The move comes after the ACCC warned the east coast could face gas shortages from 2027—a year earlier than initially forecast.

Related article: Gas supply warning clouds reality, analysis says

Australia produces more gas than it needs to meet its domestic supply, but most is contracted for export.

“As ageing coal generation comes offline in coming years, gas will continue to be needed to firm renewable energy generation and as a backup during peak energy use periods,” the minister said in a statement.

Permits will be finalised for Esso and Beach Energy in the Otway and Sorrell Basins, with any discovered gas to support the domestic market.

Exploration permits will also be finalised for Chevron, INPEX, Melbana and Woodside Energy on Australia’s west coast, supporting energy security in Western Australia. In addition, 10 permits will be finalised for carbon capture and storage exploration.

King said the finalisation of offshore exploration permits does not automatically allow new offshore gas production to occur.

“Separate and extensive safety and environmental approvals are required through Australia’s independent National Offshore Petroleum Safety and Environmental Management Authority,” the minister said in a statement.

The news drew ire from environmental groups, with Greenpeace Australia calling the decision “a step backwards”.

The Australia Institute also levelled criticism over the decision.

Principal advisor Mark Ogge said, “This government was elected to take action on climate change and reduce emissions, but they are opening new fossil fuel projects instead.

“Expanding Australia’s gas production in the middle of a climate emergency is not just short-sighted: it treats our Pacific Island neighbours and future generations with contempt.

Related article: Flexible gas backs record demand in NEM during chilly winter

“Sea dumping is a failed technology that is now little more than a delaying tactic for the fossil fuel industry. The fact that these permits are being issued to major fossil fuel companies, so that they can supposedly offset their emissions from other highly polluting projects, is a farce of the highest order.

“This has nothing to do with supporting renewables, it is about producing more gas for export.”

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AEMO flagged possible supply shortages on peak demand days in Victoria until the end of September due to tight market conditions caused by cold weather and production issues at Longford gas plant, which in turn have depleted storage levels in eastern Australia. The market operator called for new gas supplies to address supply gap risks.

Related article: ACCC: Gas shortfall less likely as supply outlook improves

However, IEEFA’s analysis suggests that there is no need for the development of additional gas supplies, either to meet export demand or to address supply gaps. Further, the analysis shows that there are profitable options to reduce gas demand in the southern states that would not only address the risks of supply gaps but would also reduce household energy bills. These would add further momentum to already declining gas demand on the east coast.

Average daily gas consumption on the east coast dropped 13% from FY2012-13 to FY2022-23 (to 1,483TJ/d), and has fallen further in the first nine months of FY2023-24 (to 1,257TJ/d). Declining use of gas for power generation has dragged overall gas consumption in eastern Australia down over the same period (Figure 1).

“While AEMO forecast supply gaps, in reality there is no shortage of gas on the east coast given that about 80% of gas produced in eastern Australia is either exported via the LNG plants in Queensland or used to freeze that gas for export,” says the report’s author Kevin Morrison, IEEFA energy finance analyst, Australian LNG/gas.

Figure 1: Eastern Australia gas consumption

Most of the LNG produced in eastern Australia is supplied under long-term LNG export contracts, which are set to expire in the mid-2030s.

Geoscience Australia estimates that 2P reserves at Queensland’s coal-seam gas (CSG) fields are sufficient to cover the existing LNG contracts for the three Gladstone plants and beyond, until 2040, when operators such as Santos aim to be net zero in their upstream operations.

Declining southern gas production explains the tightness in eastern Australia’s gas market given most domestic demand is in Victoria. Tight market conditions have been exacerbated by unplanned maintenance this year at the Longford gas plant, which processes gas from the Gippsland Basin.

Production in Queensland, which has emerged as a major gas supply source over the past decade due to development of its CSG fields, is starting to plateau. Output at three of the five largest CSG fields in the state has fallen by 20-34% since 2019.

“The decline in three of Queensland’s largest CSG fields means new supply is unlikely to be as prolific as the most profitable fields tend to be developed first, followed by the less economic fields,” Morrison says.

The Australian government estimates that new supplies from undeveloped CSG fields in Queensland’s Surat Basin would cost A$11.64/GJ delivered to Melbourne, well above historical price levels.

Other areas hailed as potential new sources of gas by the industry will be even more expensive. Gas from the undeveloped Narrabri fields northern NSW would cost an estimated A$13.50/GJ delivered to Melbourne, and A$14.97/GJ from the Northern Territory’s undeveloped fields.

