Health Check: what causes bloating and gassiness?



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One in six healthy people report problems with bloating.
Alice Day/Shutterstock

Vincent Ho, Western Sydney University

Your trousers fit when you put them on in the morning. But come mid-afternoon, they’re uncomfortably tight – and you didn’t even overdo it at lunchtime. Sound familiar?

Around one in six people without a health problem and three in four people with irritable bowel syndrome (IBS) report problems with bloating. In fact, for people with IBS and constipation, bloating is their most troublesome symptom.




Read more:
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Bloating is, of course, a feeling of increased abdominal pressure, usually related to gas. It may or may not be accompanied by visible enlargement of the waist (known as abdominal distension).

But contrary to popular belief, bloating and abdominal distention isn’t caused by an excessive production of gas in the intestines.

What causes intestinal gas?

Gas in the upper gut can come from swallowed air, chemical reactions (from neutralising acids and alkali) triggered by food, and dissolved gas moving from the bloodstream into the gut.

Food products that are poorly absorbed in the small intestine can travel lower down to the large intestine where they’re fermented by bacteria. This process can produce carbon dioxide, hydrogen or methane gas.

Gas from the gut can come out through belching or passing wind, or by being absorbed into the blood or consumed by bacteria.

How much wind is normal?

Back in 1991, researchers in the UK tracked the farts of ten healthy volunteers. The volume of gas they expelled in a day varied from 214 mls (on a low-fibre diet) to 705 mls (on a high fibre diet).




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The participants passed wind an average of 14 to 18 times per day, and it was comprised mainly of carbon dioxide and hydrogen.

In the fasting state, the healthy gastrointestinal tract contains around 100 mls of gas which is distributed almost equally among six segments of the gut: the stomach, small intestine, ascending colon, transverse colon, descending colon and lower (pelvic) colon.


Tefi/Shutterstock

After eating, the volume of gas in the gut can increase by about 65% and tends to be located around the pelvic colon.

As the stomach stretches and small bowel is stimulated, the passage of gas accelerates and you might feel the urge to fart.

But for people with a high-fat diet, fats inside the small bowel can delay this passage and make you retain the gas.

Bloaters don’t produce more gas

A 1975 study compared the amount of intestinal gas between people who reported being bloated and those who said they were not.

The researchers pumped (inert) gas through a tube directly into the participants’ intestines at a relatively high flow of 45 mls per minute. Then they recovered the gas via a plastic tube from their rectum.

The researchers found no difference in the levels of gas collected between the bloating and healthy subjects.

Not everyone who feels bloated will have a distended stomach.
siam.pukkato/Shutterstock

More recent research using abdominal CT scans has shown that people with bloating have similar volumes of intestinal gas as those who don’t feel bloated.

Likewise, although people with IBS experience more abdominal distention, they do not produce more intestinal gas than other people.

This leads us to believe the volume of gas in the gut itself isn’t the main mechanism for bloating.

When gas gets trapped

Most people tolerate intestinal gas really well because they can propel and evacuate gas very efficiently. As a result, only a relatively small amount of gas remains inside the gut at a given time.

In one study, researchers pumped just over 1.4 litres of gas in two hours into the mid-small bowel of healthy volunteers. This led to only a very small change in waist circumference: no more than 4mm.

On the other hand, people with abdominal conditions such as IBS or functional dyspepsia (indigestion), show impaired gas transit – in other words, the gas ends up being trapped in different parts of the bowel rather than moving along easily.




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Studies show people with abdominal conditions tend to retain a relatively large proportion of gas pumped into the mid small bowel. They may even have notable increases in waist circumference without any gas being pumped in.

This impairment was confirmed in a study comparing 20 participants with IBS to a control group of 20 healthy participants. All received gas pumped directly into the mid-small bowel.

Some 90% of IBS participants retained the gas in their intestines compared to only 20% of control subjects. The researchers found abdominal distension was directly correlated with gas retention.

Some people also have problems evacuating this gas, or farting. People with IBS and chronic constipation, for instance, may have difficulty relaxing and opening their anal sphincter to release farts.

This can lead to intestinal gas retention and symptoms of bloating, abdominal pain and distension.

Pain without looking bloated

Despite feeling extremely bloated, some people have minimal or no distension of their stomach.

Research among people with IBS suggests this pain and discomfort may be due to a heightened sensitivity in the gut when a section of the abdomen stretches.

In fact, one study found those with bloating alone had more abdominal pain than those who had symptoms of bloating and abdominal distension.

If you’re sensitive to this stretching, are unable to move gas throughout your gut, and can’t get rid of it, you’re likely to have bloating and pain, whether or not there’s any visual sign.




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The Conversation


Vincent Ho, Senior Lecturer and clinical academic gastroenterologist, Western Sydney University

This article is republished from The Conversation under a Creative Commons license. Read the original article.

Blocking Chinese gas takeover won’t damage Australia’s foreign investment pipeline



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A single foreign company having sole ownership and control over Australia’s most significant gas transmission business, says Australia’s treasurer, is not in the national interest.
Shutterstock

Simon Segal, Macquarie University

The Morrison government’s decision to block Hong Kong’s largest infrastructure company from buying one of Australia’s key infrastructure companies seems to make a complicated relationship with China even more fraught.

Rejections of foreign takeover bids are extremely rare. This is just the sixth such decision in nearly two decades.

It might be argued the blocking of the A$13 billion bid for gas pipeline operator APA Group by Cheung Kong Infrastructure (CKI) Holdings reflects increasing politicisation of Australia’s process for reviewing foreign investment.

