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Posts from the ‘Energy’ Category

Electric cars won’t save the planet without a clean energy overhaul – they could increase pollution

The Conservation 3 June 2019

Several countries – including France, Norway and the UK – have plans to phase out cars powered by fossil fuel before 2050, to reduce air pollution and fight climate change. The idea is to replace all conventional vehicles with electric vehicles (EVs). But this is unlikely to help the environment, as long as EVs are charged using electricity generated from the same old dirty fossil fuels.

Global electricity consumption from EVs is estimated to grow to 1,800TWh by 2040 – that’s roughly five times the current annual electricity use of UK. Using data from the UK as a benchmark, this would amount to an extra 510 megatonnes of carbon emissions coming from the electricity sector worldwide. But this massive impact could be drastically reduced if electricity is generated entirely from renewable energy sources, instead of fossil fuels.

A growing problem

To put things into perspective, 510 megatonnes is about 1.6% of the global carbon emissions in 2018. And while this may not seem like a big amount, the Intergovernmental Panel on Climate Change (IPCC) recommended that carbon emissions are reduced to net zero by 2050, to limit the average global temperature rise to 1.5°C above the pre-industrial era. So a 1.6% increase in carbon emissions is significant, and possibly catastrophic.

Perhaps this increase would be negated by the decrease in emissions, which results from phasing out polluting vehicles. But reducing global carbon emissions is not easy – in fact, emissions reached an all time high in 2018, despite the highest ever uptake of renewable energy.

Though their emissions are much lower than that of conventional cars, EVs also do generate carbon dioxide during the energy intensive manufacturing process – as do renewable energy technologies themselves.

Supply and demand

Another major issue with EVs is their impact on the availability, production and supply of rare earth metals and other scarce natural elements. EVs and their batteries contain precious metals such as lithium and cobalt. Scarcity of cobalt is already threatening the production of EVs, and alternative designs that don’t rely on scarce elements are currently being explored by car manufacturers.

This means that it’s critical to expand recycling plants dedicated to processing metals and other scarce elements for reuse. Also, detailed plans on retrofitting of conventional vehicles to turn them into EVs are needed – it’s simply not feasible to dump all conventional vehicles into landfill sites, in a scenario where they are replaced by EVs.

There are further issues with EVs that must be dealt with, if they’re to help reduce global emissions and prevent climate disaster. People are likely to charge their EVs during evening hours, after they come home from work. As more people start to use EVs, the load on the energy grid is likely to peak in the evening. And this could cause problems for electricity distribution and transmission systems, at a community or city level.

These systems may need an upgrade. Or, energy suppliers could introduce a time-of-use tariff, which is higher during peak hours and lower during off-peak times, when there’s less demand for electricity. This would encourage consumers to charge their EVs during off-peak hours.

Smart charging is another possible solution: the idea is to charge more vehicles when local electricity production through renewables such as wind and solar is high, and reduce the charging when local renewables aren’t producing enough electricity. EVs charging time can be matched with peak renewable power production using smart systems and artificial intelligence to balance the local electrical grid.

Overcoming obstacles

The high cost of EVs and the lack of available charging stations are further obstacles that the Oxford Institute for Energy Studies has identified for the mass uptake of EVs. This could create a chicken and egg scenario: the cost of EVs may not go down unless they are mass produced, and they may not be mass produced unless the costs go down. The same goes for the installation of charging stations – authorities will need foresight to recognise that extra charging stations should be built for when EV uptake increases.

Governments can help prevent these issues by subsidising EVs or providing financial incentives for clean transportation – as has already been done in China. Even on a city level, authorities can encourage people to use less polluting vehicles such as EVs through taxes or special clean air zones, as is currently being done in London.

EVs have great potential to reduce pollution and give people a more sustainable way to get around – but electricity production must also be clean. It’s not wise to rely completely on scarce natural elements required for producing EVs and alternatives have to be explored. More recycling plants are needed to make the most out of rare elements and governments need to explore ways to ensure a smooth transition to cleaner transportation.

https://theconversation.com/electric-cars-wont-save-the-planet-without-a-clean-energy-overhaul-they-could-increase-pollution-118012

Labor Government could buy petrol, diesel, jet fuel and crude oil to prevent Australia running out

ABC, 28 February, 2019

A national stockpile of crude oil and fuel would be created if Federal Labor won the next election, Bill Shorten has said.

