Gas, energy security and the interventions

Steve runs the furnace his grandfather lit. His family's glass-container plant in Melbourne's west has kept a bank of gas-fired melting furnaces burning at close to 1,500 degrees, without a break, for three generations, because a glass furnace cannot simply be switched off: let it cool and the refractory brick cracks, the molten glass inside solidifies around it, and the furnace is finished, a write-off worth tens of millions of dollars to rebuild. Gas is not an input Steve can substitute at short notice; it is the plant's lifeblood. In the second half of 2022, when he rang around for a supply contract to cover 2023, the quotes that came back were roughly triple what he had paid two years earlier, if suppliers would quote a multi-year term at all (approx.). For a business that runs on thin margins against imported glass, a bill increase of that size was not a cost to pass on. It was the difference between keeping the furnace lit and writing it off. Steve is not against gas policy or climate policy in the abstract. He wanted one thing from Canberra in that moment: a signal that the market was not simply going to price him out of his own factory.

What happened next is the subject of this article. In December 2022 the Commonwealth, acting with the states through National Cabinet, imposed an emergency 12-month price cap on uncontracted east-coast gas and set in train a permanent mandatory code of conduct for the industry. The cap, and the code that followed it, are widely credited with helping keep businesses like Steve's afloat through the worst of the 2022 energy shock. But the same instruments that shielded him also landed in the middle of a separate, slower-moving problem: the east-coast gas market's own regulator and operator had already begun warning that the southern states were running short of new supply for the rest of this decade, and that new supply depends on exactly the kind of investment a government-imposed price ceiling is designed to discourage. Whether Canberra's emergency medicine for 2022 undermined the patient's long-term prognosis is the question this article sets out to answer.

What the government did

Russia's invasion of Ukraine in February 2022 triggered the most severe global energy price shock in decades, as European buyers scrambled to replace Russian pipeline gas with liquefied natural gas (LNG) cargoes from anywhere they could find them, bidding up the global LNG price on which Australia's east-coast gas market had become directly exposed since Queensland's LNG export terminals began shipping in 2015–16. Before that link to the export market existed, east-coast wholesale gas had traded for years at a domestic price largely disconnected from world markets, commonly cited in the low single digits of dollars per gigajoule (a gigajoule, GJ, is the standard unit gas is bought and sold in; a typical Australian household uses roughly 15–20 GJ a year for heating, hot water and cooking) (approx.) (AEMC, Gas Market Reform review documents). Once the Queensland LNG plants began drawing on the same gas fields to fill export contracts, any buyer in Melbourne, Sydney or Adelaide was effectively bidding against a shipload bound for Japan or South Korea, and east-coast prices settled into a higher, LNG-linked range of roughly $8 to $11 a gigajoule through most of the second half of the 2010s (approx.) (ACCC, Gas Inquiry 2017–2030, interim reports).

The 2022 shock pushed that price band well beyond anything the east-coast market had experienced. Short-term wholesale gas prices at several trading hubs spiked above $30 a gigajoule at points during 2022, and some buyers seeking new supply contracts reported offers higher still, roughly three to four times the price ruling only a year or two earlier (approx.) (ACCC, Gas Inquiry 2017–2030, interim report, 2022). Electricity, which in the National Electricity Market is frequently priced off the cost of the last, most expensive generator dispatched — often a gas peaking plant — was dragged up in tandem. The strain became so severe that the Australian Energy Market Operator (AEMO) took the unprecedented step of suspending trading in the National Electricity Market spot market altogether for several days in June 2022, the first suspension in the market's history, after concluding it could no longer be operated safely within its normal price and reliability settings (AEMO, statement on suspension of the National Electricity Market, Jun-2022). That single fact is the clearest evidence available that 2022 was not an ordinary bad year for energy prices; it was, on the market operator's own assessment, a genuine emergency.

