Significant Contingent Resource Booking

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    testing to commence weekend..should be good chance of a commercial gas well imo

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    plus $ 5mill cash ..every dog has there day dyor

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    Santos may import carbon dioxide waste to Moomba
    Angela Macdonald-Smith
    Angela Macdonald-SmithSenior resources writer
    Dec 7, 2020 – 12.00am

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    Santos' planned carbon capture and storage project at its Moomba gas plant has attracted interest from South Korea and Japan, and raised the possibility of carbon dioxide being imported into Australia for permanent disposal at the South Australian site at world-beating low costs.

    South Korea's SK Group inked a preliminary deal with Santos last week to collaborate on carbon capture and storage (CCS) expansion and international carbon credit arrangements linked with the Moomba project.

    Santos carried out a trial injection of 100 tonnes of carbon dioxide at Moomba in South Australia in October. Kelly Barnes

    Santos was also close to signing agreements with two Japanese parties that would create additional value from carbon credit operations in Australia, investors heard at the oil and gas company's annual briefing last week.

    The deals depend on CCS becoming eligible to generate Australian Carbon Credit Units, something under discussion within government.

    The attention comes after a commitment in US President-elect Joe Biden's climate strategy to use CCS technology, with Mr Biden saying in October he would address emissions from fracking through CCS.

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    "My door is getting constantly knocked on for people to come in and join us: SK was just an example and a couple of the Japanese companies are just examples of that," said Brett Woods, head of Santos' Energy Solutions business.

    "Nearly everyone we are operating with or around is coming to see how we are doing this, and why Santos can do this cheaper than other places."

    Exciting opportunity
    While the details of the agreements with the overseas parties have not been disclosed, they could potentially mean those parties acquire tradeable carbon credits that could count towards their emissions reduction obligations back home.

    Chief executive Kevin Gallagher said Santos had also been asked to investigate taking CO2 waste from other parts of the world. "I don't know how that works, but people want to talk to us about importing CO2 into the Cooper Basin if we can permanently store it," he said.

    "There's a long way to go to see how that will play out. The exciting thing is, because we are opening this opportunity, opportunities are developing: this is very much a new market, a new business."

    Santos have provided their own answer to why the energy transition will happen more quickly than some expect.

    — Neil Beveridge, Bernstein analyst

    The initial CCS project at Moomba, which would cost between $US125 million ($168.3 million) and $US155 million over three years, would have a capacity of 1.7 million tonnes a year of storage, with the compressed and dehydrated carbon dioxide injected into two depleted gas fields 2.5 kilometres underground.

    In a successful test in October, Santos injected about 100 tonnes of CO2 deep underground into the Strzelecki field in the Cooper Basin. The initial project would involve both that field and the Marabooka field.

    Several empty reservoirs across the basin were also suitable for carbon storage, offering the potential to scale up to 20 million tonnes a year, Mr Woods said.

    Mr Gallagher said the initial project would be the second-largest CCS project globally after Gorgon in Western Australia, with the world's lowest costs, at less than $30 a tonne over the life cycle.

    Awaiting government decision
    It is aiming to reduce that further to the low $20s a tonne, leveraging off existing CO2 separation equipment at the plant, access to depleted gas reservoirs and existing wells.

    While the project is ready for a final investment decision, Santos will not give the green light until the federal government declares it is eligible to generate Australian Carbon Credit Units, a decision hoped for towards mid-2021, Mr Gallagher said.

    It is aiming to start injecting carbon waste as early as 2024, and estimates that by 2050, the first phase of the project could capture and store about 44 million tonnes of CO2. Santos cites the potential to scale up to 20 million tonnes a year, using depleted reservoirs across the Cooper Basin.

    The scale provides the opportunity for Santos to dispose of carbon waste for third parties at Moomba. Mr Gallagher said it looked possible for other oil and gas producers in the Cooper Basin that were close to infrastructure to dispose of carbon there, but studies to take emissions from other industries signalled a "very expensive" carbon price of $100-$150 a tonne.