Key points:
Australia only has 18 days’ worth of car petrol and 22 days’ worth of diesel in reserve
Under an international agreement, importers of fuel should have 90 days’ worth stockpiled
Stocks have fallen over recent years, coinciding with oil refinery closures
Australia imports most of its crude oil and refined petrol, and only has a few weeks’ worth of fuel in reserve.

Stocks have been below mandated levels since 2012, raising fears of severe shortages in the event of conflict.

Opposition Leader Bill Shorten said creating a government-owned reserve was “an important national security measure”.

“It’s simple — to increase our national fuel security, we need to increase our national fuel stocks,” he said.

“As we’ve become more reliant on the global fuel market, we’ve also become more vulnerable to international risks and uncertainty.”

Major oil companies in Australia currently hold stocks, as do some large consumers, but there are no laws forcing them to do this.

At the end of December, Australia had 18 days’ worth of car petrol, 24 days’ worth of crude oil, 22 days’ worth of diesel and 107 days’ worth of aviation gas.

It is unclear which refined fuels would be held in reserve.

Mr Shorten said a consultation process would be established before the measure was introduced.

“We will consult with industry, oil and gas importers, refineries and with national security experts on the implementation of the government national fuel reserve.”

A number of domestic fuel refineries have closed over recent years.

Peter Jennings from the Australian Strategic Policy Institute previously said a lack of refineries and fuel farms meant Australia currently did not have the capacity to store large quantities of fuel.

“We would not be able to actually keep much in-country stock, because our fuel farms are now so decrepit and falling out of service that we wouldn’t have the capacity to store it all,” he said.

Energy Minister Angus Taylor said the policy could cost “tens of billions of dollars” and Labor needed to explain how it would be funded.

“Will it be a tax on all of us through the tax system, or will they slug us at the fuel bowser?” he said.

“We are not going to increase the price of fuel at the bowser when it seems clear Labor wants to do that one way or another.”

Liberal Senator Jim Molan has previously raised concerns about the situation, and the Coalition last year announced an inquiry into fuel reserves.

Earlier this week, Labor announced it would create a strategic fleet of merchant ships to help secure crucial supplies if a crisis emerged.

The vessels would be commercially operated but could be repurposed by the government in an emergency.

https://www.abc.net.au/news/2019-02-28/labor-announces-national-fuel-reserve-policy/10857562

The Biggest Saudi Oil Field Is Fading Faster Than Anyone Guessed

Bloomberg, 2 April 2019

It was a state secret and the source of a kingdom’s riches. It was so important that U.S. military planners once debated how to seize it by force. For oil traders, it was a source of endless speculation.

Now the market finally knows: Ghawar in Saudi Arabia, the world’s largest conventional oil field, can produce a lot less than almost anyone believed.

When Saudi Aramco on Monday published its first ever profit figures since its nationalization nearly 40 years ago, it also lifted the veil of secrecy around its mega oil fields. The company’s bond prospectus revealed that Ghawar is able to pump a maximum of 3.8 million barrels a day — well below the more than 5 million that had become conventional wisdom in the market.

“As Saudi’s largest field, a surprisingly low production capacity figure from Ghawar is the stand-out of the report,” said Virendra Chauhan, head of upstream at consultant Energy Aspects Ltd. in Singapore.

The Energy Information Administration, a U.S. government body that provides statistical information and often is used as a benchmark by the oil market, listed Ghawar’s production capacity at 5.8 million barrels a day in 2017. Aramco, in a presentation in Washington in 2004 when it tried to debunk the “peak oil” supply theories of the late U.S. oil banker Matt Simmons, also said the field was pumping more than 5 million barrels a day, and had been doing so since at least the previous decade.

In his book “Twilight in the Desert,” Simmons argued that Saudi Arabia would struggle to boost production due to the imminent depletion of Ghawar, among other factors. “Field-by-field production reports disappeared behind a wall of secrecy over two decades ago,” he wrote in his book in reference to Aramco’s nationalization.

The new details about Ghawar prove one of Simmons’s points but he missed other changes in technology that allowed Saudi Arabia — and, more importantly, U.S. shale producers — to boost output significantly, with global oil production yet to peak.