Governments moved accordingly. On 9 December 2022, National Cabinet — the Commonwealth and the states and territories meeting together — agreed an Energy Price Relief Plan, and the federal Parliament passed the enabling legislation within the same fortnight, in a rare recalled sitting before Christmas (National Cabinet, Statement on the National Energy Emergency Response, Dec-2022; Treasury Laws Amendment (Energy Price Relief Plan) Act 2022, Cth). The plan had three main gas-market elements. First, a temporary price cap of $12 a gigajoule on new sales of uncontracted gas on the east coast, running for twelve months from the legislation's commencement — existing supply contracts already in place were grandfathered and left untouched, so the cap bound only gas that had not yet been sold under a new agreement (Treasury Laws Amendment (Energy Price Relief Plan) Act 2022, Cth). Second, a commitment to develop a permanent mandatory Gas Market Code of conduct, to be designed with the industry and enforced by the Australian Competition and Consumer Commission (ACCC), built around a "reasonable pricing" provision intended to prevent prices returning to 2022 extremes once the temporary cap expired (Treasury Laws Amendment (Energy Price Relief Plan) Act 2022, Cth; ACCC, Gas Market Code guidance material). Third, an Energy Bill Relief Fund, worth roughly $1.5 billion in Commonwealth funding and matched by the states, delivering direct electricity bill rebates to households and eligible small businesses rather than intervening in the gas price itself (approx.) (Australian Government, Budget Paper No. 2, Oct-2022 Budget). A parallel measure capped the price of thermal coal sold into New South Wales and Queensland power stations at $125 a tonne, addressing the electricity side of the same shock, though that is a companion story to the one told here (Treasury Laws Amendment (Energy Price Relief Plan) Act 2022, Cth).

The mandatory Gas Market Code came into effect from mid-2023, once the temporary $12 cap's twelve-month term was drawing to a close, and it did not simply expire the intervention (ACCC, Gas Market Code guidance material, 2023). Instead, the code created a standing, ACCC-enforced "reasonable pricing" obligation on east-coast gas producers, backed by a compulsory arbitration process suppliers and buyers can use if they cannot agree a price, with the $12 figure continuing to function as a de facto reference point for what regulators would treat as reasonable, while allowing higher prices where a producer could show its costs genuinely justified them (ACCC, Gas Market Code guidance material, 2023; approx.). In practice, an emergency measure legislated to last twelve months became the platform for an ongoing regulatory regime with no fixed end date — a detail that matters enormously for how investors read the government's intentions, and one this article returns to.

None of this was the government's first lever over the gas market. Since 2017, the Australian Domestic Gas Security Mechanism (ADGSM) has given the Commonwealth power to restrict LNG exporters' shipments if the resources minister forecasts a domestic shortfall, a tool introduced by the Turnbull government after an earlier east-coast supply scare and kept in force, with periodic renewal, ever since (Department of Industry, Science and Resources, Australian Domestic Gas Security Mechanism, various years). The ADGSM works on volume, not price: it is a background threat used mainly to extract voluntary supply commitments from the three big Queensland LNG export ventures, and successive governments have preferred negotiating under its shadow to actually triggering it. The 2022 price cap and mandatory code went well beyond anything the ADGSM had done, moving from a volume-based lever aimed at the export terminals to direct price regulation of the domestic market itself. That is a materially larger intervention, and the scale of the step is worth registering before weighing its effects.

The evidence: what the intervention did to prices, and what the regulators say about supply

The clearest, least contested part of the record is that wholesale east-coast gas prices did fall from their 2022 peaks over the following two years. By 2023 and into 2024, short-term trading market prices at the major hubs had retreated well below the $30-plus levels seen at the height of the crisis, generally trading closer to, and at times below, the $12 reference point associated with the cap and code, before firming somewhat through 2024 as the market absorbed rising demand for gas-fired electricity generation during the renewables transition (approx.) (ACCC, Gas Inquiry 2017–2030, interim reports, 2023–24). The honest caveat, and one the ACCC's own reporting has been careful to make, is that the fall cannot be attributed to the Australian intervention alone. Global LNG prices also eased substantially through 2023, as a mild European winter, aggressive gas-storage refilling and demand destruction across European industry reduced the bidding pressure that had driven the 2022 spike in the first place (approx.) (ACCC, Gas Inquiry 2017–2030, interim report, 2023). Untangling how much of the east-coast price relief came from Canberra's cap and code, and how much would have happened anyway as the global shock passed, is not something the public record allows anyone to state with precision, and a fair audit says so plainly rather than crediting the intervention with the whole of the improvement.