Related article: AEMO says renewables “the most efficient path” to net zero

“These new sources of gas will push up gas prices, further contributing to already challenging market conditions for commercial and industrial gas users,” Morrison says.

“At these price levels, we are likely to see further demand destruction and offshoring of Australian manufacturing.”

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According to Reuters, more than 260PJ of gas will be supplied through 2033 in two new commitments with Exxon Mobil’s Esso unit and Woodside under the government’s gas code rules, Energy Minister Chris Bowen said.

Australia last year extended a price cap of $12/GJ on natural gas until at least mid-2025, but it relaxed the rule for big producers if they agreed on domestic supply commitments for the country’s east.

“Gas is critical to supporting a lower-cost, more renewable grid as aging coal exits, and to support Australian manufacturing,” Bowen said in a statement.

The supply deals, sufficient to power east-coast gas-fired power stations for around two-and-a-half years, will directly feed into stations previously identified as being at particular risk of seasonal shortfalls, Bowen said.

This would ensure enough domestic supply to keep downward pressure on prices, he said.

In March 2023, the Australian Energy Market Operator (AEMO) warned the country faced risks of long-term supply gaps and must require additional commitments to expand its domestic gas supply.

Related article: Greenpeace takes Woodside to court over climate claims

Though Australia produces more gas than it needs to meet its domestic demands, most of the supply is exported overseas.

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Senex CEO Ian Davies said Australian energy customers would benefit from the additional supply to the domestic market represented by this agreement, and from the more than $1 billion investment in Queensland’s Western Downs region.

Related article: AGL signs renewable energy PPA with Tilt Renewables

“During this cost-of-living crunch, one certain way to put downward pressure on prices for energy customers is to deliver new gas supply to market—and our domestically-focused Atlas expansion can do just that,” Davies said.

“More secure and reliable gas supply will help to keep the lights on for Australian households and keep small manufacturers in business.

“The ACCC and Australian Energy Market Operator (AEMO) have forecast structural gas shortfalls in the east coast market without new supply in the coming years and have warned of the urgent investment needed to ensure enough supply.

“This agreement will add critical new supply to the domestic market when it’s needed most.

“It also comes at a time when the urgency—and challenge—to meet Australia’s emissions reduction and renewables targets is building every day.

“Gas plays an essential “firming” role for renewable generation by providing fast and reliable electricity to support intermittent, or “non-firm”, solar and wind generation.

“Gas is the critical safety net, maintaining the stability of the electricity grid and supporting Australia’s manufacturers as the road to net zero becomes increasing complex,” Davies said.

Related article: AGL signs renewable energy PPA with Tilt Renewables

The new gas deal between Senex and AGL and the commencement of gas supply in 2025 is conditional only on the timely recommencement of Senex’s Atlas expansion which was put on hold in December 2022 following Government intervention in the gas market.

Project recommencement requires the satisfactory resolution of regulatory arrangements and the receipt of certain Commonwealth approvals.

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The report, released yesterday, reveals a finely balanced supply outlook for 2022. A supply shortfall of 2PJ could arise across the entire east coast gas market next year, driven by a shortfall of up to 6PJ in the southern states, if LNG producers export all of their surplus gas.

This forecast is dependent upon demand from gas powered generators decreasing to record lows, and a material volume of gas from currently undeveloped reserves being supplied.

“The precarious supply situation for next year highlights the importance of the new Heads of Agreement that the Australian government signed with LNG exporters in January 2021,” ACCC chair Rod Sims said.

Under the Heads of Agreement, LNG exporters must offer uncontracted gas to the domestic market on internationally competitive terms before it is exported, and provide relevant material to the ACCC to demonstrate their compliance.

Related article: BHP and Woodside ‘discussing’ oil and gas merger

The three Queensland producers—Santos’s GLNG, Origin Energy’s APLNG and Shell’s QCLNG—did not adequately comply with a supply pact agreed with the Morrison government in January, according to the ACCC.

“The initial material LNG producers provided to us did not adequately demonstrate compliance with the new Heads of Agreement and they will need to lift their game,” Mr Sims said.

“The initial responses from LNG producers were concerning given that in the near future Australia’s southern states may depend on their surplus gas. We expect to see better compliance from LNG exporters over the next 12 months.”

The report shows that prices for contracted gas in the east coast market through to February 2021 remained at the lower levels observed during 2020. However, the tightening supply situation means these prices may not last.

