East Coast Gas Research Articles

Panel discussion: Staying the course – east coast gas market challenges and opportunities

There is not an abstract available for this discussion. To view the video, click the link on the right.

Gas markets – a bridge too far?

The energy market is becoming more globalised and renewables are changing the supply and demand balance. Gas has been suggested as the bridging fuel to the new energy world – but is it a bridge too far? This presentation examines the global gas context and its impact on the Australian east coast gas markets, trends in energy supply options and sign posts for new directions. When the first liquefied natural gas (LNG) train started on Curtis Island, the gas producers had access to more than just the domestic market. The new overseas markets are also interconnected, so the Henry Hub, Brent oil and Chinese gas demand all have an influence on Australia’s east coast gas market. Potential LNG import terminals and net back pricing are changing the domestic gas market. The energy market is moving to renewables. This is not just an anomaly that will correct itself, but is based on lower renewable costs and distribution challenges. Moving relatively small amounts of energy long distances is a major challenge for Australia. Infrastructure, market hubs and sourcing strategies need to compensate for these challenges, and investment is needed to keep pace with the changes. Capital is a global commodity seeking the optimum return for the risk, but unconventionals, such as coal seam gas, are capital hungry. Government policies and support can be the key determinant for not only new investment but sustaining investment to meet existing gas supply contracts. Smart gas buyers will need to be agile and use deeper portfolio approaches for gas supply.

Australia's unconventional future: where next?

Eastern Australia is now reliant on coal-seam gas (CSG) for its domestic gas supply; in 2018, it accounted for two-thirds of total eastern coast gas production. Australia has seen a rapid transition from relying on ‘conventional’ resources to relying on ‘unconventional’ gas supply. As legacy conventional supply sources mature and decline, exploration has been insufficient to keep up with market demand. This has created the opportunity for Australia’s vast CSG resources to fill the gap. But the development of CSG has been neither easy nor straightforward. And the costly requirement to drill hundreds, if not thousands, of wells in every single development has driven up the cost of supply. Most CSG reserves will be produced for the Pacific Basin LNG market via the three LNG projects on the east coast of Queensland. However, it is the resources beyond these LNG projects that will need to be developed, so as to ensure future supply to the east coast gas market. It is these other resources, both CSG and shale, that we evaluated to gain a picture of future gas supplies and costs. Our indicative economics showed that alternative CSG resources and Beetaloo shale both have high well-head break-even costs. In addition, the infrastructure required to get them to market will be expensive. The high costs, coupled with the demand from the LNG plants of Gladstone leads us to conclude that eastern-coast gas prices are likely to remain closely linked to global LNG prices for the foreseeable future.

Esso Australia’s long-term contribution to the east coast gas market

This year marks the golden jubilee of Australia’s offshore petroleum industry after the first gas was produced from Bass Strait by Esso and BHP’s Gippsland Basin Joint Venture. For half a century our industry has been driven by technology – pioneering technical excellence and pushing the envelope in the pursuit of much needed oil and gas production. Today, the landscape in East Australia is changing and gas is at the forefront of the discussion. Declines in East Australia’s historical conventional fields have seen gas supply tighten and prices rise. There is a strong need for additional affordable and reliable gas supply. While continued improvements in technology remain a critically important enabler in developing Australia’s gas resources; global supply and demand, regulatory frameworks, and the commercial arrangements that underpin new developments are becoming more and more important. ExxonMobil Australia’s new Chairman, Nathan Fay, has a wealth of experience working with gas markets around the world. He will explain why it is so important for policymakers to establishment a stable free market environment to encourage these long-term relationships. To view the video, click the link on the right.