    "I don't see that happening any time soon" he said.

    Santos and SK are partners in the Barossa gas project off Australia's north coast.

    CCS remains a hugely controversial technology amid concerns among environmental groups that it will be used as an excuse to prolong the life of fossil fuels. High costs mean the process has also been uncommercial, while uncertainty reigns over the potential for long-term carbon leakage and over long-term liabilities.

    But Mr Gallagher told investors he was greatly encouraged by the international attention on CCS, including from the US President-elect. Mr Gallagher said CCS was also a "critical enabler" for zero-emissions hydrogen production at Santos at a cost matching the federal government's stretch target of less than $2 a kilogram.

    Santos aims to switch the fuel it uses to power its gas operations at Moomba to hydrogen.
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    Santos is relying on both CCS and hydrogen to help reach its upgraded target for net zero direct emissions, which it brought forward last week by 10 years to 2040.

    Bernstein analyst Neil Beveridge said Santos "could be onto something" with its strategy for "blue" hydrogen – derived from gas but made carbon-neutral – combined with CCS.

    "At less than $2/kg, Santos have provided their own answer to why the energy transition will happen more quickly than some expect and why at some point they will have to break their addiction to building a bigger oil business," Mr Beveridge said.

    Mr Gallagher said CCS was "very much at the forefront of energy strategy globally to reduce emissions and it's very important for Australia".

    Angela Macdonald-Smith writes on the resource

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    Companies form initiative to scale up green hydrogen production
    By Nina Chestney

    2 MIN READ

    FILE PHOTO: A passenger rides on a public bus on the day that Mayor of London Sadiq Khan outlined plans to place a levy on the most polluting vehicles in London, Britain, April 4, 2017. REUTERS/Toby Melville
    LONDON (Reuters) - Seven companies, including developer ACWA Power and Spanish utility Iberdrola, have formed a joint initiative to scale up production of “green” hydrogen in the next six years and bring down costs, they said on Tuesday.

    “Green” hydrogen is a zero-carbon fuel made by electrolysis, using renewable power from wind and solar to split water into hydrogen and oxygen.

    It is increasingly being touted as a way to decarbonise emissions-intensive heavy industry and transport sectors, but currently costs of production are too high to be competitive with other fuels.

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    The so-called Green Hydrogen Catapult initiative also includes Italian gas group Snam, renewable energy investor CWP Renewables, low-carbon technology group Envision, renewable energy developer Ørsted, and fertiliser company Yara.

    It aims to deploy 25 gigawatts (GW) of renewables-based hydrogen production to 2026, and to halve the current cost of the fuel to below $2 per kg.

    Its goal will require investment of around $110 billion - to be raised from a mix of debt and equity providers, with some public co-investment - and deliver more than 120,000 jobs, it said.

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    Industry experts say a $2/kg price will make green hydrogen more competitive with other fuels and encourage more large-scale projects.

    “From an industry perspective, we see no technical barriers to achieving this, so it’s time to get on with the virtuous cycle of cost reduction through scale up,” said Paddy Padmanathan, chief executive of ACWA Power.

    Reporting by Nina Chestney; Editing by Jan Harvey

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    good cheap gas play now... should get results before xmas 5 mill cash in bank cheap imo..

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    this can easy be a $8 k a day well pipeline only 2klm away testing anyday now, been a dog but looks a cheap gas punt here dyor..

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    testing start should be soon imo this can easy be a $8 k a day well pipeline only 2klm away testing anyday now, been a dog but looks a cheap gas punt here dyor..