But this is not a political shot across the bows like China’s announced anti-dumping probe into imports of Australian barley. This takeover proposal was always doubtful. News of its knock-back potentially damaging relations with China, or foreign investment more generally, are greatly exaggerated.




Read more:
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Always unlikely

APA Group owns 15,000 km of natural gas pipelines and supplies about half the gas used in Australia. It owns or has interests in gas storage facilities, gas-fired power stations, and wind and solar renewable energy generators.


APA Group’s infrastructure assets.
APA

Back in September, after APA accepted the takeover offer from a CKI-led consortium, the investment research company Morningstar judged it unlikely that Australia’s Foreign Investment Review Board would approve the bid.

The board is only an advisory body. The final decision rests with the federal treasurer. Josh Frydenberg signalled his intention to block the deal in early November, giving CKI a few weeks to change its proposal, either by selling assets or finding other investment partners, enough to change his mind.

That did not happen. Frydenberg’s final decision to block the bid was based, he said, on “a single foreign company group having sole ownership and control over Australia’s most significant gas transmission business”.

He emphasised the government remained committed to welcoming foreign investment: “foreign investment helps support jobs and rising living standards.”

It’s not all about CKI

CKI is not state-controlled. It is headed by the son of Hong Kong’s richest man, Li Ka-shing, and has a history of considerable success in investing in Australia.

Nonetheless speculation about the rejection damaging the Australia-China relationship has ensued. In the words of the South China Morning Post: “As the most China-dependent developed economy, Australia potentially has a lot to lose should relations with its biggest trading partner deteriorate further.”




Read more:
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Let’s put this into perspective.

First, there is broad bipartisan agreement that foreign investment is crucial to Australia’s economic prosperity.

Second, as already mentioned, this is just the sixth major public foreign investment proposal blocked since 2000. (All but one, notably, have been by Liberal treasurers.)

Third, all six rejections have been case-specific. Each bid has been considered on its merits.

This case arguably has less to with CKI being Chinese linked than with the size and significance of APA, whose transmission system includes three-quarters of the pipes in NSW and Victoria.

In 2016 CKI’s A$11 billion bid for NSW electricity distributor Ausgrid was also blocked (by then-treasurer Scott Morrison) on national security grounds.

But in 2017 CKI won approval for its A$7.4 billion bid for West Australian-focused electricity and gas distribution giant DUET. And in 2014 CKI’s acquisition of gas distributor Envestra (now Australian Gas Networks) was also cleared.

Shifting emphasis

This is not to deny that politics played a part in Frydenberg’s decision.

The seven-person FIRB board was divided (the exact votes are not known). The Treasurer’s call could have gone either way.

Forces within the Liberal Party that opposed Malcolm Turnbull’s leadership have also been deeply hostile to APA’s sale to CKI. Among the most vociferous was NSW senator Jim Molan, who warned of “hidden dragons” in the deal.

For a minority government lagging in the polls and just months away from an election, such views have assumed inflated importance.

Nonetheless the APA decision was not a surprise. Greater scrutiny is now part and parcel of the Foreign Investment Review Board process. In particular, the emphasis has firmly shifted over the past few years to scrutinising national security and taxation areas.




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The Critical Infrastructure Centre within the Department of Home Affairs, which became fully operational this year, brings together capability from across the federal government to manage national security risks from foreign involvement in Australia’s critical infrastructure. It’s particularly focused on telecommunications, electricity, gas, water and ports.

David Irvine, who has chaired the Foreign Investment Review Board since April 2017, is a former head of the Australian Security Intelligence Organisation.

This shifting emphasis does not equate to a bias against foreign investment per se. There is no evidence investors, including Chinese, are being discouraged or significantly deterred from investing in Australia.

CKI itself demonstrates, by returning to Australia despite previous rejections, that foreign investors will not give up so long as the next deal stacks up. There is already speculation CKI has moved on, and now has its eyes on Spark Infrastructure, an ASX-listed owner of energy asset.The Conversation

Simon Segal, PhD research candidate, Business, Macquarie University

This article is republished from The Conversation under a Creative Commons license. Read the original article.

Explainer: what is energy security, and how has it changed?


Samantha Hepburn, Deakin University

The idea of energy security has been at the centre of much policy debate recently. The federal government defines energy security as the adequate supply of energy across the electricity, gas and liquid fuel sectors.

But this notion has become outdated, following the spate of electricity blackouts that have occurred in the past few years. The concept of energy security is now increasingly synonymous with resilience: responding to problems quickly and avoiding power outages.




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To be secure, the national energy market must ensure a sufficient supply of electricity at an affordable price and be able to respond to major disruptions. Being “energy secure” in this context now means having a backup plan. Unfortunately, Australia doesn’t.

All about oil

Historically, energy security was purely about oil supply. It evolved as a policy response to the 1973 Arab oil embargo. At the time, the aim was to coordinate among the industrialised countries if supply was disrupted, to avoid future supply problems and to deter exporters from using resources as a strategic weapon. Four key developments emerged from the embargo:

  • the International Energy Agency (IEA), whose members are the industrialised countries;

  • strategic stockpiles of oil, including the US Strategic Petroleum Reserve;

  • continued monitoring and analysis of energy markets and policies; and

  • energy conservation and coordinated emergency sharing of supplies in the event of a disruption.