Geological and bioregional assessments – enabling future tight, shale and deep coal gas development – Cooper Basin case study

The Australian Government’s Geological and Bioregional Assessment (GBA) Program is a series of independent scientific studies conducted by Geoscience Australia and CSIRO, supported by the Bureau of Meteorology and managed by the Department of the Environment and Energy. These studies focus on the Cooper, Isa and Beetaloo GBA regions, all of which include basins which are prospective, but under-explored, for shale, tight and/or deep coal gas. The GBA Program seeks to expedite development in order to bring new gas resources to the east coast gas market within the next 5–10 years through increased understanding of the potential environmental impacts posed by gas development and increasing the efficiency of assessment, monitoring and ongoing regulation, including improved data capture and reporting. This multi-agency program addresses the potential environmental impacts of gas development through geological and environmental baseline assessments and identification of major information gaps (Stage 2), followed by an analysis of the potential impacts on assets, including groundwater, surface water, environmental and cultural assets as well as Commonwealth and State matters of environmental significance (Stage 3). This paper will discuss how integrated conceptual models of the geology and hydrogeology of selected unconventional petroleum resources can be utilised by industry, regulators and other stakeholders. By establishing a baseline assessment for the Cooper Basin, which includes an integrated shale, tight and deep coal prospectivity and groundwater study, future development scenarios can be envisaged and the potential impact on groundwater and other resources contemplated. Similar baseline assessments and conceptual models are being developed for the Isa and Beetaloo GBA regions.

A paradox of plenty: the Australian domestic gas supply regulatory dilemma

Energy security is a multi-faceted policy conception heralding from traditional principles focused on security of supply. Onshore conventional and unconventional gas has played an integral role in Australia’s energy security since its commercial production commenced in the Cooper Basin Region in 1969. However, since 2015, the staggering increase in Liquefied Natural Gas (LNG) exports, earning Australia its title as the second-largest global LNG exporter, has heightened competition for gas supply in the Australian East Coast Gas Market (ECGM). This article examines whether the Australian Domestic Supply Mechanism (ADGSM), in imposing controls on LNG exports, marks a shift in regulation and policy by fostering gas security for the ECGM. This article advances the argument that the ADGSM enacted in 2017 is an initial temporary and short-term step in seeking to avert a domestic gas shortfall. Further, it is argued a market-based approach to gas regulation will not achieve domestic gas security for Australia without additional regulatory measures and infrastructure investment.

The feasibility of cost-effective gas through network interconnectivity: Possibility or pipe dream?

Australia's east coast gas market has faced transformational shifts in demand with the commencement of three Liquefied Natural Gas facilities in Queensland. Faced with risks of high domestic prices and potential gas shortages, political intervention has been considered as a possible solution. This paper investigates the impact of network interconnectivity on domestic gas prices by employing a long-term planning model underpinned by mathematical optimisation. At optimal system cost, improved network interconnectivity can provide material and sustained price reductions for the gas market with potential flow-on reductions to the electricity market. Increased connectivity is shown to deliver reductions of over $2/GJ in average gas prices across the eastern seaboard, with a subsequent reduction in electricity prices across all mainland National Electricity Market (NEM) regions. The results also highlight the need to unlock new supply as new transmission projects, though having the potential to reduce gas prices through market connectivity, rely on adequate supply to meet long term demand, and sustain market balance.

East-coast Australian gas markets—Overcoming the lumpiness of capital allocation and temporal instability

Australia’s east-coast gas market has undergone significant transformation in the past decade. The discovery of non-conventional coal-seam gas reserves led to investment in three ‘lumpy’ LNG export facilities in Gladstone, Queensland. Drilling activity has subsequently slowed, a direct result of a soft global price for LNG. This slowdown, in an environment of a tripling of east-coast gas demand, has resulted in concerns about domestic gas shortages. To be clear, there is no lack of gas resources. Instead, the problem relates to the relative lumpiness of capital allocation and temporal instability driven by changing global circumstances. Utilising a simple partial equilibrium model, various options for overcoming these problems are analysed. Of these options, developing import infrastructure appears to be a ‘no regrets’ option that would ensure that the price floor, the LNG netback price, also becomes the market price cap.