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    very cheap low to med risk gas test coming ... 5 mill cash dyor

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    Cheap into a low risk gas test

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    As frustrating as this has been, the field equipment and supplies are now being assembled in Roma prior to mobilising to the well sites during the
    first week in November 2020."
    Icon announced earlier in the year, that an exciting gas prospect has been identified in Halifax No.1 which was the first well drilled in the whole of the ATP 855 tenement. This followed Icon’s decision to rehabilitate the existing wells in ATP 855.
    Prior to the commencement of the rehabilitation program, an extensive review of the six wells drilled was undertaken in house, with the advice of Consulting Engineers, to be sure that no other hydrocarbon opportunity had been overlooked.
    Following this review, it became evident that there was a real possibility of producing commercial hydrocarbons from the Callamurra sandstone which is above the unconventional gas play in the Halifax No.1.
    As a result of the ATP 855 review, the program has now been modified to test Halifax No.1 over the Callamurra sandstone.
    If the test is successful then the well can be suspended as a producing gas well. A full investigation of the results of the well would then be undertaken to determine the commerciality of the well."

    From the June QR.
    "If the test yields flow rates above 1 million cubic feet of gas per day and the chemical composition remains as per the original Drill Stem Test result, then the well can be suspended as a producing gas well. Following a full investigation of the results the well could be placed on commercial production.
    The APA sales gas pipelines are within 2 kms of the well, so it would not be difficult to place Halifax No.1 on production.

    It's on the record (2014 AR) that Halifax-1 was tested for the 6 months period from February 2013 to August 2013, around 200 days, produced over 243 Million Standard Cubic Feet of gas. The zone from which this gas was generated was not specified, but, certainly without any guarantees, gives a fair indication that this next test is reasonably in with a chance of being successful.

    Nature permitting, this is the first chance that shareholders have had to at least get a run for their money in over SEVEN long years.

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    Should be a good jan for icn

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    Company Announcements Office Australian Securities Exchange Limited 20 Bridge Street Sydney NSW 2000 Icon Energy Limited (ASX:ICN) is pleased to announce that Operations for the Rehabilitation and Testing program in ATP 855 in the Cooper Basin, commenced today at 10 am, 30th December 2020. The delayed start time was due primarily to COVID-19 interruptions to supply and certification of specialised equipment manufactured for the program in the USA. The downhole operations are expected to take up to 35 days, subject to weather and operational constraints. During this program, the testing of Halifax No.1 over the Calllamurra Sandstone will be conducted, with the timing of the test to be governed by the equipment mobilisation logistics. A further announcement of the testing of Halifax No.1 will be made when the test results are known. The test of the gas flow from Halifax will add a new gas provenence in the Cooper Basin, if it proves to be commercial. This outcome is important to Icon’s first test in this area from a conventional gas reservoir, which is normally pressured, with high methane gas content of approximately 97% based on previous gas composition analyses. This rehabilitation program is an essential operation, prior to the next exploration stage. Yours Faithfully

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    Australian firms to reap windfall from LNG Asia boom
    A cargo of Australian LNG from the $US54bn ($70bn) Gorgon plant in Western Australia sold for $US37 per million British thermal units to a Japanese utility at the weekend.
    A cargo of Australian LNG from the $US54bn ($70bn) Gorgon plant in Western Australia sold for $US37 per million British thermal units to a Japanese utility at the weekend.
    PERRY WILLIAMS
    SENIOR BUSINESS WRITER
    12 MINUTES AGO JANUARY 10, 2021NO COMMENTS
    LNG prices in Asia have soared to an all-time record, with a cold snap sparking a battle among the world’s biggest gas buyers to secure supplies, potentially delivering a windfall for Australian gas producers.

    A cargo of Australian LNG from the $US54bn ($70bn) Gorgon plant in Western Australia sold for $US37 per million British thermal units to a Japanese utility at the weekend, according to an industry source.

    That represents a near 20-fold jump from just over six months ago when the benchmark for LNG spot prices in North Asia, JKM, was trading at $US2 per mbtu in June.

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    Freezing weather in Asia among the top LNG importers — China, Japan and South Korea — has seen utilities race to grab enough gas for delivery over the next few weeks as inventories dwindle, hobbling the ability of some gas power plants to run at ­capacity.

    The Asian JKM index hit $US20.70 mbtu on Friday, eclipsing a 2014 record and more than 10 times the prices recorded just six months earlier.

    “That’s the biggest rally in LNG industry history and biggest commodity rally over the last year,” Credit Suisse analyst Saul Kavonic tweeted.