Australia is not ‘secure’

When Australia joined the IEA in 1979, it was a net exporter of oil and was therefore exempt from the requirement to stockpile liquid fuel. Since this time, however, Australia’s oil production has peaked and is now in decline.

Reasons for this are various but include the reduction in oil refining capacity and significant increases in reliance on imported oil products.

In 2012 Australia became non-complaint with the IEA requirement that all members maintain oil stocks equivalent to at least 90 days of the previous year’s daily net oil imports.

In contrast with many other IEA members, Australia does not have a public (or government-owned) stockpile of oil and has instead relied on commercially held stocks. Currently, Australia has an aggregated fuel reserve of roughly 48 days, including about 22 days’ supply of crude oil, 59 days of LPG, 20 days of petrol, 19 days of aviation fuel, and 21 days of diesel.




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This lack makes Australia very vulnerable in a crisis – 98% of our transportation relies on liquid fuel, as do all of our major defence platforms. An extended disruption means our economy, policy force and army could cease to function.

While the federal government intends to return to compliance by 2026, our ongoing failure to understand and respond to a changing environment has resulted in us becoming, at least in the context of liquid fuel, energy “insecure”.

Are we ready for a new approach?

The modern energy landscape is complex, and energy security is a much broader and more dynamic concept than it was thirty years ago. Public expectations have also evolved. Australia must address a multitude of new challenges that include: climate change, integrating renewable energy, rising peak demand, rising domestic gas prices and a raft of new geopolitical rivalries.

In many parts of the world, mechanical and analogue systems traditionally powered by oil-products, have been replaced with automated and networked systems that run on electricity. As a result, the number of digitally connected devices has grown from 400 million in 2001 to in excess of 25 billion in 2018.

These changes make electricity and natural gas, in addition to oil, key supports of many facets of society. They ensure that the modern world is completely dependent on energy generation. Within this context, resilience is a critically important requirement.

Future energy systems, responsive to this enlarged concept of energy security will therefore look very differently. Large fossil fuel and synchronous generators will be replaced by a clean electricity system composed of small-scale, clean asynchronous generators. It will mix large renewable projects (which will mean extending the physical transmission network) with distributed energy generation (for example, from rooftop solar), and the network will require new systems to ensure coordination and stability.

Renewable energy is an important component of energy security but it works differently to fossil fuels. For example, inertia functions differently. Inertia is the capacity of a power system to respond to unexpected shocks, and its ability to react and stabilise the system’s balance.

Inertia slows down the rate at which frequency changes after a disruption in the grid, such as the failure of a power plant or a transmission line. Inertia has traditionally been provided by fossil fuel generators. However, within a mixed energy framework, renewables will provide synthetic inertia. For example, modern wind turbines can use the kinetic energy stored in the generator and blades to be responsive during grid stress. This can provide an efficient injection of power into the grid where it is required, and the delivery can be flexibly controlled to suit regional grid conditions. New storage technologies will, however, need to be incorporated into networks early so their application in practice can be understood.

These are all responses to a new understanding of energy security. Today, what is essential to the definition of energy security is not just an adequate supply of energy at an appropriate price but an adequate supply of sustainable, resilient energy at an appropriate price, which is responsive to the demands of a decarbonising economy.




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In light of this, energy security is perhaps even more crucial in our modern world than it was back in 1973. Understanding the evolving meaning of energy security means we are better equipped to comprehend the different ways in which our global interconnection can make us vulnerable.

We need to minimise risk and reduce exposure. We need to imagine what a secure energy framework of the future looks like. We need energy policy that is more responsive to the social, economic and environmental demands of modern Australia.The Conversation

Samantha Hepburn, Director of the Centre for Energy and Natural Resources Law, Deakin Law School, Deakin University

This article is republished from The Conversation under a Creative Commons license. Read the original article.

Australia’s deal with Timor-Leste in peril again over oil and gas



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The central element of the Timor Sea dispute seems far from resolved.
AAP/Caroline Berdon

Rebecca Strating, La Trobe University and Clive Schofield, University of Wollongong

In April, Australia and Timor-Leste reached agreement on their maritime boundaries in the Timor Sea. This resolved a longstanding source of contention between them.

The potential benefits of this historic breakthrough are now in peril, because the critical issue of how the shared oil and gas of the Timor Sea are to be developed remains in dispute.

Breakthrough on maritime boundaries

Australia and Timor-Leste’s boundary agreement was achieved thanks to a unique dispute resolution process: the United Nations Compulsory Conciliation Commission. The commission was initiated under the United Nations Convention on the Law of the Sea (UNCLOS).

Because both Australia and Timor are parties to UNCLOS, Timor was able to invoke a compulsory conciliation process. It was the first time this has occurred.

Australia was at first reluctant to engage in the UNCC process. It lost its argument that the commission did not have the competence to negotiate the dispute. Australia did then engage with the process in good faith.

Indeed, the success of the UNCC was in large part due to the willingness of both parties to participate in good faith. A series of “confidence building” measures in 2016 helped build trust between the states.

By January 2017, Australia had agreed to terminate the existing Certain Maritime Agreement on the Timor Sea (CMATS). In return, Timor-Leste dropped two international legal cases it had initiated against Australia.

The process set up a neutral commission to run facilitated negotiations over a year, although sessions ultimately ran from July 2016 to February 2018. While participation in the conciliation was compulsory for the parties, it differed from an arbitration process, such as an international court, because the commission’s recommendations could only be non-binding. A crucial aspect of these facilitated negotiations were the discussion papers that allowed both states to think creatively about solving the dispute.