Earning community trust to operate – Northern Gas Pipeline

The Northern Gas Pipeline (NGP), is a 622-km gas pipeline in outback Australia that will connect gas reserves in the Northern Territory to the east coast gas market. With the current east coast gas crisis and continuing pressure to reduce coal-fired base load power, this project creates a new market to deliver additional gas to the east coast. The project includes the construction of the pipeline and two compressor station facilities at the start and end of the line: the Phillip Creek Compressor Station, which includes gas processing infrastructure, and the Mount Isa Compressor Station. The AU$800 million project began in November 2015 and first gas is scheduled to flow in late 2018. The bid to contract the pipeline included a range of local and Indigenous commitments that would maximise local participation in the project, ensuring that the social licence to achieve land access and government approvals was realised while keeping to a very aggressive timetable. Jemena worked closely with local businesses, communities and Traditional Owners to provide training and development opportunities, employment and other social support services. This approach has meant that the project is on track to deliver this nationally significant gas pipeline under budget, ahead of the contractual schedule requirement, while meeting or exceeding all local obligations and commitments.

The east coast gas market explained: analysis of the gas market supply and demand dynamics

The Australian east coast gas market is experiencing arguably the most disruptive structural change since its inception, with the completion of the 25.4 mtpa Curtis Island Liquefied Natural Gas (LNG) facilities and the introduction of a fourth pillar to the market for domestic gas. However, this disruption was not in isolation and coincided with substitutional interactions with the electricity market already dealing with transition. This report develops context for the natural gas market, establishes the four major avenues of markets and then investigates eight fundamental supply and demand dynamics that are influencing the market in an interconnected fashion. The report concludes that all participants of the gas market must address the multiple dynamic drivers including economic consideration, government policy and regulatory engagement to avoid disorderly market transition.

Evolution of the east coast gas market

This extended abstract reviews how the east coast gas market is managing the major transition from being a ring-fenced domestic market to being part of an interconnected global trading market, and what still needs to be done to rebalance after half a decade of disruption. The east coast gas market has a great future ahead of it, but only if Australia acts quickly to open up access to new gas supply sources as existing gas fields mature and decline. The presence of a global liquefied natural gas (LNG) supply market on the east coast now provides an incentive for gas producers to invest in new provinces and new plays at a scale the domestic gas market could not have supported on its own. This can only be good for competition in the east coast gas market over the medium to long term, and potentially open up enormous supplies for the growth of Australian industry, akin to the US shale gas revolution. To make the most of the resources and infrastructure we now have on the eastern seaboard, there is a role for governments to play in ensuring access to resources and providing stable, coordinated, robust energy policy and regulatory frameworks that attract investment in further growth in the gas sector, the benefits of which will flow on to Australian industry more generally.

An overview of the new Geological and Bioregional Assessments Program

As part of the AU$86.3 million ‘Towards a New Energy Future’ package, the Australian Government has committed AU$30.4 million to undertake the Geological and Bioregional Assessments Program. This program aims to encourage sustainable gas development through a series independent scientific studies into the potential environmental impacts of shale and tight gas exploration and production. These studies, conducted by Geoscience Australia and CSIRO, supported by the Bureau of Meteorology and managed by the Department of the Environment and Energy, will focus on three basins (regions) that are prospective, but underexplored for shale and tight gas. The program seeks to encourage exploration to bring new gas resources to the East Coast Gas Market within the next 5–10 years, increase the understanding of the potential environmental impacts posed by gas developments and increase the efficiency of assessment, monitoring and ongoing regulation, including improved data capture and reporting. The Cooper Basin and the Isa Superbasin have been selected for investigation with a third basin expected to be announced by mid-2018. The program will be delivered in three stages over 4 years and will investigate areas prospective for shale and tight gas within these regions. This independent, transparent, science-based approach aims to assist in building community understanding of, and confidence in, the capacity for safe and environmentally sustainable unconventional gas developments.