The prospectus offered no information about why Ghawar can produce today a quarter less than 15 years ago — a significant reduction for any oil field. The report also didn’t say whether capacity would continue to decline at a similar rate in the future.

In response to a request for comment, Aramco referred back to the bond prospectus without elaborating.

Lost Crown

The new maximum production rate for Ghawar means that the Permian in the U.S., which pumped 4.1 million barrels a day last month according to government data, is already the largest oil production basin. The comparison isn’t exact — the Saudi field is a conventional reservoir, while the Permian is an unconventional shale formation — yet it shows the shifting balance of power in the market.

Ghawar, which is about 174 miles long — or about the distance from New York to Baltimore — is so important for Saudi Arabia because the field has “accounted for more than half of the total cumulative crude oil production in the kingdom,” according to the bond prospectus. The country has been pumping since the discovery of the Dammam No. 7 well in 1938.

On top of Ghawar, which was found in 1948 by an American geologist, Saudi Arabia relies heavily on two other mega-fields: Khurais, which was discovered in 1957, and can pump 1.45 million barrels a day, and Safaniyah, found in 1951 and still today the world’s largest offshore oil field with capacity of 1.3 million barrels a day. In total, Aramco operates 101 oil fields.

The 470-page bond prospectus confirms that Saudi Aramco is able to pump a maximum of 12 million barrels a day — as Riyadh has said for several years. The kingdom has access to another 500,000 barrels a day of output capacity in the so-called neutral zone shared with Kuwait. That area isn’t producing anything now due a political dispute with its neighbor.

While the prospectus confirmed the overall maximum production capacity, the split among fields is different to what the market had assumed. As a policy, Saudi Arabia keeps about 1 million to 2 million barrels a day of its capacity in reserve, using it only during wars, disruptions elsewhere or unusually strong demand. Saudi Arabia briefly pumped a record of more than 11 million barrels a day in late 2018.

“The company also uses this spare capacity as an alternative supply option in case of unplanned production outages at any field and to maintain its production levels during routine field maintenance,” Aramco said in its prospectus.

Costly Strategy

For Aramco, that’s a significant cost, as it has invested billions of dollars into facilities that aren’t regularly used. However, the company said the ability to tap its spare capacity also allows it to profit handsomely at times of market tightness, providing an extra $35.5 billion in revenue from 2013 to 2018. Last year, Saudi Energy Minister Khalid Al-Falih said maintaining this supply buffer costs about $2 billion a year.

Aramco also disclosed reserves at its top-five fields, revealing that some of them have shorter lifespans than previously thought. Ghawar, for example, has 48.2 billion barrels of oil left, which would last another 34 years at the maximum rate of production. Nonetheless, companies are often able to boost the reserves over time by deploying new techniques or technology.

In total, the kingdom has 226 billion barrels of reserves, enough for another 52 years of production at the maximum capacity of 12 million barrels a day.

The Saudis also told the world that their fields are aging better than expected, with “low depletion rates of 1 percent to 2 percent per year,” slower than the 5 percent decline some analysts suspected.

Yet, it also said that some of its reserves — about a fifth of the total — had been drilled so systematically over nearly a century that more than 40 percent of their oil has been already extracted, a considerable figure for an industry that usually struggles to recover more than half the barrels in place underground.

https://www.bloomberg.com/news/articles/2019-04-02/saudi-aramco-reveals-sharp-output-drop-at-super-giant-oil-field

Saudi Aramco says climate lawsuits ‘could result in substantial costs’

Climate home news, 2 April, 2019

The world’s largest oil producer made more money than Apple and Alphabet combined last year, but the company sees litigation and clean tech as threats

Climate lawsuits, clean energy and electric cars pose threats to Saudi Aramco’s mammoth profits, according to a historic public disclosure on Monday.

The state oil producer netted $111 billion in 2018, more than tech giants Apple and Alphabet combined, it revealed in a bond prospectus.

It is aiming to raise funds to buy petrochemical company Sabic, as part of Saudi Arabia’s strategy to diversify its economy away from crude oil.

Saudi Aramco will continue to be “significantly impacted” by the international oil price, the document noted, warning: “Climate change concerns and impacts could reduce global demand for hydrocarbons and hydrocarbon-based products and could cause the company to incur costs or invest additional capital.”