Ultimately, the process succeeded in its primary aim of helping Australia and Timor-Leste to resolve their long-running dispute in the Timor Sea. The breakthrough came in July 2017, when the countries outlined to the commission the points on which they were willing to compromise.

On August 30, an agreement on maritime boundaries, revenue split and an action plan for their engagement in the joint venture was reached. The maritime boundary treaty was signed on April 6 2018.

Deadlock over downstream developments

On May 9 2018, the commission, to little media fanfare, released its report and recommendations on the conciliation.

The report provides valuable insights into the ongoing disputes over development of the Greater Sunrise complex of gas fields located in the Timor Sea – a critical issue for Timor-Leste’s future economic security and development.

Australia and Timor-Leste asked the UNCC to extend its mandate to include the development concept for Greater Sunrise. This extended the sessions beyond the initial one-year period.

Despite its significant success in helping the states agree on maritime boundaries in the Timor Sea, the report indicates little progress was made on the question of how Greater Sunrise gas would be processed.

Crucially, Timor-Leste’s lead negotiator and newly re-installed prime minister, Xanana Gusmao, has consistently advocated a pipeline to the south coast of Timor-Leste to support the development of a Timorese oil and gas processing hub.

The Sunrise Venture Partners (SVP), led by Woodside, have preferred either a floating platform or, more recently, back-filling an existing processing plant in Darwin. Australia, for its part, describes itself as “pipeline neutral”, but supports the decision of the commercial venture partners.

To address this issue, the SVP was invited to participate in the commission process. The report suggests very little progress has been made between the three parties – Australia, Timor-Leste and the SVP – on this dispute.

The commission considered two development concepts, based in Darwin and Timor Leste respectively. According to Gusmao, the pipeline to Timor-Leste is “non-negotiable”. Yet, there is little impartial evidence that this concept would be commercially viable.

In an effort to find a way out of the impasse, the commission employed an independent consultant from a London-based firm, Gaffney, Cline & Associates, to comparatively analyse the two development concepts. The specialist’s assessment, provided in Annexe 27 of the report, said that for a Timorese processing hub to achieve an acceptable return, the Timorese government or another funder would have to subsidise the project to the tune of US$5.6 billion. This is about four times Timor-Leste’s annual GDP, or more than one-third of its Petroleum Wealth Fund.

A letter from Gusmao leaked to the commission in February 2018 – after the last round of UNCC meetings – accused the commission of lacking impartiality, preferring the Darwin concept to the Timor-Leste concept.




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The letter also rejected the comparative analysis provided by the independent expert. It accused the technical expert of not having the “appropriate experience or understanding from working in Timor-Leste” and of having failed to consider the socioeconomic development benefits of the Timorese proposal.

In contrast, the commission’s report noted that Gaffney, Cline & Associates had previously worked for Timor-Leste, but that Australia had not objected to the appointment.

The report suggests that the three parties – Australia, Timor-Leste and the SVP – are no closer to agreement on how to process Greater Sunrise gas.

A looming threat to Timor-Leste’s development

The need to resolve the development issue is increasingly urgent. Timor-Leste is rapidly running out of revenue and development options. Over 90% of its annual budget comes from revenues from oil fields that are expected to be depleted within the next five years. Economically, Timor-Leste does not appear to have a plan B if its strategy for bringing gas to the southern shores of Timor-Leste fails.

Given its precarious situation, one might wonder why Timor-Leste is taking what appears to be a risky approach to this issue, and about what kind of agreements it has sought with other actors or states. In any case, the central element of the Timor Sea dispute seems far from resolved.

The Conversation

Rebecca Strating, Lecturer in Politics, La Trobe University and Clive Schofield, Professor and Challenge Lead, Sustaining Coastal and Marine Zones, University of Wollongong

This article was originally published on The Conversation. Read the original article.

The government could be boosting the budget bottom line with a change to how it taxes gas


Diane Kraal, Monash University

Resources usually give the budget a healthy boost in economic boom times but the government could be reaping more revenue if it changed the way it taxes gas projects, my new modelling shows.

A small change in the method for valuing gas would increase revenue from the petroleum resource rent tax by US$15.5 billion to 2030, compared to the current US$5 billion to 2030.

I modelled what would happen with an alternative but accepted method to tax the revenue from Australia’s four largest gas projects in Western Australia – Inpex’s Ichthys, Woodside Petroleum’s Pluto and Chevron’s Wheatstone and Gorgon. The method is called “net back” and it calculates back from a gas market price to get the gas transfer price, in a similar approach to that currently used for state gas royalties. It netted an average of A$1 billion per annum in Queensland and Western Australia from 2012 to 2016.




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The production capacity of the four largest projects is 38.3 million tonnes of gas per annum (about 44% of Australia’s natural gas). But these projects currently raise no petroleum resource rent tax and scant income tax. This gas is earmarked for export and little is reserved for domestic consumption.

A small tax regulation change is required

When businesses shifts or transfers gas between different stages (upstream to downstream) of a project they are required by petroleum resource rent tax regulation to use a combination of methods (“cost plus” and “net back”) to value gas at the transfer point. My alternative of the net back method alone, uses the LNG market price from which costs are deducted back to the point, prior to gas being processed into liquid form.

My submissions to both Treasury, and the Senate inquiry into tax avoidance for the offshore gas industry, explain how the current gas transfer pricing method can be legally manipulated by gas operators. For instance, timing differences in recognising capital or operating costs.