    READ MORE:Shell takes giant writedown on Prelude|Cheap gas unrealistic: Origin|Shell buzzing over giant Prelude|Gas ‘shortage’ looming for WA: AEMO
    Shell has also struck a sweet moment to resume production from its troubled $US12bn Prelude floating LNG plant after battling technical problems that have kept it offline since February 2020.

    The energy giant confirmed supplies have restarted after a prolonged outage.

    “LNG cargoes have resumed from Shell’s Prelude FLNG facility. Prelude is a multi-decade project, and our focus remains on delivering sustained performance over the long term,” a Shell spokesman said.

    Prelude was touted by Shell as the first of a revolutionary line of projects to unlock stranded gas resources previously considered too remote to support development of conventional land-based LNG plants. The floating LNG vessel started delivering supplies from the Prelude gas field, 475km north-northeast of Broome, in June 2019.

    Shell’s Prelude floating facility. Picture: Royal Dutch Shell Australia/Reuters
    Shell’s Prelude floating facility. Picture: Royal Dutch Shell Australia/Reuters
    However, the plant had yet to get anywhere near its full 3.6 million tonne-a-year capacity when a number of safety incidents unfolded in December and January which were probed by the National Offshore Petroleum Safety and Environmental Management Authority.

    Just two cargoes were shipped in January 2020 before operations were suspended due to the failure of back-up diesel power generation, EnergyQuest said.

    Shell took a $US1.3bn pre-tax writedown in the third quarter on Prelude, further hiking concerns over the long-term fortunes for the plant.

    The price boom may also hand Australia, the world’s biggest LNG producer, a revenue bounty should prices remain elevated for the duration of the Asian winter.

    Australia’s LNG income was estimated at $2.9bn for November, down over a third from six months ago, but showing a recovery after a September low of $1.8bn and October’s $2.2bn and likely to substantially rise given price momentum so far in January.

    Japan’s power price for Monday delivery jumped to 117 yen per kilowatt hour, marking the first time the daily average has ever been higher than 100 yen, according to Bloomberg.

    The huge rise in LNG spot prices may also raise issues for Australia’s manufacturers who have been campaigning for an LNG netback price.

    PERRY WILLIAMSSENIOR B

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    go ICN cheap imo

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    LNG price at new record as Asia, Europe cold snap bites
    Woodside is tipped to be one of the big winners from the soaring LNG prices.
    Woodside is tipped to be one of the big winners from the soaring LNG prices.
    PERRY WILLIAMS
    SENIOR BUSINESS WRITER
    @perrybwilliams ‏

    2 HOURS AGO JANUARY 13, 2021
    1 COMMENT
    LNG prices in Asia have soared to a new all-time record as traders scramble to secure new supplies amid a prolonged cold snap that has depleted inventories and prompted warnings of power shortages across the region.

    The Asian Japan-Korean Marker index hit $US32.49 ($41.82) per million British thermal units on Tuesday, eclipsing $US30mbtu for the first time and over 15 times prices recorded just six months earlier.

    Spot prices have now soared by 60 per cent in less than a week, with frigid weather across Asia and Europe sparking a frenzy among gas buyers. Fears of blackouts have emerged in Japan with utilities calling on the public to conserve energy to ensure the lights stay on.

    READ NEXT
    Commodity trader Trafigura paid $US39.30mbtu for an LNG cargo from France’s Total, which is thought to be one of the most expensive deals ever struck in the gas market.

    Australian companies are among producers also cashing in, with a cargo of Australian LNG from the $US54bn ($70bn) Gorgon plant in Western Australia selling for $US37mbtu to a Japanese utility over the weekend, according to an industry source.

    Woodside Petroleum stands to cash in from an expected doubling of spot LNG prices in 2021, Bernstein analysts said, with a quarter of its total production volumes currently sold on the spot market.

    READ MORE:Oil supply curbs sustain price rally|Woodside to gain as spot LNG prices soar
    It forecasts spot LNG forecast to trade at $US8mbtu in 2021 and $US9.50 mbtu in 2022, more than double 2020 prices of $US4.20 mbtu.