The harder, more contested part of the record concerns what the intervention did, or may still be doing, to the investment that new gas supply depends on. Every barrel of new east-coast gas supply — a new well drilled into an existing field, a new field brought into production, additional pipeline capacity built to move gas from the north to the southern states that need it — starts with a company deciding the expected price it will receive justifies the capital it must commit, often years before the gas actually flows. A price cap, even one framed as temporary and even one that formally exempts existing contracts, changes that calculation for any project not yet locked in, because it tells a prospective investor that the price ceiling it is planning around today can be reset by government decree tomorrow if prices rise again. The gas industry's peak body — the Australian Petroleum Production and Exploration Association, which rebranded as Australian Energy Producers in 2023 — argued exactly this in submissions during the code's design, describing the intervention as a serious dent to the "sovereign risk" premium investors attach to committing capital in Australia, and warning that a government prepared to cap prices once, in a genuine emergency, could plausibly be prepared to do it again the next time prices rose sharply (Australian Energy Producers, public submissions on the Gas Market Code, 2023; industry-source, cited for the investment-signal argument specifically).

A price cap that only binds gas nobody has yet agreed to sell is, by its own design, a message about the future — and the future is exactly where the supply warnings say Australia is short.

That investment question landed on top of separate, pre-existing warnings from the market's own regulator and operator about a looming east-coast supply gap that long pre-date the 2022 crisis and the government's response to it. The ACCC's Gas Inquiry 2017–2030, a standing monitoring inquiry that reports roughly twice a year, and AEMO's annual Gas Statement of Opportunities (GSOO) have, across a run of consecutive editions through the early-to-mid 2020s, forecast a developing supply shortfall concentrated in the southern states — Victoria, New South Wales, South Australia and Tasmania — as the Gippsland Basin fields under Bass Strait, the traditional backbone of southern gas supply for half a century, decline faster than new southern supply or additional northern pipeline capacity is being brought on to replace them (AEMO, Gas Statement of Opportunities, 2023 and 2024 editions; ACCC, Gas Inquiry 2017–2030, interim reports, 2023–24). AEMO's modelling has repeatedly flagged the risk of a shortfall opening from around the second half of this decade onward on a business-as-usual investment trajectory, worsening in cold winters when gas demand for both heating and gas-fired electricity generation peaks together (approx.) (AEMO, Gas Statement of Opportunities, 2024 edition). Both bodies have said, in careful regulatory language, that closing the projected gap depends on new investment arriving roughly on schedule — new wells in existing basins, new fields such as those under appraisal in the Otway and Beetaloo basins and in the Narrabri region of New South Wales, and expanded pipeline capacity to move northern gas south — and that delay compounds the risk rather than merely deferring it (AEMO, Gas Statement of Opportunities, 2023–24 editions).

It is worth being precise about what these warnings do and do not say. Neither AEMO nor the ACCC has said the east coast is running out of gas in the ground; the resource base in existing and prospective basins is not, on current geological assessments, the binding constraint (Geoscience Australia and AEMO, resource assessments, various). The constraint both bodies describe is a supply-development one: getting new gas out of known and prospective fields, and moving it to where it is needed, on a timeline that matches when the Gippsland fields decline. That distinction matters because it is precisely the kind of constraint that responds, for better or worse, to the price and regulatory signals a government controls, unlike a genuine physical resource shortage that no amount of favourable policy could fix. The commercial reality behind the warnings is that final investment decisions on new east-coast gas developments have been comparatively scarce since 2022, with several producers publicly citing a mix of state planning and environmental approval delays — the long-running New South Wales approval process for the Narrabri gas project among the most cited examples — alongside the changed pricing and regulatory environment created by the cap and code, as reasons for caution about committing new capital to east-coast-only supply (approx.) (Australian Energy Producers, public statements and submissions, 2023–24; state planning authority decisions, 2022–24). Separating how much of that caution is attributable to the price intervention specifically, as against planning delays, community opposition and the industry's own capital discipline after a volatile few years, is not something this record allows anyone to state with false precision — but the ACCC's own interim reporting has repeatedly identified "sovereign risk" and pricing uncertainty as factors industry participants raise when explaining subdued investment, alongside the more familiar planning and approval constraints (ACCC, Gas Inquiry 2017–2030, interim report, 2023–24).