The petroleum resource rent tax regulations prescribe an arbitrary gas valuation method for integrated gas projects, which devalues the transfer price of gas, meaning less revenue for the government.

The current method is not a transparent approach for businesses to use to value gas on its transfer from upstream to downstream. It incentivises tax minimisation through easily manipulated calculations.

Since September 2017 the Turnbull government has yet to respond to the Treasury inquiry’s interim report on gas. The Senate inquiry report has also been delayed.

Another variation to increase revenue along with the “net back” method would be to shift the gas taxing point from just before liquefaction, to after the gas-to-liquid process, at what’s called the “custody transfer meter”. The price per the metered volumes is accepted by the buyer and the seller of gas as the basis for a transaction.




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Australia needs to follow in the footsteps of countries like the Netherlands, which has already reformed its inequitable, regulated gas pricing to market-linked pricing. The Netherlands government changes, which increased tax revenues, mainly targeted their current (not future) Groningen gas field, partly owned by Shell and Exxon.

Any change to resource taxing will bring the usual chorus of concern about sovereign risk so often heard in Australia when tax reform is raised. However sovereign risk concerns overt changes, such as nationalisation of resources, certainly not regulatory changes to promote transparency in taxation.

Changes to the petroleum resource rent tax have been part of pre-budget negotiations between the Turnbull government and certain independent senators. However these changes will only affect new projects that will not start for at least 10 to 15 years, so the expected revenue will have no impact on next week’s budget.

The current petroleum resource rent tax regulations prescribe an arbitrary gas valuation method for integrated gas projects. It devalues the transfer price of gas, meaning less revenue for government.

The ConversationAs a first step, the government should reform tax regulation to the net back method for existing projects. This change could easily be part of next week’s federal budget.

Diane Kraal, Senior Lecturer, Business Law and Taxation Dept, Monash Business School, Monash University

This article was originally published on The Conversation. Read the original article.

The government’s new gas deal will ease the squeeze, but dodges the price issue



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The government has so far refrained from putting a legal limit on LNG leaving our shores.
Ken Hodges/Wikimedia Commons, CC BY

Samantha Hepburn, Deakin University

The deal signed this week by the federal government and the nation’s biggest three gas producers will ease Australia’s gas supply squeeze, but it will do nothing to address the current high prices.

Under the contract, Shell, Origin and Santos have agreed to supply more domestic gas to avert the predicted shortfall for 2018.

In so doing, the government seemingly sidestepped the need to trigger its own powers to forcibly restrict gas exports.

Sighs of relief all round, then. But here’s the thing: neither the new deal, nor the legislation that governs export controls, actually addresses the issue that is arguably most important to consumers – the high prices Australians are paying for their gas.


Read more: To avoid crisis, the gas market needs a steady steer, not an emergency swerve


Australia has vast gas resources, and yet somehow we find ourselves with rising prices and a forecast shortfall of up to one-sixth of demand in the east coast gas market in 2018.

This is partly understandable, given that rising global demand has fuelled a lucrative export market. The primary destination is Asia, which will assume more than 70% of global demand. In geographical terms this puts Australian exporters in a very strong position, and by 2019 Australia is forecast to supply 20% of the global market – up from 9% today.

However, the strong global demand for liquefied natural gas (LNG) does not in itself provide the full explanation for rising gas prices in Australia’s east coast gas market. This is caused by a weak regulatory environment.

Policy levers

The Australian Domestic Gas Security Mechanism, which took effect in July 2017, gives the federal resources minister the power to restrict exports of LNG in the event of a forecast shortfall for the domestic market in any given year.

This five-year provision was designed as a short-term measure to ensure domestic gas supply. If triggered, it would require LNG exporters either to limit their exports or to find new sources of gas to offset the impact on the domestic market.

To trigger the mechanism, the minister must follow three steps:

  1. formally declare that the forthcoming year has a domestic shortfall, by October 1 of the preceding year;

  2. consult relevant market bodies, government agencies, industry bodies and other stakeholders to determine their view on the existing and forecast market conditions; and

  3. make a determination by November 1 on whether to implement the measures.

Any export restriction implemented under the ADGSM would potentially apply to all LNG exports nationwide, including those from areas with no forecast gas shortage, such as Western Australia. The minister does have the ability to determine the type of export restriction that is imposed. An unlimited volume restriction does not impose a specific volumetric limitation and can be applied to LNG projects that are not connected to the market experiencing the shortfall. A limited volume restriction imposes specific limits on the amount of LNG that may be exported and may be applied to an LNG project that is connected to the market experiencing the shortfall.

Non-compliance with the export limits imposed on gas projects would have a range of potential consequences for gas companies. These include revocation of export licence, imposition of different conditions, or stricter transparency requirements.

The new deal

The agreement signed with the big three gas producers effectively relieves the government of the need to consider triggering the ADGSM. As such, 2018 has not been officially declared to be a domestic shortfall year.

But the agreement is not grounded upon any specific legislative provision. Therefore it is essentially only enforceable against the gas companies that are parties to it. And in accordance with the private terms and conditions that those companies agree to.

The broad agreement is that contractors will sell a minimum of 54 petajoules of gas into the east coast domestic market (the lower limit of the forecast shortfall) and keep more on standby in case the eventual shortfall turns out to be bigger.

But what about prices?

The deal contains no specific provision regarding domestic pricing. So, although there will be more gas in the domestic market, this does not necessarily mean that the current high prices will drop.