    Producers with east coast gas exposure could be among the winners, according to Credit Suisse.

    “The biggest surprise in 2021 so far has been LNG to my mind. And the markets LNG and east coast gas price expectations have not yet priced in upside potential to the extent oil expectations have improved of late in our view,” Mr Kavonic said.

    “Every US$1/mmbtu higher LNG price should increase domestic gas netbacks ~A$1.20/GJ. And the market’s east coast gas price expectations have not yet priced in upside potential the way oil has in our view.”

    Oil also hit an 11-month high on Tuesday near $US57 a barrel on Saudi Arabia’s plans to limit supplies.

    Chinese gas distributors have also been caught out by the rush to find supplies with some users resorting to taking supplies of trucked LNG, Wood Mackenzie said.

    “As demand was sluggish before winter, city gas distributors did not ask upstream suppliers for enough additional supply in winter piped gas contracts. As a result, some of them were caught by the sudden demand surge and had to resort to trucked LNG,” Wood Mackenzie research director Miaoru Huang said.

    PERRY WILLIAMSSENIOR BUSINESS WRITER
    Perry Williams joined The Australian in 2018. Previously he was Asia energy reporter for Bloomberg News and prior to

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    mpact of Winter’s LNG Crunch to Linger Even As Price Surge Ends
    By Stephen Stapczynski
    14 January 2021, 10:00 GMT+10
    Woodmac sees tighter gas market this summer due to Asia freeze
    Asian LNG prices to average $7.6/mmbtu in 2021, Woodmac says
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    The historic surge in Asian liquefied natural gas prices is poised to soon end as frigid winter weather subsides. Its impact could linger all year.

    The past few weeks of abnormally low temperatures across North Asia, home of the biggest LNG consumers, will force the region’s end-users to restock supplies, providing support for price benchmarks throughout 2021. What was expected to be a finely balanced summer just a month ago, is now looking increasingly tight, according to Wood Mackenzie Ltd.

    “The cold spell will have long-lasting implications throughout the year,” said Massimo Di-Odoardo, a vice president at the consultant firm. “That is going to pave the way for restocking demand very much across North Asia. Total available LNG to Europe will in turn be lower.”

    A harsh winter has upended energy markets and caught some utilities flat-footed, sending prices for electricity, fuel and vessels to record highs. The Japan-Korea Marker, Asia’s benchmark for the fuel, surged to $32.494 per million British thermal units on Tuesday, a 18-fold rise from April’s record low and the highest since S&P Global Platts began assessments in 2009.

    That rally is poised to peak this week as the February contract expires on Friday. Spot prices will roll to the March delivery contract, which is trading at half the previous month’s rate, mainly because the cold spike and supply tightness are expected to ease by then. This will make it appear that the JKM benchmark fell by a significant amount on Monday, when March becomes the front contract.

    Asian LNG prices will soon begin to fall, and end up averaging $7.6 per million Btu in 2021, nearly double last year’s rate, according to WoodMac. Dutch prices, a European benchmark, are seen rising 75% to $5.6 this year.

    Asian LNG spot prices extend historic rally amid frigid winter weather, limited supply
    More LNG suppliers are diverting cargoes from Europe to Asia to take advantage of the higher prices. Storage levels in Europe are already more than 15 billion cubic meters lower than last year, according to WoodMac. And higher coal and carbon prices, also partially driven by frigid weather, will provide headroom for more summer gas demand in Europe, the consultancy added.

    Already, the end of Asia’s cold blast is in sight. “The big cold seen in recent weeks in Northeast Asia will be over by next week, as milder temperatures return and the focus of the most anomalous cold shifts to northern Europe,” said Todd Crawford, lead meteorologist with the Weather Co., an IBM business. “The period from late-December through mid-January will likely end up as the coldest three-week stretch observed in more than a decade.”