“Domestic spot prices for gas spiked in July but the increase was driven by a particular set of circumstances that won’t necessarily impact offers for long-term contracts. Fortunately, we have subsequently seen some softening of those high spot prices in August,” Mr Sims said.

The ACCC observed that price offers for supply in 2022 trended from $6-11/GJ at the start of 2020 to $6-8 in the second half of 2020.

Although lower prices were welcomed by commercial and industrial users, many users are struggling to obtain offers for supply beyond 2022. Where supply is offered, prices are often at $9-10/GJ.

“We are also concerned that there have been significantly fewer offers for gas supply being made in the domestic market recently.”

The difficulty in securing offers beyond 2022 may have been partially caused by uncertainty around the Gas Code of Conduct and the ACCC’s LNG netback price series review. This demonstrates that it is important both are completed in a timely manner.

The ACCC’s LNG netback price series review is underway and will be completed by September 2021, following two rounds of public consultation.

APPEA immediately responded to the ACCC’s report, denying there would be a supply shortfall.

“The Australian Competition and Consumer Commission (ACCC) has reaffirmed for the tenth straight time there is no shortfall in Australia’s domestic gas market,” APPEA’s statement read.

Related article: Kurri Kurri gas proposal draws ire from Hunter community

“The ACCC’s latest Gas Market Inquiry 2017-2025 interim report found ‘Sufficient supply is forecast to be available to meet demand in 2022’ and that minor concerns around supply are already being addressed.” 

APPEA chief executive Andrew McConville said, “Our members are constantly working with customers to meet their energy needs. This includes signing more than 100 gas supply agreements and other commercial arrangements since 2012 including just last month Senex signing a long-term domestic gas sales agreement with Adbri Limited to supply up to 11PJ of natural gas to support Adbri’s South Australian manufacturing operations to 2030. 

“They are also meeting the requirementunder the 2021 Heads of Agreement to offer equivalent volumes of uncontracted gas (spot cargoes) with reasonable notice on competitive market terms to the Australian domestic gas market before they are offered to the international market. 

“This includes billions of dollars in new investment to bring more gas into the domestic market such as the announcement by Senex today of an expansion at Atlas which will supply a total of 18PJ of gas a year entirely for domestic use—which is more than five times the energy needed to run all the homes in Toowoomba.”

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Consistent with the findings released in 2019, AEMO’s 2020 Gas Statement of Opportunities (GSOO) and 2020 Victorian Gas Planning Report Update (VGPR Update) have identified a projected shortfall of gas supply on peak winter days in the southern states from 2024, unless more southern supply sources are developed, or pipeline capacity limitations are addressed. 

“Supply from existing and committed southern gas developments is expected to reduce by more than 35 per cent over the next five years, despite the increase in newly committed gas projects over the last 12 months,” said AEMO’s Managing Director and CEO, Audrey Zibelman. 

The decline in supply is due to updated forecasts from gas producers that show several existing gas fields could end production between mid-2023 to mid-2024. If production from these fields ends earlier, southern states could experience peak winter day supply gaps as early as 2023. 

The report’s forecast also shows that anticipated gas field projects, which are likely to proceed over the next few years, could improve supply until 2026; however, pipeline limitations will still need to be addressed to help meet gas demand during peak winter days. 

“The risk of peak day shortfalls could be resolved by a wide range of different options, some of which are already being explored by industry and governments,” Ms Zibelman said. 

“This could include the development of new LNG import terminals, pipeline expansions, or new supply that could result from the Victorian Government’s decision to lift the ban on onshore gas exploration from July 2021. The Commonwealth and New South Wales’ government have also proposed a target to inject 70 petajoules of gas into our energy markets by 2022.”

The reports also flag the increasing amount of forecast uncertainties, particularly in 2022-2024, when decline in southern production coincides with the staged closure of Liddell Power Station. 

“As the energy industry transforms, the growing linkages between Australia’s gas and electricity sectors mean that events occurring in one sector, could have strong impacts on the other,” Ms Zibelman said. 

Any delays to the projects identified in AEMO’s Integrated System Plan, a further reduction in availability of Australia’s coal-fired generation fleet, earlier than forecast depletions of gas fields, long-term changes in industrial activity, changes to the global LNG markets, or the ongoing effects of COVID-19 could all heavily impact current forecasts. 