In the short term, the provision of additional supply may curtail dramatic increases in domestic gas prices. However, the gas deal does not address the core problem, which stems from our enormous commitment to LNG exports and the connection of domestic gas prices to the global energy market.

Indeed, the commitments are so great that many LNG operators have had to take conventional gas from South Australia and Victoria to fulfil their export contracts. This has put significant pressure on domestic prices.

The unequivocal truth is that gas prices were much cheaper before the LNG export boom. The only way to achieve some level of protection for domestic gas prices is to implement stronger regulatory controls on the export market. This should involve taking account of the public interest when assessing whether export restrictions should be imposed.

The ADGSM legislation does not incorporate any explicit public interest test, despite the fact that gas is a public resource in Australia and gas pricing is a strong public interest issue.

Compare that with the United States, where public interest is a key principle in assessing whether to approve any LNG exports to countries with no US free trade agreement (such as Japan). Public interest tests in the United States involve a careful determination of how exports will affect domestic supply and the potential impact that a strong export market will have upon domestic prices.


Read more: Want to boost the domestic gas industry? Put a price on carbon


The Australian government’s decision to broker a deal with gas suppliers, rather than extend the long arm of the law, means that regulators will need to keep a close eye on the gas companies to check that they are holding up their end of the bargain.

That job will fall to the Australian Competition and Consumer Commission (ACCC). ACCC chair Rod Simms this week warned gas suppliers to ensure that their “retail margins are appropriate”.

The ConversationIn the absence of any explicit rules compelling gas producers that signed the deal to provide clear and accurate information and adopt stronger transparency protocols, the ACCC may face a very onerous task.

Samantha Hepburn, Director of the Centre for Energy and Natural Resources Law, Deakin Law School, Deakin University

This article was originally published on The Conversation. Read the original article.

Big gas shortage looming, but government stays hand on export controls



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Josh Frydenberg, Scott Morrison and Malcolm Turnbull at a press conference announcing the possibility of a serious gas shortfall.
AAP/Mick Tsikas

Michelle Grattan, University of Canberra

The government has issued another warning to gas producers but held off pulling its export control trigger, despite two new reports warning of potential severe local supply shortages.

The Australian Energy Market Operator (AEMO) and the Australian Competition and Consumer Commission (ACCC) have both pointed to looming shortfalls in the eastern Australian market in projections released on Monday.

AEMO said supply remained tight for 2018 and 2019, with a shortfall risk for 2018 of between 54 and 107 petajoules (PJs); for 2019 it was between 48 and 102 PJs. This was in the context of total expected demand for domestic gas of about 642 PJs in 2018 and 598 PJs the following year.


Read more: Our power grid is crying out for capacity, but should we open the gas valves?


The ACCC projected a shortfall in the east coast market of up to 55 PJs in 2018 which could be as much as 108 PJ if demand were above expectations.

The government earlier this year foreshadowed using export controls to force more local supply but so far is holding back from implementing them – despite calls from the opposition to do so. It hopes the threat will be enough.

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Malcolm Turnbull told a news conference, held with Treasurer Scott Morrison and Energy Minister Josh Frydenberg, that the reports showed the shortages in the east coast domestic market would be considerably greater than estimated six months ago. The 110 PJs estimate was more than three times an earlier estimate, he said.

Turnbull said that following the announcement about export controls more gas had come into the local system from the exporters “but it has clearly not been sufficient to date”.

“The recent rises in the cost of gas are the single biggest factor in the current rise in electricity prices,” he said.

“More expensive gas has huge implications for industry and for struggling families but it feeds directly into the electricity market.”

He condemned the “comprehensive failure” by state governments to develop their own gas resources. Queensland was “an honourable exception” but NSW and Victoria needed to act, as did the Northern Territory. He would be contacting the premiers and the NT chief minister to urge they do so.


Read more: Memo to COAG: Australia is already awash with gas


He said the government had already had discussions with the executives of the big gas exporting companies and “we’ll be speaking with them again this week”. Turnbull spoke by phone on Monday with Origin Energy, Santos and Shell.

“We expect them to demonstrate to us what they have already indicated in meetings and in writing – that they will ensure that there is not a shortage of gas next year on the east coast.

“If they are able to do that, and to the satisfaction of the ACCC, then the foreshadowed export control mechanism will have done its work.

“But we will continue to hold that mechanism ready to go … so that if we are not able to receive the assurances from the industry to our satisfaction and that of the ACCC, then we will impose those export controls.”

Turnbull said the government’s commitment was “to ensure there is not a shortfall in the domestic market in 2018”.

The ConversationBill Shorten tweeted: “Turnbull just admitted a huge gas shortfall. As I’ve been saying: it’s time to pull the trigger on export controls. Why does he refuse?”

https://www.podbean.com/media/player/4vmna-742f96?from=site&skin=1&share=1&fonts=Helvetica&auto=0&download=0

Michelle Grattan, Professorial Fellow, University of Canberra

This article was originally published on The Conversation. Read the original article.

We don’t have a gas shortfall worth worrying about


Dylan McConnell, University of Melbourne

Australia was warned earlier this year that a shortage of gas could create an energy crisis. A report from the Australian Energy Market Operator (AEMO) suggested a shortfall could occur in 3 of the next 13 years. The Conversation

This report was widely reported in the national media, with sensational headlines like “AEMO warns of blackouts as gas runs out”.

A couple of weeks ago, in a dramatic intervention, Prime Minister Malcolm Turnbull declared that there was a shortage of gas supplies for eastern Australia and that certain restrictions may be placed on gas exports.

