a time that will coincide with the development of the gas pipeline, there is the opportunity to accommodate construction workers and their families in the Tieri township to reduce any impediments to construction timeframes.

Develops business and industry capacity to operate in a low-emissions or more diversified economy

Y

See ‘Supporting the transformation of regional communities to a low-emissions economy’

Supports precinct development to assist in local investment, diversity or decarbonisation

N

Supports whole of basin development more broadly which will result in local investment, diversification and decarbonization as outlined above

Supports Aboriginal & Torres Strait Islander employment, skills development, business establishment or investment

Y

Aboriginal and Torres Strait Islander employment, skills development, business establishment and investment can be incentivized through design of the project, including as part of procurement design.

Identifies or leverages a region’s strengths by way of feasibility studies, business cases or targeted research

N

Project Justification

What is the need or demand for this (or problem the project is aiming to resolve)?

Domestic supply

The Bowen Basin Gas Pipeline Report produced by KPMG states that there is a confirmed need for the securing of additional domestic gas supplies to supplement demand by the mid-2020s, and the Bowen Basin is the prime candidate.

Forecasts consistently predict a shortfall of gas supplied in the ECGM by the mid-2020s, starting with peak demand periods (winter) and extending to net annual shortfalls. This will drive upwards pressure on domestic gas prices and downward pressure on consumption, and thus economic activity in gas-intensive industries.

As a result of the analysis undertaken as part of this KPMG study, there is a need for development of additional gas production capacity to supplement the predicted shortfall of gas in the ECGM.

Whilst other prospective basins exist and could also be developed to provide gas into the ECGM, the Bowen Basin is considered to be in a prime position to supply this shortfall due to the level of existing infrastructure, existing production and extensive exploration and appraisal activity.

Reducing greenhouse emissions

One of the most significant barriers to utilising pre-drainage coal mine gas is access to export pipelines, due to the typical lack of proximal export pipelines, and the lack of required gas infrastructure to meet pipeline quality and pressure requirements. New technology, such as membrane separation of methane to improve concentration and usable levels, has the potential to change the dynamics of CMM utilisation in the Basin. The analysis undertaken as part of the KPMG Study indicates that the limited existing infrastructure in the Central Region is not sufficient to cater for the expected demand and in light of the large gas reserves, a new pipeline connection is warranted.

Investment in the Bowen Basin Gas Pipeline and capture of CMM would result in a net positive reduction in emissions, noting that metallurgical coal mining will still be required over the medium to long-term depending upon the commercialisation of green steel technology and its compatibility with Australian iron ore.

The KPMG Study found that the reduction in emissions resulting from the capture and use of even a small portion of CMM far outweighs the cost of the additional new emissions from developing the basin’s CSG reserves.

Analysis undertaken as part of the KPMG study indicates that the development of the Basin is expected to generate total emissions below 10Mt CO2-et over the life of the project. Using this estimate, the 12Mt total emissions from the basin development (at the higher end of the estimate) would require only a 4% reduction in overall underground coal mine fugitive emissions to achieve emissions return on investment (4% of mid case >200Mt unabated underground coal mine emissions).

What are the objectives and proposed benefits of the Project?

(Consider labour market impact, emissions reduction, additional spend in region, social inclusion, liveability, local supply chain opportunities, business or industry capacity building, Aboriginal and Torres Strait Islander participation, support towards precinct development or further investment, etc.)

Developing the Bowen Basin Gas Pipeline and resources will be complex and challenging but has the opportunity to improve Queensland’s productivity, liveability and environmental sustainability.

As with the development of any gas basin, many challenges and opportunities are present. However the analysis undertaken as part of the KPMG study confirmed that there is a clear need for the securing of additional gas supplies and Queensland is in the optimal position to leverage that opportunity with the development of the Bowen Basin.

Economic, social and environmental benefits include:

New revenue stream to replace lower mining royalties in a post thermal coal world (and perhaps post metallurgical coal world, subject to the commercialization of green steel);

Secured supply of gas for domestic customers;

Stable and affordable energy prices – there is a strong relationship between economic growth and energy prices – other things being equal, high energy prices increase production costs and slow down economic growth

Providing certainty for industry to invest resulting in jobs and economic growth; and

Meaningful contribution to Queensland’s net zero targets by reducing fugitive gas emissions.

Development of the Bowen Basin will improve the prosperity of Queensland, most notably the regions and will stimulate further industrial development in larger centres such as Gladstone, Mackay and Townsville. The KPMG Study states that the project will:

“Enable the regions to invest in skills of the next generation of workers and provide opportunities along the supply chain”; and

“Future proof the regions”.

The project would unlock a new basin and economic opportunity, not only in CMM gas, but also beyond that as a basin for hydrogen production and therefore the project would secure long term jobs spanning across gas and renewable energy industries.

In addition, development of the project would ensure that the metallurgical coal mining sector, crucial to royalties, is able to abate emissions and continue economic output to benefit the Isaac and Central Highlands regions directly through employment and supply chains and the broader Queensland economy.