“Close collaboration between AEMO, market bodies, industry and state and federal governments will be a critical component to the success of our energy transformation. AEMO will continue to work closely with all parties in the best interest of consumers, and to shape a better energy future for all Australians,” Ms Zibelman said.

The post AEMO: Additional east-coast gas supply required by 2024 appeared first on Energy Source & Distribution.

The report found that the supply outlook for 2020 has improved slightly since July 2019 but beyond 2020 there is significant uncertainty about whether future demand can be met.

On the ACCC’s findings, a joint media release from Treasurer Josh Frydenberg, Minister for Energy and Emissions Reduction Angus Taylor and Minister for Resources Keith Pitt, titled ‘ACCC points to improved gas supply in 2020’, said the ACCC’s report was good news.

“The Australian Competition and Consumer Commission (ACCC) reported an improvement in the gas supply outlook across the East Coast market in 2020, with a supply shortfall unlikely in the short-term,” it read.

Importantly, between June 30, 2017 and June 30, 2019 Queensland LNG reserves were written down by more than 4,400 PJ.

Related article: Gin Gin substation revamp hits half-way mark

“Southern states risk facing a shortfall in the medium term unless there is more exploration and development in the south, or new infrastructure to bring more supply to southern states,” ACCC Chair Rod Sims said.

“We continue to urge state and territory governments to assess individual gas development applications on a case-by-case basis. We also suggest they actively manage tenements to prevent ‘warehousing’ of gas, and that they coordinate the development of pipeline and storage infrastructure to avoid unnecessary duplication.”

While LNG netback prices have been falling since May 2019, with forward LNG netback prices for 2020 well below netback prices seen in recent years, prices offered in the East Coast Gas Market have remained mostly steady within a range of $9-$12/GJ.

“The recent significant divergence between the netback prices and the prices offered is a concern for the ACCC and in 2020 we intend to now delve much deeper into the reasons why this is occurring,” Mr Sims said.

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“Indeed, average netback prices expected for 2020 have been under $7/GJ since November 2019, which is well below prices being offered to domestic buyers.

“We have been watching prices closely, and have observed instances where prices offered have included a fixed price component, on top of an LNG spot price linked component.”

The Energy Users Association of Australia (EUAA) says the ACCC’s report confirms the gas crisis is still here.

“While LNG netback prices have fallen, domestic contract prices remain high,” said EUAA Chief Executive Officer, Mr Andrew Richards.

“In our view, uncertainty about future domestic supply and competition issues are still major concerns for gas users. This will require significant and sustained attention by governments and the gas industry if we are to avoid demand destruction and thousands of lost jobs.”

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The 12-month agreement is an extension of the 2018 agreement to take gas from the offshore Casino, Henry and Netherby fields in the Otway Basin.

The gas forms part of Origin’s domestic portfolio, which is one of the major suppliers to Australian households, large gas users such as manufacturers and gas-fired power stations.

“Origin and other gas producers have answered the call and made sure gas is available for domestic users,” Origin executive general manager energy supply and operations Greg Jarvis said.

“Gas customers on Australia’s east coast can access supply, with competitive tenders and at prices well down from their peak.

“We are proud to be one of the major gas suppliers to the east coast domestic market, and to have invested in further growing our gas business in the past year.”

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Addressing the Paydirt 2018 South Australian Resources and Energy Investment Conference in Adelaide this week, Leigh Creek Energy managing director Phil Staveley said the company was on track to commence this quarter, a pre-commercial demonstration of its in situ gasification (ISG) demonstration plant under construction currently on the former coal mine site.

Subject to a positive outcome of the planned 90-day demonstration trial to produce syngas, this should lead to an anticipated upgrade to reserve, of the project’s 2C unconventional gas resource.

The demonstration plant includes the construction of an above-ground plant and the establishment of a below-ground single-ISG gasifier chamber.

“We have recently secured the key environmental approval for the demonstration to go ahead and that has substantially de-risked the test schedule,” Mr Staveley said.

“The pre-commercial demonstration will commence shortly from what is arguably the best ISG site in the world.

“It has the correct geological setting, and we are deploying industry best practices to ensure Leigh Creek remains one of the world’s most low-risk ISG commercial operations.”

The demonstration plant will be commissioned and operated for a short period, between two and three months, to produce syngas, so the technical and environmental performance of the process can be analysed.