But do we really need “more gas supply and more gas suppliers”? In a report published today, my colleague Tim Forcey and I review AEMO’s initial report and its results and recommendations. Our work finds there is a shortage of “cheap” gas, but not a gas supply “shortfall”. Moreover, high gas prices combined with falling renewable and storage costs mean that there are cheaper options than developing new gas resources.

What gas shortfall?

AEMO forecast of electricity generated by fuel source, showing AEMO’s forecast supply gap as a thin red line at the top of the stack.
Author

The AEMO report suggests that eastern Australia face a shortfall in 3 of the next 13 financial years – 2018-19, 2020-21 and 2021-22. The largest gap modelled by AEMO is equal to only 0.19% of the annual electricity supply, or 363 gigawatt hours.

In gas supply terms, this is equivalent to only 0.2% of the annual gas supply. But AEMO’s modelling considers a range of possible scenarios, with a variation of roughly plus or minus 5%, far larger than the possible shortfall.

Just 11 days after the report warning of a supply gap, AEMO published updated electricity demand forecasts. In this update, AEMO reduced its forecast electricity demand by roughly 1%. This reduction in demand is more than four times greater than the largest forecast shortfall.

A day later, Shell announced it would proceed with Project Ruby, a gas field with 161 new wells. This was not included in the AEMO modelling process.

Alternatives to gas

Gas has historically been characterised as a transition fuel on the pathway to a zero-emissions power system. The falling costs of renewable energy and storage technologies combined with rising gas costs means this pathway and may indeed be a detour, particularly when taking into account Australia’s climate commitments.

This is also a sentiment increasingly reflected by the industry, with gas producer AGL suggesting that:

the National Electricity Market […] here in Australia could transition
directly from being dominated by coal-fired baseload to being dominated by storable renewables.

Gas generation generally falls into two categories: open cycle gas turbines (OCGT) and combined cycle gas turbines (CCGT). These two technologies effectively play different roles in the energy sector. Open cycle turbines are highly flexible, and are used occasionally over the year to provide peak capacity. Combined cycle turbines, on the other hand, operate continuously and provide large amounts of energy over a year.

Each of these technologies is now under competitive threat from renewable generation and storage. Flexible capacity can also be provided by energy storage technologies, while bulk energy can be provided by renewable energy. These are compared below.

Energy: renewables vs gas

The chart below compares the cost of providing bulk energy with gas and renewable technologies. We’ve represented the price of new CCGT, PV (which stands for photovoltic solar) and wind as the cost of providing energy over the lifetime of the plant.

The other two gas generation costs illustrated, CCGT and Steam, represent the cost of energy from existing plants, at their respective thermal efficiencies. The steam thermal efficiency is similar to that of a highly flexible open cycle gas turbine.

Surprisingly – and depending somewhat on gas price and capital cost assumptions – new renewable energy projects provide cheaper energy than existing gas generators.

Comparison of energy cost from new and existing gas with new renewable energy generation. The range of solar (PV) and wind costs reflect different capital cost assumptions, while the range of gas costs reflects gas price assumptions. CCGT refers to Combined Cycle Gas Turbine.
Author

Flexible capacity: storage vs gas

The next chart compares the cost of providing flexible capacity from gas and storage technologies (again, taking the cost over the lifetime of the plant).

In this analysis we compare the cost of capacity from OCGT with that from diesel and various storage technologies, including battery and Pumped Hydro Energy Storage (PHES). As can be seen, storage technologies can compete with OCGT in providing flexible capacity, depending on technology and capital cost.

Comparison of flexible capacity cost from gas (OCGT), diesel and storage technologies generation, including battery and Pumped Hydro Energy Storage (PHES) . The range of costs reflect different capital cost assumptions.
Author

Another option, not shown here, is demand response. This is the strategy of giving consumers incentives to reduce their energy use during critical times, and is cheaper again.

What is clear is AEMO’s forecast gas shortfall is very small, and that it may have already been made up by revised demand forecasts and new gas field developments. But the question of how Australia should deal with any future shortfall invites a larger debate, including the role of gas in our electricity system, and whether the falling costs of renewable energy and storage technology mean we’ve outgrown gas.


The short-lived gas shortfall: A review of AEMOs warning of gas-supply ‘shortfalls’ was prepared by Tim Forcey and Dylan McConnell.

Dylan McConnell, Researcher at the Australian German Climate and Energy College, University of Melbourne

This article was originally published on The Conversation. Read the original article.

Budget 2017: government goes hard on gas and hydro in bid for energy security


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Gas infrastructure and exploration attracted the lion’s share of new energy announcements in the 2017 federal budget.
Sean Heatley/Shutterstock.com

Hugh Saddler, Australian National University; Alan Pears, RMIT University; Roger Dargaville, University of Melbourne, and Tony Wood, Grattan Institute

The budget contains several measures designed to boost energy security, including: The Conversation

  • A$90 million to expand gas supplies, partly through increased unconventional gas exploration

  • a potential Commonwealth buyout of an expanded Snowy Hydro scheme

  • up to A$110 million for a solar thermal plant at Port Augusta

  • monitoring of gas and electricity prices by the Australian Competition and Consumer Commission.

Below, our experts react to the measures.

Gas price problem far from solved

Roger Dargaville, Deputy Director, Melbourne Energy Institute, University of Melbourne

The budget contains a broad range of funding in energy-related areas, with a significant focus on gas resources, making A$78 million available for onshore unconventional gas exploration and reform in the gas markets, and A$7 million for studies into new gas pipelines to South Australia, from both Western Australia and the Northern Territory.