How will this project support economic transition? (Consider how the project will support project objectives including economic transformation into low emissions economy, diversification or long term sustainability)

The development of the Bowen Basin Gas Pipeline in accordance with the recommendation made within the KPMG Bowen Basin Concept Study will result in the provision of key export infrastructure to capture coal mine methane (CMM), which includes pre-drainage of SIS gas, open cut mine operational emissions, ventilation air methane and goaf gas. Delivery of the infrastructure will not only result in delivery of a transition fuel resource identified by Australia’s then Chief Scientist, Alan Finkel, as essential in the transition to renewables energy sources, to pick up where batteries and pumped hydroelectricity run short as existing coal-fired power stations close, but also will reduce emissions from coal mines, which have a substantial greenhouse footprint through fugitive emissions, which represent 11-15% of Queensland’s total emissions – this said in the context of a continued need for metallurgical coal nationally and internationally.

Following exhaustion of the gas fields or cessation of extraction, the Bowen Basin Gas Pipeline infrastructure could be repurposed for the transport of hydrogen produced in inland locations to be exported or used for domestic power supply, including through repurposing coal-fired power station infrastructure in Gladstone to become hydrogen power plant. Hydrogen produced inland could utilise coal seam gas by-product water. Therefore, the infrastructure could support a whole lifecycle, beyond only natural gas and set Queensland up with infrastructure to support the transition to a net-zero emissions economy well into the future.

How does this project align to Queensland and Local Government policy and strategies? (Where possible, cite specific objectives in government policy - e.g.: Queensland Energy and Jobs Plan)

The alignment of this project with various Federal, State and Local Government policies and strategies is extensively detailed at Appendix B of the KPMG Study which outlines the strategic fit of the project with:

Australian Government’s Gas-Fired Recovery

Unlocking the Northern Bowen: The Strategic Basin Plan

National Gas Infrastructure Plan: Interim Report

Our North, Our Future: 2021-26

ACCC’s Gas Inquiry 2017-2025 – 2021 Interim Report

Gas Pipeline Decision Regulation Impact Statement

Queensland’s COVID-19 Economic Recovery Plan

Queensland State Infrastructure Strategy

Queensland Climate Transition Strategy

Queensland Climate Action Plan

Queensland Renewable Energy Zones

Queensland Resources Industry Development Plan

Central and Western Queensland Regional Plan

Mackay, Isaac and Whitsunday Regional Plan

In addition, the project fits with the Queensland Energy and Jobs Plan actions to:

Invest to modernise Queensland’s coal-fired power stations for the future (Action 3.1): Invest in the future of power stations by reserving, repurposing and reinvesting, through the production of either blue hydrogen or gas transition fuels which utilise similar infrastructure and ultimately for the pipeline to be repurposed to transport hydrogen from inland Queensland in the proximity of the pipelines to Gladstone for use at the repurposed Gladstone Power Station;

Ensure reliability with low to no emissions gas (Action 1.5): The Queensland Energy and Jobs Plan expressly identifies an action to ‘work with industry to investigate options for connecting the Bowen Basin to the East Coast Gas market and options to secure additional gas storage for electricity needs’; and

Grow the future renewable hydrogen industry (Action 1.6): As noted above, gas pipelines developed under this project have the longer term potential to be converted for hydrogen use and development of the inland hydrogen industry within the Central Highlands and Isaac Regional Council local government areas.

The project also fits within the Central Highlands Regional Council Corporate Plan 2022-2027. The Central Highlands Regional Council Corporate Plan 2022-2027 includes a long-term destination goal to ‘protect and grow a diverse and prosperous economy’ – the Bowen Basin Gas Pipeline Project would deliver upon this long term destination goal.

Indicative number of jobs created or retained, including:

New direct jobs created (FTE)

New indirect jobs created (FTE)

Jobs retained (FTE)

Details of new regional skills developed/utilised

Details of where direct or indirect jobs are retained or created

Minister Scott Stewart in a media release titled ‘Queensland’s pipeline to more gas and jobs gains ground’ estimated “there would be potentially 1000 construction jobs available and countless opportunities in gas production and other industries which rely on affordable sources of gas”.

Project Cost and Funding

Total project cost ($) (Attach Project budget)

Funding requested of government ($)

N/A

Contribution from Proponent or other parties ($)

Unknown – to be negotiated with Federal Government and Private Sector

Delivery and Additional Information

Have you completed a risk assessment for the project? (Please attach) If not, please provide a summary of the key project risks/assumptions and detail how they are proposed to be mitigated?

Key risks are outlined on page 18 of the KPMG Study. Section 10 of the KPMG Study outlines key approvals pathways that need to be negotiated and resultant considerations/risks involved in same.

Which other parties will be impacted? Have they been consulted? What views and issues have they raised and how have these been addressed?

This is canvassed in section 10.3.5 of the KPMG Study.

Detail what additional information that can be provided if required.

Nil