The scarcity of new supply commitments has also revived a long-running debate about mandatory gas reservation, of the kind Western Australia has run since 2006, requiring LNG exporters there to set aside a share of production for the domestic market. East-coast producers and their export ventures have resisted a reservation mandate on the east coast, arguing existing supply contracts already channel gas to domestic buyers without a blunt volume rule, while some manufacturers and unions have pushed the government to adopt one, pointing to Western Australia's comparatively lower and more stable domestic gas prices as evidence a reservation policy need not collapse investment (approx.) (industry and manufacturing-sector submissions, various, 2022–24). The government has so far preferred the price-and-code approach over a Western Australian-style reservation mandate, a choice that leaves it exposed to the investment-signal risk this article documents, without the volume guarantee a reservation policy would provide.

The Future Gas Strategy: the government answering its own question

The clearest evidence that the government itself came to see a coherence problem is its own subsequent policy. In May 2024, the Department of Climate Change, Energy, the Environment and Water released Australia's Future Gas Strategy, a document explicitly designed to give the industry a considered, long-term signal after nearly two years of emergency intervention (DCCEEW, Future Gas Strategy, May-2024). The strategy states plainly that new gas supply investment, including new fields, will be needed for domestic use — for manufacturing, for gas-fired electricity generation used to firm an increasingly renewable grid, and for households — out to 2050 and beyond, even as the broader economy decarbonises (DCCEEW, Future Gas Strategy, May-2024). A government does not commission and publish a strategy stating gas investment must continue for another quarter of a century unless it has concluded, at some level, that the investment was not otherwise assured to arrive on the timetable the reliability warnings say is needed. The Future Gas Strategy is, in effect, Canberra's own admission that the price and regulatory settings coming out of the 2022 emergency needed a second document to reassure the investment the first set of measures had made harder to commit to.

The critique: two tools built for different jobs, run through the same intervention

The central coherence problem is a mismatch between the timeframe the household-protection tool was built for and the timeframe the reliability problem actually runs on. The 2022 price cap and the code that followed it were designed, sensibly, to answer an emergency: get prices down for households and manufacturers now, before businesses like Steve's glass plant close and before winter bills push vulnerable households into hardship. AEMO's and the ACCC's supply warnings describe a different problem on a different clock: whether enough new gas will have been found, appraised, approved and connected by the back half of this decade to meet demand as old fields decline. Those two problems interact, because the tool built for the first one — a price ceiling, however carefully designed with grandfathering and a cost-reflective floor — inevitably touches the return calculation behind the second one. A government cannot fully solve "prices are too high right now" without at least partly touching "will new supply be worth developing later," because in a market-based gas industry, price is the signal that does both jobs at once.

The specific design choices compound rather than resolve that tension. Grandfathering existing contracts protected supply already locked in, which was the right call for minimising disruption to sunk investment, but it did nothing to improve the return calculation for the new supply the GSOO says the southern states are short of — new supply is, by definition, uncontracted, which means it is exactly the gas the cap and the code's reasonable-pricing provision bind. And the conversion of a legislated 12-month emergency measure into a standing, ACCC-enforced code with no announced end date extends the period over which investors must price in the risk of intervention, arguably for longer than the original emergency justified. A measure explicitly sold to Parliament as temporary, in December 2022, having effectively continued in a different legal form through 2023, 2024 and into 2025, sends a materially different signal to a company weighing a decade-long field-development decision than a measure that genuinely sunsets on schedule. Investors do not price policies by their stated duration; they price them by their observed persistence, and an intervention that keeps being renewed in substance, however justified case by case, teaches the market to expect it to be renewed again.

There is also a straightforward gap between what the cap addressed and what the transition itself now needs from gas. AEMO's own Integrated System Plan for the electricity grid — the roadmap behind the renewables and transmission targets examined elsewhere on this site — assumes gas-fired peaking generation continues to play a firming role backing up wind and solar well into the 2030s, precisely because storage and transmission are not yet built out fast enough to do that job alone (AEMO, Integrated System Plan, 2024 edition; see this site's analysis of the 43% target and the real cost of the transition). That means the electricity transition itself, not only direct gas users like households and manufacturers, is now a growing claimant on the same east-coast gas supply the price cap and code were built around — adding a further source of demand onto a market the regulators were already warning would be short of new supply, at the same time as the price and regulatory settings coming out of 2022 were making new supply harder to commit capital to.

