3.1
Both the Australian Petroleum Production and Exploration Association (APPEA) and Dr Cameron Murray argued that one of the benefits of plentiful natural resources is a lower cost of that resource to domestic users. While this has generally held true for Western Australia (WA), it has not been the case for the eastern seaboard.
West coast gas
3.2
Gas prices in WA are less than half than that of the east coast as a consequence of the state's domestic gas reservation policy. This policy requires that export projects reserve 15 per cent of production for domestic use, complementing supply from projects developed solely for the domestic market. This results in prices for domestic consumers and industry below the netback price. Liquefied natural gas (LNG) producers favour gas exports over the domestic market and control around 97 per cent of WA's gas reserves (on and offshore).
3.3
Adjustments to the policy in 2020 clarified its application to preserve the integrity of the policy and the local gas market, including that: the government will not agree to the export of gas via the existing WA pipeline network (except under exceptional circumstances), supply to markets on the east coast is considered to be an export for the purposes of the policy, as is LNG used in international shipping.
3.4
With a relatively small domestic market, this small reservation has a large price effect, and flow-on benefits for the competitiveness of the manufacturing and mining sectors, which rely heavily on gas for commercial operations. The Ai Group noted that the WA gas reservation policy has been 'highly successful' and appears to have been no barrier to investment by the oil and gas sector.
3.5
In 2014 the WA Economic Regulation Authority recommended that the WA domestic gas reservation policy be rescinded, stating that 'there is no economic justification for the government intervention in the domestic gas market.' Moreover, it described the reservation policy as tax on the production of LNG, offering short-term price benefits but lowering returns, reducing investment and supply, and making gas less productive in the long run.
3.6
Often overlooked—there are two significant factors that work in conjunction to lower the price of gas in WA significantly below that of the eastern seaboard—a supply of gas well in excess of demand, and low-cost gas.
East coast gas
3.7
The east and west coast gas markets operate in isolation from each other. Several submitters observed that gas prices on the eastern seaboard had increased significantly since 2014–15, despite the fact that production has also increased. The eastern seaboard now has some of the world's most expensive gas, as illustrated in Figure 3.1.
3.8
A number of reviews have been undertaken into east coast gas pricing and supply as a result in efforts to reduce costs and improve supply, as discussed below.
Productivity Commission Review 2019
3.9
The Productivity Commission (PC) conducted a review of Australia's gas markets in 2015. It concluded that high east coast domestic gas prices are not a sign of market failure, but of the market working as intended. The PC submitted that the linking of the eastern Australian gas market to the Asia-Pacific market created an opportunity for companies to receive a higher return for domestically produced gas, and this resulted in broad community benefits from the generation of higher capital and labour income, and a higher flow of royalties and taxation revenue to governments.
ACCC gas price inquiry 2017–25
3.10
In April 2017, the government directed the Australian Competition and Consumer Commission (ACCC) to inquire into the supply and demand for wholesale gas in Australia and publish regular information on the supply and pricing of gas. The three-year inquiry has been extended until 2025.
3.11
In July 2019, the ACCC found delivered prices on the east coast for commercial and industrial users:
were lower (approximately $12.80/gigajoule (GJ)) than the delivered prices paid by commercial and industrial users in Asian countries that purchase Australian liquified natural gas (LNG) (South Korea and China). This reflects the costs involved in liquefying, shipping, re-gasifying, and transporting the gas to end users;
were higher than the prices paid by commercial and industrial gas users in other gas exporting countries. This reflects a tight supply and demand balance, weak competition, high gas production costs, high transmission prices, and close linkage to international LNG markets.
3.12
The Australian Bureau of Statistics (ABS) introduced a price index for wholesale natural gas in the domestic market in September 2019. The data is intended to reflect the domestic gas price received by producers through bilateral contracts and other pricing mechanisms. As well as its main role of supporting the compilation of national accounts, consultation feedback indicated that industry thought the price index would improve overall market transparency.
3.13
Analysis from the ACCC released in January 2020 showed that average margins for retailers for mass market customers were consistently high, between 19 and 23 per cent of the delivered price of gas at approximately $27/GJ. For commercial and industrial users, average margins grew to 28 per cent of the delivered gas price at approximately $12.80/GJ.