The company’s flagship Leigh Creek project has an estimated resource of 2964PJ – equivalent to about 7.8 per cent of the east coast’s 2C gas resources of 38,600PJ and delivering a potential 30-year plus life.

Its syngas can be converted into power, natural gas, petrochemical and agricultural products.

Leigh Creek Energy is looking to final feasibility, approvals, FEED and offtake conclusions through calendar 2019 to facilitate a final investment decision and start to construction of the project’s main power station, in 2020.

The ISG configuration will consist of two wells drilled into a deep coal seam more than 500m below the surface, one for an inlet well for the addition of air and water, and the other for the outlet well for the extraction of synthesis gas (syngas).

The demonstration project is regulated as an exploration activity under the Petroleum and Geothermal Energy Act 2000 and as an exploration activity the syngas produced is unable to be sold for commercial use, and will therefore be treated on site in a thermal oxidiser as part of the process.

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AEMO’s 2018 Gas Statement of Opportunities (GSOO) has found a change in international market dynamics, lower demand for gas-powered generation (GFG), new pipeline interconnections and the Federal Government’s Australian Domestic Gas Supply Mechanism (ADGSM) have delivered an improved outlook for the east-coast gas markets.

AEMO planning and forecasting executive general manager David Swift said the GSOO provides a 20-year outlook for Australia’s east-coast gas sector.

“The 2018 GSOO outlines a number of rapid responses made by industry and government based on our concerns raised around forecast shortfalls in the 2017 GSOO update and the 2018 Victorian gas planning report,” Mr Swift said.

“Alongside international market changes, newly committed electricity generation resources have resulted in a favourable increase of gas availability for the east-coast market.”

Last year, AEMO forecast a 48PJ gas shortfall for 2019.

This year, AEMO forecasts no gas supply gaps in the most likely scenario for the domestic gas market out to 2030, and forecasts a 58PJ gas surplus in the east coast domestic market in 2019.

“With more than 4000MW of wind and solar coming online in the next two years, our forecasts show GPG demand could be even lower than the projections in our 2017 GSOO, as the role of GPG transitions to focus more on meeting demand when renewable generation is low,” Mr Swift said.

“However, an increased need for GPG due to weather related or contingency events could still adversely impact this forecast, and tighten the supply demand balance once again.”

Federal Energy Minister Josh Frydenberg and Minister for Resources Matthew Canavan said in a joint statement the improvement in gas supply was thanks to government action.

“The Turnbull Government’s intervention in the market to ensure more gas for domestic use before it is shipped offshore has averted a previous projected shortfall,” the statement said.

“Adequate gas supply above domestic demand is forecast for 2019.

“This is largely due to reductions in forecast demand for gas-powered generation and a small increase in domestic gas supply including the connection of the Northern Gas Pipeline between the Northern Territory and Mt Isa in Queensland.

“While the gas market remains finely balanced, the gas market on the east coast continues to improve since the volatility of 2016-17.”

The ministers called on states and territories to remove blanket bans and moratoria on conventional and unconventional gas exploration.

The report also reflects the connection between Australia’s domestic and international gas markets, as minor changes in liquefied natural gas (LNG) exports provide additional supply to the east coast.

“The international oversupply of LNG capacity and the emerging spot Asia-Pacific LNG market means international buyers are forecast to source less gas from Australian LNG producers in the short-term,” Mr Swift said.

“Coupled with the current supply conditions on the east coast, this will mean LNG producers will be able to provide up to 8PJ more than previously expected to the domestic market, which is a minor, but favourable addition to the east coast’s dynamic supply demand balance.”

In the longer-term, the 2018 GSOO highlights the need for additional gas supply reserves to be developed, as existing fields ramp up their production to meet short-term demand.

“While southern producers have informed AEMO about their forecast production increase from the southern gas fields, AEMO’s 2018 GSOO forecasts still show that further exploration and development will be needed to meet demand from as early as 2022,” Mr Swift said.

Santos managing director and chief executive officer Kevin Gallagher said the outcome was a good demonstration of the corporate sector working in partnership with government to solve a public policy problem without the need for market intervention.

“As a proud Australian company, Santos is committed to ensuring the domestic gas market is adequately supplied and is set to deliver around 70PJ, which is about 11 per cent of expected east coast domestic demand this year,” he said.

“The industry as a whole did an exceptional job of increasing gas supply to the domestic market in the face of unprecedented reputational challenges arising from community concerns about access to reliable and affordable energy.”

