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.




Read more:
PRRT explained: why aren’t we benefitting from the resource tax?


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.




Read more:
Senate inquiry told zero tax or royalties paid on Australia’s biggest new gas projects


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.

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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.

San Bruno Disaster: Latest News


There are now seven confirmed deaths following the San Bruno gas explosion disaster in San Francisco. Sadly, the death toll may rise with six people still missing. 52 people were injured in the explosion and fire, with 37 homes destroyed and another badly damaged.