3.14
At the time, the ACCC made a number of findings with regard to the east coast gas market, including that prices had not fallen with the decline in the LNG netback price expectations for 2020; a more efficient and transparent transportation and storage network was required; there were significant and continued write-downs of proven and probable (2P) reserves and resources and increased reliance on more expensive speculative sources (i.e. coal seam gas (CSG)) for future supply, with most of the reserves in Queensland; and that the majority of these reserves were held by LNG producers and affiliates with potential interests in delaying development and delivery of gas to the market.
3.15
The ACCC supported the following actions:
adopting policies that consider the risks of individual gas development projects [i.e. not state-wide moratoria];
that the development of pipelines be coordinated by governments during the planning and approval process, and operated on a third-party access basis to prevent unnecessary duplication and inefficiencies; and
that governments should actively manage tenements to ensure producers bring gas to market in a timely manner to prevent larger producers 'warehousing gas'.
3.16
As a result of ongoing concerns about the degree of concentration in this part of the market and anti-competitive practices, the ACCC announced a review of upstream competition and the timeliness of supply in September 2021. Submissions closed in October; the results of the review are yet to be announced.
Box 3.1: Netback price
The netback price is used to estimate the minimum price an LNG producer needs to obtain to sell gas into the domestic market rather than selling it internationally. It is calculated by taking the price that could be received for LNG (the Asian LNG spot price) and subtracting (netting back) the costs incurred by the supplier to convert the gas to LNG and ship it to the destination port. The netback price is assumed to be the price a producer can sell the gas domestically and make the same profit it would if it sold it on the international market and is generally recognised as the most relevant export reference price for the domestic market.
The ACCC noted in 2021 that there can be large differences between expectations of prices for the various types of LNG sales depending on whether suppliers use the LNG spot (Japan Korea Marker or JKM) price, long-term LNG price or LNG 'strip' price, plus variations in how suppliers view opportunity or production costs.
2021 Updates
3.17
In January and July 2021 the ACCC released two further interim reports into gas pricing and supply. Over the year the ACCC found a growing disparity between east coast gas price offers and LNG netback prices, which did not align with its expectations for a well-functioning and competitive market and pointed to structural problems in the market.
3.18
The ACCC concluded that LNG netback prices are often viewed by suppliers as a price floor, with the upper limited of expected prices appearing to be influenced more by prices achieved in recent transactions and the perception of regulatory intervention, than pricing behaviour of competitors. This was confirmed in the ACCC July report.
3.19
In southern states the 'buyer alternative' price ceiling of LNG netback in Queensland plus transportation costs appears to have been a key driver of prices. However, the ACCC reported that some suppliers targeted prices even higher than this, with one major producer aiming to sell uncontracted gas 'at or above LNG parity pricing' (LNG netback plus transportation costs).
3.20
The review noted that suppliers continue to view Asian LNG spot prices as the opportunity cost of short-term domestic gas sales:
some LNG producers appear to have considered entering higher priced, short to medium term LNG contracts, influencing supplier pricing;
some LNG have considered long-term LNG contract prices when assessing domestic sales; and
oil prices appear to play an important role in domestic gas pricing, and several major suppliers appear to have forecast Asian LNG spot prices using oil.
3.21
Some suppliers have started to incorporate LNG import pricing and supply dynamics into pricing strategies and assumptions for southern markets. This may influence prices from 2022, when LNG imports are assumed to commence, but does not appear to have affected pricing prior to this.
3.22
The ACCC advised that prices offered by producers and retailers had dropped since 2020 as a result of low oil and LNG spot prices. This was largely due to existing market trends, the pandemic, lower global demand, and the resulting increased domestic supply. Prices offered by producers and retailers dropped from $8–14 per GJ in 2019 to $6–$8 per GJ in mid-2020, with prices remaining around this level, despite spot and LNG prices rising. Prices under Gas Supply Agreements also decreased significantly in 2020 and competition between suppliers improved, with favourable outcomes for commercial and industrial users. However, the ACCC expressed concern that prices offered to domestic gas users for supply in 2021 have generally remained above LNG netback prices.
Demand and export
3.23
The figures in Tables 3.1 and 3.2 outline the forecast supply and demand for the east coast gas market in 2021.