Mr Gallagher said Santos had also made significant progress in reducing the cost of supply.

“When it comes to putting downward pressure on gas prices, cutting the cost of supply is a good place to start,” Mr Gallagher said.

“Connected well costs in our Roma field are now $900,000 per well, and in the Cooper Basin, our completed well costs are averaging $2.8 million per well.

“That’s a reduction of 72 per cent and 42 per cent respectively since the end of 2015.

“As Australia’s lowest cost onshore developer, we’re extracting more gas for less money.”

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The pipeline will connect Senex’s new ‘Atlas’ gasfield in the Surat Basin in south-east Queensland with Jemena’s Darling Downs Pipeline and the Wallumbilla Gas Hub – the largest gas hub in the country.

After a competitive tender process, Jemena was selected as Senex’s preferred partner because it proposed the most cost-effective and direct pathway to the domestic gas market.

Jemena’s solution also leverages the Darling Downs Pipeline, which provides direct access to the Wallumbilla gas hub and offers Senex flexibility to sell its gas to Australian gas customers.

Jemena managing director Paul Adams said the AGPP would provide additional volumes into the domestic market for a range of commercial and industrial gas users.

“The Atlas gasfield is the first of 13 gas exploration tenements awarded by the Queensland Government as part of a broader move to fast-track the development of new gas to the domestic market,” Mr Adams said.

“Jemena will construct the AGPP on an expedited schedule in order to deliver first gas by the end of 2019.”

Jemena will invest around $140 million to build the gas plant and 60km pipeline, which is capable of transporting approximately 40TJs of gas per day.

The AGPP is expected to create around 200 jobs throughout its planning, construction, and commissioning phases.

Mr Adams said the AGPP would build on Jemena’s Northern Growth Strategy to develop an interconnected supply chain of gas infrastructure assets across northern Australia.

“We know there is continued demand for gas across the east coast and that northern Australia will play a leading role in meeting this demand by bringing new gas to where it is most needed, via the most direct and economic route,” he said.

“The AGPP is another crucial addition to our plans in northern Australia and allows us to play a leading role in bringing a new source of gas supply and greater competition to the market.

“We are also continuing work on our Northern Gas Pipeline (NGP), which will initially bring around 90TJs of gas to the east coast, and are now progressing plans to expand and extend the NGP so it can transport around 700TJs of gas – that is enough gas to meet the average daily gas needs of Sydney, Brisbane, and Adelaide combined.”

Mr Adams said the NGP continues to track to schedule with first gas set to flow before the end of the year.

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Central and Macquarie are joint venture partners at the Mereenie oil and gas field, located in the Amadeus Basin in the Northern Territory, approximately 250km west of Alice Springs.

In order to allow the development of Mereenie gas as soon as possible, the ACCC has granted interim authorisation, which allows the parties to begin negotiating joint supply agreements with customers pending the ACCC’s final determination.

Central and Macquarie propose to jointly market gas produced from the Mereenie field and give effect to gas supply agreements with customers with common terms and conditions including price.

The companies have applied for authorisation through the ACCC because without it, the joint marketing arrangement would likely breach competition laws.

“The ACCC’s preliminary view is that joint marketing is likely to encourage investment to increase gas production at Mereenie,” ACCC chairman Rod Sims said.

“Bringing forward new gas supply benefits the public, particularly once the Northern Gas Pipeline links the Northern Territory to east coast gas markets for the first time later this year.

“Supply of affordable gas available for east coast customers is tight, particularly in southern parts of Australia which is putting significant pressures on consumers and businesses.

“We were very mindful of this in granting interim authorisation.”

Where commercially viable, separate marketing is generally preferable as it results in more competitive outcomes.

However, in this instance, the ACCC identified minimal, if any, public detriment resulting from time-limited joint marketing.

Customers in the NT-Mount Isa region appear to have the option of alternative sources of supply, such as Power and Water Corporation from the Blacktip Field in the NT, and suppliers from the Cooper Basin and potentially the Galilee Basin.

“These alternatives are likely to constrain Central and Macquarie if they were to attempt to offer their gas at higher prices or on less flexible terms,” Mr Sims said.

The ACCC proposes to grant authorisation for the parties to engage in joint marketing for three years.

Any agreements entered into during that period must end no later than December 31, 2028.

The ACCC has invited submissions from interested parties on the draft determination before it issues its final determination.