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    Scott Morrison has struck a two-year deal with large east-coast LNG exporters to offer uncontracted gas first to Australian companies, in a bid to keep prices down and lower costs for manufacturers as part of the government’s COVID-19 recovery plan.

    But the deal, signed on Wednesday night in Gladstone by the Prime Minister and Queensland’s three LNG producers, avoided formal price controls, which some big manufacturers had pushed for but were strenuously resisted by the LNG industry.

    “Gas is critical to our economic recovery and this agreement ensures Australian businesses and families have the gas supply they need at the cheapest possible price,” Mr Morrison said. “This is about making Australia’s gas work for all Australians, while also supporting economic growth and backing important ­regional jobs in our expanding LNG sector.

    READ NEXT
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    EDITORIAL
    “As part of our JobMaker plan we are delivering more Australian gas where it is needed at an internationally competitive price. This particularly includes manufacturing businesses who employ more than 850,000 Australians, many of which rely on gas to operate.”

    The new agreement will lock in LNG exporters until 2023 and is an extension of the 2017 agreement struck between the Turnbull government and the industry aimed at heading off supply shortfalls in the domestic gas market which threatened to push up prices. The 2017 deal ensured LNG ­exporters offered uncontracted gas to the domestic market in the event of a shortfall, guaranteeing domestic users had access to enough gas for their own needs before supplies were shipped to Asian buyers.

    The new pact commits LNG exporters to offer uncontracted gas to the domestic market first on competitive market terms before it is exported.

    READ MORE:BHP slashes mine values
    The renewal of the deal has taken on additional significance given the federal government’s hope that cheap gas will spur households and manufacturers to recover more quickly from the COVID-19 pandemic.

    While the three LNG producers — the Santos-led GLNG project, Origin Energy‘s APLNG and Shell’s QCLNG — already comply with the new agreement, the Morrison government hopes the compromise will help ease tensions with manufacturers who complain they are still paying over the odds for gas. Resources Minister Keith Pitt said the government was working to achieve a balance between affordable gas for manufacturers and a price that encourages new gas development.

    However, energy giants dodged the mooted introduction of formal price controls on supplies for the first time, despite ­sustained pressure from manufacturers for cuts to their gas costs.

    Mr Morrison, in a September pledge, said the government would strengthen price commitments as part of plans to get more gas in the market and re-establish a strong economy, worrying ­producers that more government intervention would add fresh sovereign risk and lead to an investment strike.

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    The Australian understands there is neither a specified price nor an international benchmark referenced in the heads of agreement, easing fears among big gas suppliers the rules would be ­rewritten after they have sunk more than $70bn into building Queensland’s giant gas export industry. They have argued that, should the pricing option be introduced, it could effectively represent a ­rewrite of regulatory rules, hindering future investment and Australia’s international reputation.

    The absence of a price mechanism may cloud a goal for cheaper gas costing $4 to $6 a gigajoule issued by former Dow boss ­Andrew Liveris, who advised the ­government’s National Covid ­Coordination Commission on how manufacturing could help lift the economy out of the pandemic.

    Big energy users complain they can’t find gas on a contracted basis for less than $8 to $10 a ­gigajoule, more than double historic levels, which could force some facilities into importing products rather than producing Australian-made goods or even shutting their doors.

    Major gas users including billionaire Anthony Pratt’s Visy Industries, Qenos, Incitec Pivot and Orica took part in a high-level meeting in November with Mr Pitt and Energy Minister Angus Taylor to put forward their case for the policy change. Still, Canberra says the industry is much healthier since it introduced the agreement four years ago.

    “Since the government first acted in mid-2017 to ensure gas supplies for the domestic market through the introduction of the Australian Domestic Gas Security Mechanism and the first Heads of Agreement, the spot price for gas has dropped from $12.50 to $10.50/GJ to now be between $7 to $5/GJ,” it said.

    Cheaper domestic gas prices in Australia are likely to change again after LNG prices in Asia soared to a record as traders scrambled to secure new supplies amid a prolonged cold snap that has depleted inventories and prompted warnings of power shortages across the region.