Table 3.1: Forecast supply for east coast gas market 2021
|
|
|
|
|
|
East coast gas production
|
1 956
|
98
|
38
|
|
Storage depletions
|
16
|
0.8
|
5
|
|
Northern Territory supply
|
19
|
1
|
1
|
|
Total
|
1 991
|
|
34
|
Source: ACCC
Table 3.2: Forecast demand for east coast gas market 2021
|
|
|
|
|
|
Domestic demand (residential, commercial)
|
454
|
23
|
9
|
|
Domestic demand (gas-fired power generation)
|
85
|
3
|
13
|
|
LNG (export)
|
1 401
|
72
|
31
|
|
Total
|
1 940
|
|
29
|
Source: Australian Energy Market Operator (AEMO)
3.24
The ACCC reported that the supply risks facing the gas market over the medium term have increased, although there is expected to be sufficient supply to meet domestic and export demand in 2021. In July 2021 the ACCC forecast that the demand outlook for 2022 'is the most finely balanced' it has seen across its previous reports with deteriorating conditions and forecast reduced supply. The Australian Energy Market Operator (AEMO) similarly forecast a decrease in southern supply.
3.25
The ACCC reported the risk of a gas shortfall in the southern states from 2022, with declining options to address the shortfall, unless:
more exploration and development occurs in the south, including into more speculative resources;
more investment occurs in north-south transportation infrastructure to allow greater volumes from Queensland and the Northern Territory to flow south; and/or
one or more LNG import terminals are developed.
3.26
Globally, Australia's Chief Economist expects demand for gas to rise, as do others, with growth forecast to recover after the impacts of COVID-19. However, given the large scale expansion of LNG capacity, import demand is expected to fall short of export supply capacity through to 2023. Low-cost producers, particularly in Qatar and Russia, are expected to significantly increase their export capacity beyond 2023, with a well- or even over-supplied market potentially reducing gas prices, affecting returns for higher cost producers, such as Australia.
3.27
On a positive note, the ACCC found potential new sources of gas and gas infrastructure which—while not yet approved—may address uncertainties in the longer term, although progress on securing supply was not as advanced as it had expected. The ACCC also observed that:
…many [commercial and industrial, or C&I] users have also expressed doubts that these projects will result in meaningful downward pressure on prices. Some users believe LNG import terminals may result in domestic customers permanently paying gas prices based on the amount international customers, without access to domestic gas reserves, are willing to pay. There is also concern that supply from LNG import terminals may expose C&I users to international currency and oil price risks.
Longer-term demand outlook
3.28
Uncertainty has been a factor in the market over recent years with the Commonwealth Scientific and Industrial Research Organisation (CSIRO) warning in 2017 that:
…the energy mix of the future is not predictable. Technological and regulatory uncertainty looms large in this equation. Rapidly falling costs of gridscale solar photovoltaics, energy storage technology (including batteries) and electric vehicles are likely to influence the future energy market. Future regulations in the area of GHG management could stimulate this shift … they have the potential to decrease demand for oil and gas …
… [A] rapid decarbonisation of the energy sector could completely undermine the ostensible role of gas as the bridge to a zero-carbon future—a potentially large risk for the Australian gas export industry. In the face of such uncertainty, the sector would be remiss to take a 'business as usual' approach.
3.29
The RBA also warned of uncertainty around the speed and manner of global transition towards net zero emissions and the impacts of renewable energy technology, possibly posing risks to Australia's oil and gas exports. Australia's commitment to net zero emissions by 2050 in late October 2021 is expected to accelerate changes, as illustrated by Figure 3.4
3.30
In 2020 the International Energy Agency (IEA) forecast a decline in gas demand by the world's advanced economies by 2040 for the first time, countered by a 30 per cent increase in global demand from South-East Asia. The IEA also noted that global demand would continue to rely heavily on policy support for gas—such as air quality regulations or restrictions on more polluting fuels—as well as significant investment in new gas infrastructure.
3.31
However, the IEA also noted considerable uncertainty in the market, with growth dependent on the policies of India and China, as well as China and Australia's trade relations, and cooling demand from Japan as a result of nuclear and renewable energy sources and emissions reductions targets.
3.32
The RBA noted that many of Australia's LNG customers—such as China, South Korea and Japan—have pledged to reduce greenhouse gas emissions to net zero by 2050 and that this and other international regulatory changes will influence demand for Australian gas exports and thus domestic prices in the longer term.