Production and development across Australia 2016

In 2016, sustained depressed and volatile oil prices led companies to continue cost reduction strategies. Proposed developments have seen delays and reductions in scope as a result. Australian oil production declined by around 10%. However, new and continued liquefied natural gas (LNG) production bolstered both Australian and global gas supply. Australia was the strongest contributor to global LNG growth in 2016, showing the biggest year-on-year increase. In the first half of 2016, 20% of global LNG came from Australia, second only to Qatar with 29% of the market share. Australia remains on track to become the world’s largest LNG producer in the next 3–5 years. 2016 saw the start-up of Gorgon LNG in March, the first of Chevron’s two North West Shelf LNG projects and the third of several producing, developing and proposed LNG projects within the North Carnarvon Basin – already Australia’s most prolific producing basin. On the east coast, development of the coalbed methane (CBM) to LNG projects continued with an additional train brought onstream at each of the Origin/ConocoPhillips-operated APLNG Project and Santos’ GLNG Project. This further increased production in the Bowen–Surat Basins and drove discussions around the ability of east coast gas to meet both the demands of the LNG projects and ensure continued domestic gas reliability. Additional gas may be required for both, opening opportunities for production from other basins. Gas production continues to drive the Australian industry, with substantial inputs from LNG and unconventional operations. The next phase, in all sectors, will be key to Australia’s future in the global energy market. Will it be able to overcome the expected challenges of global oversupply, continued price volatility and domestic reliability concerns to fulfil its potential?

Jemena's perspective on Australian gas market dynamics: a vision of a fiercely competitive market facilitated by an interconnected supply chain

As pipeliners, we take a long-term view of the transformative opportunities facing the Australian gas industry. We believe a market-driven approach will overcome the current challenges around gas price volatility and supply constraints by further developing the missing links that will enable genuine connectedness, greater flexibility and operating synergies across a national gas transportation grid – one that can deliver gas where it is needed most and at the right price. Looking at mature gas trading environments like the USA provides some aspirational direction in terms of the fluidity of the gas trading environment, where pricing is more dynamic. However, the past and present development opportunities within our own backyard also provide valuable insight. Building the Eastern Gas Pipeline transformed the east coast gas market by introducing a competitive alternative for gas transportation into Sydney and upstream competition between basins. A similar market-led opportunity exists today to build infrastructure connecting Northern Territory gas producers to east coast markets – introducing a competitive alternative for gas transportation and upstream competition between the Beetaloo/McArthur basins and the Surat/Bowen basins. Winning the right to build the Northern Gas Pipeline was an important first step in Jemena realising this vision. Current regulatory discussions would not be relevant if the industry can shape its own market. Jemena’s northern Australia growth strategy could be the catalyst to resolving these challenges and avoiding further gas constraints or Australian Competition and Consumer Commission interventions seeking to address theoretical issues, rather than solving actual market challenges.

The Australian east coast gas supply cliff

On Australia’s east coast over the period 2013–2016, we forecast that aggregate demand for natural gas will increase three-fold, from 700 PJ to 2100 PJ per annum, while our forecast of system coincident peak demand increases 2.4 times, from 2790 TJ to 6690 TJ per day. This extraordinary growth is being driven by the development of three Liquefied Natural Gas plants at Gladstone, Queensland. In this article, we present our dynamic partial equilibrium model of the interconnected gas system and produce forecasts with daily resolution. We find that absent additional supply-side development, unserved load events will remain more than a theoretical possibility in the short-term due to inter-temporal spatial constraints. In the long-term, with appropriate policy settings in place, additional supplies will be brought to market, albeit at higher than historical prices.

Unconventional gas prospectivity of the Cooper Basin

The Cooper Basin is an Upper Carboniferous–Middle Triassic intracratonic basin in northeast SA and southwest Queensland. The basin is Australia's premier onshore hydrocarbon-producing province and is nationally significant due to its provision of domestic gas for the east coast gas market. Exploration activity in the region has recently expanded with numerous explorers pursuing newly identified unconventional hydrocarbon plays. While conventional gas and oil prospects can usually be identified by 3D seismic, the definition and extent of the undiscovered unconventional gas resources in the basin remain poorly understood. This extended abstract reviews the hydrocarbon prospectivity of the Cooper Basin with a focus on unconventional gas resources. Regional basin architecture, characterised through source rock distribution and quality, demonstrates the abundance of viable source rocks across the basin. Petroleum system modelling, incorporating new compositional kinetics, source quality and total organic carbon (TOC) map, highlight the variability in burial, thermal and hydrocarbon generation histories between depocentres. The study documents the extent of a number of unconventional gas play types, including the extensive basin-centred and tight gas accumulations in the Gidgealpa Group, deep-dry coal gas associated with the Patchawarra and Toolachee formations, as well as the less extensive shale gas plays in the Murteree and Roseneath shales.