Canberra capped the price of gas nobody had committed to sell yet, then spent the following eighteen months publishing warnings — and eventually a whole new strategy — about the gas nobody was committing to sell.

None of this means the cap caused the supply gap; the Gippsland fields were always going to decline on a geological timetable, and the southern shortfall warnings predate the 2022 crisis by several years, appearing in AEMO's gas planning documents as early as the late 2010s (approx.) (AEMO, Gas Statement of Opportunities, various editions, 2018–2024). What the evidence does support is a narrower, but still serious, claim: an intervention justified and largely successful as an emergency household and manufacturer shield was allowed to persist, in a modified but still binding form, well past the emergency, without a clearly stated plan for how the government would simultaneously secure the new investment its own regulators said the market needed. Coherence, in the sense this article's central question asks about, means those two things — protecting households from a price shock and protecting the reliability of future supply — being pursued by policies designed to work together. On the evidence here, they were run largely in parallel, with the reliability side left to catch up through a second, later strategy document rather than built into the design of the first intervention.

What the government got right

A fair audit credits what worked. The core judgment to intervene at all, in the specific circumstances of December 2022, is difficult to fault on the evidence. AEMO's own decision to suspend the National Electricity Market — a step the market operator does not take lightly, and had never taken before — is close to as strong a piece of independent evidence as exists that the crisis was real, not manufactured, and that normal market mechanisms had, for a period, stopped functioning as intended. Manufacturers like Steve, and households facing winter bills that had risen sharply through no fault or choice of their own, needed relief measured in weeks, not the years a standard regulatory reform process would have taken, and the cap delivered that relief on a timetable nothing else on offer could have matched.

The design also shows real restraint by the standards of emergency market interventions elsewhere in the world during the same global crisis. Grandfathering existing contracts, rather than reopening or capping already-agreed prices retrospectively, protected the sanctity of contracts already relied upon for investment decisions, a distinction that matters to anyone assessing sovereign risk with any care. The shift from an emergency cap legislated in a fortnight to a mandatory code developed over several months of industry consultation was a genuine process improvement, and the code's cost-reflective "reasonable pricing" design, at least on paper, tries to preserve a path for higher-cost new supply to still earn an adequate return, rather than imposing a flat ceiling that would treat a deep, expensive offshore field the same as a cheap, shallow onshore well. The code also gave the ACCC a stronger, standing monitoring role over the east-coast market than existed before 2022, producing more frequent and more granular public reporting on prices, contracts and supply conditions than the market had previously been subject to — a transparency dividend that helps buyers and investors alike make better-informed decisions, even where it does not by itself resolve the pricing-uncertainty question (ACCC, Gas Inquiry 2017–2030, enhanced monitoring reporting, 2023–24).

Credit is also due for the follow-through. Rather than leaving the investment question to resolve itself, or ignoring the industry's warnings, the government commissioned and published the Future Gas Strategy specifically to address the gap this article identifies — an acknowledgement, in substance if not in words, that the emergency measures needed a companion long-term signal. That the strategy proved politically contentious, criticised by climate advocates for extending gas's policy licence to 2050 and beyond even as the government pursues net-zero commitments, does not change the fact that it was a considered attempt to answer the investment-certainty question the price intervention had complicated. And it is worth recording plainly that prices did fall, materially, from their 2022 peaks, and that businesses like Steve's kept their furnaces lit through the worst of it — an outcome that was not guaranteed, and that the counterfactual of no intervention at all, in a market this concentrated and this exposed to a global shock, was unlikely to have delivered on its own.

The caveats that remain

Even on the most generous reading, two caveats stand. First, the government has not, in the years since 2022, published a single integrated account of how the price and regulatory settings for existing supply and the incentives for new supply are meant to work together — the Future Gas Strategy addresses the investment question broadly, but it was released roughly eighteen months after the original cap, treating the coherence problem as something to patch after the fact rather than design for from the outset. Second, "reasonable pricing" as a standing, ACCC-enforced concept is inherently a judgment call rather than a bright line, and every judgment call an arbitrator or regulator makes under it becomes a fresh data point investors use to estimate how a future price spike, should one occur, would likely be handled — meaning the code has not fully removed the sovereign-risk premium the original cap introduced, even if it has softened it.