3.33
The central bank has also forecast that industrial gas demand, which accounts for the largest proportion of domestic gas use on the east coast, is unlikely to increase materially going forward. Demand for gas for gas-fired electricity generation is also being challenged by renewable energy and storage and shifts in investor and consumer preferences. Just six per cent of Australians rank gas as their preferred energy source, with 19 per cent ranking gas in their top three preferences.
3.34
There have been calls to fast track Australia's energy transformation, with the Business Council of Australia (BCA) recommending that Australia's decarbonisation commence with the electricity grid, as an enabler of decarbonisation across 'virtually all other sectors of our economy'.AEMO has reported on the growing electrification of energy sources in the transportation, commercial and industrial sectors, with growing investments in renewables, but further investments in electricity network integration and transmission needed.
3.35
Ai Group told the committee that it expects global gas demand to contract:
… the most plausible outcome of intensifying global efforts to fight climate change is a substantial long term contraction in global gas demand, making production-maximisation less attractive.
3.36
Mr Bruce Robertson from the Institute for Energy Economics and Financial Analysis (IEEFA) agreed, describing it in these terms:
… with climate commitments globally, we're beginning to see the collapse of the gas market and the LNG market internationally. 'Collapse' is not a word I use lightly, but that's what we're seeing … So Australia is not a low-cost producer, and we will struggle in this environment of declining demand and increasing competition from Qatar.
Is there a gas supply problem?
3.37
Some witnesses told the committee that there is without question a gas supply problem, however others claimed that the problems are due to poor government policy and wider market operation issues.
3.38
Chemistry Australia, in particular, drew attention to the implications of higher gas prices for the manufacturing industry, telling the committee that:
For more than a decade, domestic manufacturers have highlighted the lack of forethought given to the impacts of Australia exporting decades of gas reserves, balanced against its domestic requirements. These have resulted in a range of unintended consequences now being managed by manufacturers.
3.39
Meanwhile, the Australian Manufacturing Workers' Union (AMWU) put the east coast gas market problems firmly at the feed of poor policy:
The domestic gas market has demonstrably failed—the prices that are paid. The ACCC's most recent report is damning. There is a complete policy failure in the market conditions that surround the provision of gas and the distribution of gas on the eastern seaboard. There's no competition. It hasn't and doesn't work properly, and it continues to be a market failure.
Gas hoarding
3.40
Some large industrial gas users have suggested that retention lease arrangements have enabled operators to hoard gas. They have advocated for a 'use it or lose it' policy for leases, with leaseholders required to relinquish titles if production is not commenced.
3.41
However, the PC believes that gas companies are already incentivised to maximise their profits and extract gas reserves, and that that 'use it or lose it' mechanisms may not result in additional supply if costs are more than users are prepared to pay. This may see the gas directed to exports, and disincentivise investment in exploration activities.
3.42
Conversely, the United States Studies Centre draws attention to the Obama Administration 'use it or lose it' policies to boost oil and gas production:
The Responsible Federal Oil and Gas Lease Act, a bill brought before Congress in 2008, sought to strengthen the mechanisms in the US that incentivise efficient development of oil and gas reserves for the benefit of the public. Applying insights from the US experience with retention lease reform in Australia could facilitate increased competition in the market for developing national oil and gas reserves, provided such measures are applied in such a way as to minimise investment deterrence.
Lack of competition and supply
3.43
Some submissions cited insufficient competition between the major retailers—AGL, Energy Australia and Origin Energy—and overcharging by pipeline owners as the principal factors contributing to the high cost of gas. The ACCC concurred, concluding that lack of competition and overcharging by pipeline owners are factors in the high cost of gas, stating.
In our view, some of the LNG exporters have not clearly demonstrated compliance with the Heads of Agreement … while the Heads of Agreement does not expressly require prices to align with the ACCC's LNG netback price series, due to the magnitude of the difference, we are concerned that some offers appear not to have been made on 'competitive market terms.'
3.44
Supply is not the issue claimed the Australian Workers' Union (AWU), rather lack of transparency and 'cartel-like' behaviour are behind east coast gas market issues.