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Queensland Natural Resources, Mines and Energy Dr Anthony Lynham today announced Central Petroleum and Armour Energy would develop a total of almost 400ha just north of the townships of Miles and Surat in southwest Queensland.

Speaking at the Australian Domestic Gas Outlook 2018 conference in Sydney, he said the government was meeting its recent election commitment to release land for domestic-only production by today releasing more than 6000sq km for exploration.

“These releases are shoring up Australia’s gas supply – further demonstrating Queensland as a reliable and affordable gas producer,” Dr Lynham said.

The release comes just five months after the first release of land for domestic supply only, with the first tender going to Senex Energy.

In the latest release, explorer Central Petroleum has been awarded exploration permits for 77sq km in the Surat Basin, 28km northwest of Miles.

Managing director Richard Cottee said securing the tenement will help fulfill a goal to preserve local jobs in Australia’s domestic manufacturing sector.

“We fully support the dedication of land specifically for the exploration and production of domestic gas, and the awarding of this tender helps us to further this cause,” Mr Cottee said.

“The Queensland Government is helping to secure Australian industry and the right way to do this is by increasing rather than rationing supply.

“I congratulate the government on its commitment, increasing local supply will go a long way in ensuring that we can maintain a diversified economy and the jobs that come with it.”

Armour Energy has been awarded permits to explore a 318sq km area 17km north of Surat, near the company’s existing tenures and existing infrastructure.

Armour Energy chief executive officer Roger Cressey said the area would add to the company’s existing portfolio in the Roma Shelf.

“Armour has recently restarted production from its south western Queensland Kincora Gas Project and we are confident that this new acreage will provide further resources for long term gas production,” Mr Cressey said.

“Additionally, the close proximity of this new tenement to our Kincora gas plant means gas resources can be easily connected, processed and delivered to market.

“While Armour Energy it is still in its early days in terms of gas production, we are contributing to the local region as well as the east coast gas market as a steady and growing supplier.”

The release of additional land for petroleum and gas exploration includes another 6000 sq km for domestic production as well and other 11,000sq km without any market condition.

“These tenements will give junior and mid-tier producers a further gateway into Queensland’s diverse exploration industry,” Dr Lynham said.

Dr Lynham told the conference it was not reasonable for other states to issue moratoriums on extracting their own gas when they are happy to import it from Queensland.

“These parcels of land will continue to help in meeting east coast gas supply, they are not a silver bullet,” he said.

“I see no reason why other mainland states cannot follow our lead to help secure a sustainable gas industry, including a stable domestic supply.”

Central Petroleum and Armour Energy must now negotiate land access agreements and fulfil all existing environmental and Native Title requirements before the Petroleum Lease is granted and work can begin.

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The report finds that, after increasing in 2016, wholesale gas prices for large industrial customers fell in all east coast states in 2017, and by 11 per cent from 2015 to 2017.

“In 2017, the media often reported anecdotes about contract offers of $18 or more to industrial customers. Now, with the report to COAG, we have a comprehensive, independent analysis which shows actual prices in the market,” APPEA chief executive Dr Malcolm Roberts said.

“The report shows the average delivered price for large industrial customers is $10.08/GJ, with the wholesale gas component of that price $9.19.

“As in 2015, when they last reported to COAG, the analysts advise “gas prices reflect the supply and demand balance”.

In 2017, “wholesale gas prices increase with distance from Queensland”.

“Governments in Victoria and New South Wales should squirm when they read the report.”

Dr Roberts said Victoria now has the most expensive wholesale gas in the market, while New South Wales is almost entirely reliant on interstate supplies of gas, mostly coal seam gas from Queensland.

“The political gestures of bans and moratoriums may feel good to these state governments but customers in these states are paying the price,” he said.

“The report underlines a simple, inescapable truth – the only sustainable way to place downward pressure on gas prices and to improve energy security is more gas supply and more gas suppliers.

“Cooler heads must prevail in 2018. The focus must move back to where it belongs – the need to ensure more gas supply and more gas suppliers.”

Queensland Minister for natural Resources, Mines and Energy Dr Anthony Lynham agreed that more supply was needed.

“Queensland has been doing the heavy lifting on boosting gas supply since 2016,” he said.

“Gas is a feedstock as well as an energy supply, and those costs impact on employers’ ability to create jobs.

“It’s time for the Federal Government to take some of the expert advice it’s now had from the Chief Scientist’s review and this COAG team. Invest in some infrastructure and encourage gas exploration and development.”

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