Interestingly, there is A$110 million in equity available (but not guaranteed) for a solar thermal plant in Port Augusta. And most notably, the government has proposed purchasing the Snowy Hydro Scheme from the New South Wales and Victorian governments, ensuring that the scheme stays in public hands.

The budget also includes A$13 million for CSIRO to improve energy forecasting tools, and A$8 million for the ACCC to investigate consumer energy pricing issues.

Overall, the budget highlights the government’s desire to do something about gas prices, but offers little to make a significant difference to a very difficult problem. Gas market reform and new pipelines are unlikely to reduce the exposure of the domestic market to price rises driven by international exports.

Importantly, there is little new funding in the budget directly relating to reducing carbon emissions and meeting the pledges made in the Paris Agreement (a 26-28% emission reduction relative to 2005 levels by 2030). Also noteworthy is the fact that funding for the carbon capture and storage flagship ceases in 2018-19.

‘On energy this budget is small fry’

Tony Wood, Energy Program Director, Grattan Institute

The budget does little more on energy than endorse the government’s deal with Senator Nick Xenophon on corporate tax cuts, complemented by modest commitments to energy security, more gas and better regulation.

Government facilitation of gas development and beefing up the energy capability of the Australian Energy Regulator and the ACCC are simple logic, and the one- off payment to pensioners to help with electricity bills will be welcomed by them.

Major public funding for further feasibility studies is a little more questionable. If the gas crisis can’t galvanise support from pipeline companies and gas consumers for pipelines, why would governments reach a different conclusion?

And finally, one can only speculate as to why the federal government is contemplating buying out the NSW and Victorian governments’ share of Snowy Hydro. Presumably it is because the feds are concerned about securing support for the proposed expansion.

In summary, on energy this budget is small fry ahead of major policy decisions that rest on the forthcoming Finkel Review of the National Electricity Market next month, and the climate change policy review later in the year.

A step towards radical energy reform?

Hugh Saddler, Honorary Associate Professor, Centre for Climate Economics and Policy, Australian National University

Few announcements in the budget speech are more emblematic of complete policy reversal than the announcement that the Commonwealth would buy the shareholdings in Snowy Hydro Limited of the governments of NSW (58%) and Victoria (29%), to add to the 13% currently owned by the Commonwealth. This comes almost exactly 11 years after Prime Minister John Howard, responding to vociferous public opposition, pulled the plug on plans by all three governments for a public float of their entire shareholdings. What is more, Treasurer Scott Morrison has now announced that, once owned by the Commonwealth, Snowy Hydro would remain in public ownership.

This announcement of course accompanies the government’s Snowy 2.0 proposal, for a fivefold increase in the Snowy scheme’s current 500 megawatt pumped storage capacity (at Talbingo). This was used, after commissioning in 1974, to allow inflexible coal fired power stations to operate with constant output levels day and night, but is now almost never used. This presumably reflects commercial decisions by Snowy Hydro, as it trades in the National Electricity Market.

The rationale for Snowy Hydro 2.0 is to facilitate operation of a grid with a high share of renewable generation, by smoothing out variations in wind and solar supply. Does this announcement mean that the government envisages moving away from a strictly commercial approach to using the assets of the Snowy scheme? Is this a first step towards radical restructuring, or even dismantling, of the National Electricity Market?

Stronger legislation needed

Alan Pears, Senior Industry Fellow, RMIT University

The detailed A$265 million energy package includes a number of useful measures to strengthen the weak regulatory culture of the energy sector that has allowed our energy crisis to evolve. But it is still limited: strong legislative reform and active support of emerging competitors will also be needed. It is a modest investment compared with recent multibillion-dollar energy cost increases. If it is successful, it will deliver vary large net benefits to the economy by limiting energy price increases. Unfortunately, past efforts to fix the energy situation have largely failed to deliver real outcomes: we need clear objectives for outcomes, and a mechanism to implement contingency strategies if they are not achieved.

In a context of increasing urgency for stronger action on climate, and the reality that the global “burnable carbon” budget is very limited, investment to encourage more gas development seems misplaced. More emphasis on energy efficiency, renewables and smart energy systems would make much more sense. Energy efficiency already saves billions on energy costs and could save much more, while renewable energy is becoming cheaper than fossil fuel alternatives. They also help to achieve our climate targets. And fossil fuels are responsible for almost three-quarters of Australian emissions, so we need strong action to meet our international obligations.

The extension of the A$20,000 tax write-off for small business spending on equipment is a measure that, at least for small businesses, offsets a significant barrier to investment in energy efficiency. Firms will also be able to continue to claim the write-off to improve the economics of investments in on-site renewable energy and storage. Of course, the problem still remains for spending over A$20,000 by small businesses, and for larger businesses.

The energy security plan, which includes funding for ACCC to police energy industry behaviour is only a small step towards fixing the disastrous failures of energy policy and a transition to a 21st century energy policy framework. Much more will need to be done.

Hugh Saddler, Honorary Associate Professor, Centre for Climate Economics and Policy, Australian National University; Alan Pears, Senior Industry Fellow, RMIT University; Roger Dargaville, Deputy Director, Melbourne Energy Institute, University of Melbourne, and Tony Wood, Program Director, Energy, Grattan Institute

This article was originally published on The Conversation. Read the original article.