2014 PESA production and development review

2014 was the penultimate year for many of the massive multi-year LNG development projects. These projects will lift Australia’s LNG capacity by more than 250% from present levels. The first train of the Queensland Curtis LNG project came on-line in late 2014. Exports are expected to commence from a further three LNG projects (APLNG, Gladstone LNG and Gorgon) in 2015. The ramp-up in gas demand on the east coast of Australia is spurring secondary development. A pipeline link has been proposed from the NT’s gas transmission system to connect to the east coast gas transmission system to allow gas from the Timor Sea to be fed into the east coast market and to the Queensland LNG projects. 2014 was a quiet year for new oil developments. Offshore, the Balnaves FPSO development was brought on-line. Onshore, the operators of the Cooper western flank continued to discover and develop a series of small fields. These small developments and better performance from some existing fields were able to offset natural reservoir decline elsewhere, leading to an overall increase in crude oil production of approximately 4% from the previous year. The second half of 2014 was characterised by a decline in crude oil price from more than $100/BBL to under $60/BBL by year-end. For many LNG contracts, LNG price is linked to oil price; existing LNG developments are well progressed and are unlikely to be curtailed by the low commodity price, but future developments are already being slowed or stopped.

Building liquidity and transparency in the Australian east coast gas and global LNG markets

The Australian natural gas market is undergoing a dramatic change. Queensland will start LNG production and exports at the end of this year, and this is already having an effect on the east coast’s domestic gas market. LNG ramp-up gas supplies are now exerting downwards pressure on forward prices in Queensland and to some extent in other east Australian states. LNG plant operators are ramping-up well drilling and production to ensure the smooth processing of gas feedstock for liquefaction. But the availability of this gas for the domestic market will start to fall when the first LNG plant comes on line at the end of 2014. The Argus Wallumbilla index (AWX), for month-ahead gas delivery in southeast Queensland, usefully illustrates the changing dynamics of the Australian east coast gas market and provides the industry a transparent reference point on which to base a transaction. This extended abstract provides expert insights into the interplay between the Australian LNG export and east coast domestic gas markets, as well as the pricing implications and outlook for the global LNG markets. It also aims to answer the following questions: How will liquidity develop in the Australian east coast domestic spot gas market? How will the east coast LNG spot supply picture evolve? What are the key drivers in the global LNG spot markets? How will Henry Hub pricing impact Australian LNG pricing?

Pricing prospects for global LNG and Australian gas markets

Global LNG pricing outlook Liquidity in the global LNG spot market is increasing and the industry is seeking price diversification in its supply contracts. The rationale for oil linkage is being challenged. Short-term trade now accounts for a quarter of the total market, and the US’ Henry Hub, the UK’s NBP, and global LNG spot indices are all used in LNG price indexation. Growth in LNG supplies, short-term trade, and operational flexibility will drive global price connectivity and increase transparency. The US will begin exporting LNG, tightening the price differential between Atlantic and Pacific basins. The LNG industry will continue to question the validity of oil-price linkage as it seeks a reliable reference capable of reflecting supply and demand fundamentals in the gas markets themselves. It is, however, important to recognise that gas-to-gas pricing will not automatically deliver cheaper LNG than equivalent oil-index formulas. East coast Australia gas pricing outlook Dynamics in Australian east coast gas markets are changing rapidly, with LNG at the heart of this revolution. The east coast gas industry seeks a deeper, more liquid and transparent market, while looking to international gas hubs for lessons in boosting market efficiency. The industry must address challenges such as gas storage and pipeline capacity if it is to have the flexibility needed to build a vibrant market. Oil-indexed LNG netback pricing is starting to work its way into east coast gas supply contracts; however, as the European gas industry moves away from oil indexation, Australia’s domestic gas market needs to look at alternative pricing structures.