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    Hydrogen is going to take 25% of all oil demand by 2050, Bank of America analyst says
    PUBLISHED FRI, JAN 22 20219:52 AM EST
    Anmar Frangoul
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    KEY POINTS
    A number of major energy firms are working on projects connected to “green” or “renewable” hydrogen production.
    At the moment, however, the vast majority of hydrogen generation is based on fossil fuels.

    Stephen Barnes | iStock | Getty Images
    Hydrogen is set to play a major role in the global energy markets over the coming decades, supplanting a large chunk of oil demand, according to Bank of America’s head of global thematic research.

    Speaking to CNBC’s “Squawk Box Europe” on Friday morning, Haim Israel accepted that while oil and gas would still be needed going forward, it was nearing a peak in demand. “We think it’s peaking this decade, it’s soon — way sooner than what everybody thinks,” he said.

    Israel listed several factors which would affect oil and gas going forward, including cheaper renewable energy, regulation and the electrification of cars.

    “We believe that hydrogen is going to take 25% of all oil demand by 2050,” he went on to state, adding that oil was “facing headwinds left and right. Yes, we’ll still need it, yes, it’s still going to be around, but the market share of oil is going to plummet.”

    As noted by the U.S. Department of Energy, hydrogen “is an energy carrier, not an energy source,” meaning it’s a secondary energy source like electricity. The DOE adds that hydrogen “can deliver or store a tremendous amount of energy” and “can be used in fuel cells to generate electricity, or power and heat.”

    Changing times?
    In recent years, governments and companies around the world have announced goals to reduce their environmental footprint and move away from fossil fuels. Both the U.K. and European Union are, for example, targeting net zero greenhouse gas emissions by 2050.

    If these kinds of goals are to be met, the world’s energy mix will need to see a significant shift to renewable and low carbon sources, a mammoth undertaking. For his part, Bank of America’s Israel emphasized the importance of diversification for companies involved in fossil fuels.

    “We … strongly believe that the ‘big oils’ need to think in different ways,” he said. “They need to think about not ‘big oil’ anymore but ‘big energy’ from here onwards, to go much more into renewable sources, to diversify their sources.”

    In a sign of how things may be starting to change, a number of energy majors — who, it should be noted, remain big players in oil and gas — are now ramping up investment in renewables such as solar and wind.

    Last September, it was announced that BP had agreed to take 50% stakes in the Empire Wind and Beacon Wind projects from Norway’s Equinor. The $1.1 billion deal is due to close in the early part of 2021.

    When fully up and running, Equinor says the Empire Wind and Beacon Wind projects, set to be located in waters off the East Coast of the United States, will each be able to power over 1 million homes.

    Hopes for hydrogen
    Hydrogen is another area starting to gain momentum. The EU has laid out plans to install 40 gigawatts of renewable hydrogen electrolyzers and produce as much as 10 million metric tons of renewable hydrogen by the year 2030.

    Hydrogen can be produced in a number of ways. One includes using electrolysis, with an electric current splitting water into oxygen and hydrogen. If the electricity used in the process comes from a renewable source such as wind then it’s termed “green” or “renewable” hydrogen.

    At the moment, the vast majority of hydrogen generation is based on fossil fuels. Nevertheless, recent years have seen major firms including Repsol, Siemens Energy and BP get involved in projects connected to “green hydrogen” production.

    At the start of this week, it was announced that a subsidiary of German industrial giant Thyssenkrupp had been awarded an engineering contract to carry out the installation of an 88 megawatt water electrolysis plant for Hydro-Québec. The electricity for this project will come from hydropower.

    A few days later, on Wednesday, Danish energy firm Orsted said it was pushing ahead with plans to develop a demonstration project which will harness offshore wind energy to produce green hydrogen.

    The International Energy Agency says global dedicated hydrogen production amounts to roughly 70 million metric tons per year, and states that demand continues to grow, having increased “more than threefold” since 1975. According to the Paris-based organization, “less than 0.1% of global dedicated hydrogen production today comes from water electrolysis.”

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