3.45
However, AGL Energy explained a number of issues affecting the supply of domestic gas including declining production in existing fields (in particular Victoria's Gippsland, Bass and Otway Basins), out dated gas pipeline contracts, insufficient pipeline capacity from Queensland, and practical inability to reverse the direction of gas flow using existing infrastructure. The ACCC and AGL advocated for increasing supply to the east coast market through the introduction of new market participants, increased production or gas import.
3.46
Mr Wolfgang Fischer submitted that additional exploration needs to occur to boost domestic gas volumes, with extensive opportunities still available and ready to be exploited, in particular by local, junior explorers who may be more ready to supply to a domestic market.
Linkage with international markets
3.47
Some submitters argued that issue linkage of the east coast gas market to international markets not supply, is the issue. Lock the Gate Alliance thought that high domestic gas prices were the result of three factors:
linking of the Australian market to the historically more expensive north Asian market and consequently world prices;
redirection of domestic gas resources overseas to fulfil long term supply contracts; and
cartel-type behaviour by gas companies.
3.48
DISER did not agree with this view, advising that the three LNG exporters do not supply the majority of the gas provided to the east coast gas market.
3.49
Submitters noted that while eastern Australia gas production had tripled since 2015, east coast domestic gas prices had also tripled over the same period. They argued for increased regulation rather than increased production, advising that any further increases in gas production will only result in more exports.
3.50
Mr Rod Sims, Chairman of the ACCC, was of the opinion that gas companies had mislead governments over the benefits of exporting gas:
So I think the gas industry as a whole certainly has to carry a lot of blame for the mess. And it is a mess that we are in; the companies that are closing down and [then] the trouble this is causing for Australian manufacturing and Australian jobs.
The gas companies assured governments that the local market would be fine, that prices wouldn't go up. And that turned out not to be the case.
3.51
The AWU believes that problems caused by gas exports were compounded by 'monumental public policy failure by regulators, domestic industry participants, and politicians of all persuasions' with the approval of multiple gas export projects.
Lower gas prices and more expensive production
3.52
Mr Robertson of the IEEFA argued that the decrease in global long-term gas prices had affected profit margins of the main gas producers in Australia and that increasing domestic gas prices is one way for them to offset these losses.
3.53
The IEEFA argued that the gas export market was premised on the production of cheap unconventional gas, but that this gas has ended up being more expensive than expected. It believes that gas exporters have retained the expensive gas for the domestic market and exported the cheaper sources of supply. Mr Robertson said that the gas lobby 'love talking about shortages because it gives them the excuse to artificially inflate the price of domestic gas' leaving consumers to effectively subsidise gas companies.
3.54
The ACCC and the Curtin University Sustainable Policy Institute also concluded that Australia has largely already developed its known low-cost gas field. The Institute noted that declining gas quality is also contributing to more expensive production and higher prices for consumers. It observed:
Already gas quality issues in particular higher embodied contents of inerts particularly CO₂ and N₂ contents are impacting on the design and efficiency of production facilities as well as environmental performance, which point to less return for proponents and higher prices for consumers.
The industry strategy is changing as they look to exploit smaller fields, indicating that new long-term supply will be more expensive and in more difficult locations and with poorer quality, or indeed not in Australia. The FLNG [floating liquefied natural gas] technology is a direct response to this trend to add flexibility for the industry.
Declining development and production
3.55
Wood Mackenzie observed that the era of large LNG projects in Australia appears to be over. Newer projects are not competitive with overseas projects, for example in Qatar and the US, and there are market uncertainties.
3.56
In 2019 the Department of Industry, Innovation and Science (DIIS) observed that oil and gas production was in decline. It thought that in the future there would be fewer integrated facilities, more incremental expansion of existing infrastructure, that projects would more likely feature back- and in-fill development, and that much of this development would be smaller, more isolated and/or more technically complex, resulting in lower efficiency, development delays and stranded fields.
3.57
Recent reporting by the Chief Economist appears to have borne out these concerns, at least on the NWS where production is expected to decline as gas fields are depleted, there have been delays in initiating backfill projects due to complex commercial arrangements and high capital costs, and investment decisions have been deferred due to weak LNG markets.
3.58
In 2020 decisions about the future of more than $80 billion of new LNG projects were put on hold as a result of uncertainties relating to climate change, COVID-19 and other emerging risks. Figures from March 2021 showed that quarterly spending on offshore petroleum exploration dropped 14 per cent to round one quarter of what it was in March 2015.