Climate policies such as renewable energy mandates, carbon pricing and energy efficiency standards are expected to dampen demand for fossil fuels, it said. Trends in electrification of transport and clean energy prices will also be critical.

Meanwhile the company faces legal challenges over the role of its products in causing climate change. On 2 July 2018, US state Rhode Island sued oil and gas companies including Motiva, an Aramco subsidiary, for damages to coastal infrastructure. “Claims such as these could grow in number,” the note said, and “litigation could result in substantial costs”.

Peter Barnett, a climate lawyer with ClientEarth, agreed. “Climate litigation is gathering pace as citizens, cities, states and shareholders seek accountability for continued reliance on fossil fuels as the impacts of climate change are increasingly acutely felt,” he said. “As Saudi Aramco’s prospectus underscores, climate litigation is now of mainstream financial concern to fossil fuel-exposed companies and their investors.”

Saudi Aramco dismisses peak oil demand ‘hype’, touts carbon efficiency

These caveats did not stop agencies Fitch and Moody’s giving the company a solid A+/A1 credit rating, judging it a fairly safe bet for investors.

Saudi Aramco’s relatively low cost oil production makes it better placed than many competitors to weather the global transition to clean energy.

To meet the goal of the Paris Agreement to hold global warming below 2C, oil will ultimately need to be phased out. In the short term, though, climate models allow a budget for its continued role in the energy mix.

Less than 10% of Saudi Aramco’s capital spending to 2025 falls outside that 2C budget, analysts at Carbon Tracker judged in a 2018 ranking of 72 oil companies. That compares to 20-30% for Exxon Mobil, Total and Petrobas, or up to 60% for US-based Energen.

Saudi Arabia also wastes less energy in the extraction process and through gas flaring than most oil-producing countries, a 2018 study in Science found.

For all these advantages, Saudi Aramco is not immune from pressure on the sector to shift investment into renewable energy. At a conference in February, its chief Amin Nasser described a “worrying and growing belief among policy makers… and many others that we are an industry with little or no future”.

Crown prince Mohammed bin Salman in 2016 proposed floating part of the company on the stock exchange. If that ever comes to pass, it will only bring more scrutiny on its carbon and financial accounting.

Shareholder resolutions on climate change have become a regular feature of AGM season for publicly listed companies. Several oil majors have bowed to calls to disclose what the 2C warming limit means for their business. The next ask is to set emissions reduction targets in line with the Paris Agreement goal – a proposal Exxon Mobil is trying to block.

Another focus for activists is the mismatch between companies’ climate-friendly rhetoric and covert support for lobbying against climate policies. Shell revealed on Tuesday it was quitting the American Fuel & Petrochemical Manufacturers over its climate stance – but staying in the controversial American Petroleum Institute.

Saudi Aramco says climate lawsuits ‘could result in substantial costs’

Australia’s plunging wind, solar, storage costs stun fossil fuel industry

Renew Economy, 29 March 2019

This week the federal Coalition government decided to dump 90 per cent of the coal projects that had been submitted to its big underwriting program, and chose instead a shortlist dominated by renewables backed by battery storage and pumped hydro, and some gas and just one coal upgrade.

The choice may have been driven more by politics than economics, given the project developers were asked for only a broad outline of their proposal and there is an election just a few weeks away.

But when the final detailed tenders come in later this year – assuming the program survives the upcoming election campaign – the economic case for favouring renewables and storage projects should be crystal clear, if the latest numbers from global analysts BloombergNEF are anything to go by.

The stunning fall in the costs of wind, solar and storage – estimated on a global scale – has already put the fossil fuel industry on notice, as we reported earlier this week.

Now, we can publish the BloombergNEF cost estimates for Australia, and they reveal an even more devastating outcome for the fossil fuel industry and their cheer leaders in politics and the media.

The headline number is the cost of “bulk energy”, where unsubsidised solar and wind easily beat coal and gas. Even the highest priced wind and solar is cheaper than the lowest cost estimate for coal, so the Coalition might as well save $10 million to taxpayers funds and stop the feasibility study for the new Queensland coal generator now. We already know it makes no sense.

But the BNEF numbers tell us a lot more, and reinforce the cost estimates produced by the CSIRO and the Australian Energy Market Operator last year, that found that wind and solar, even backed by hours of storage and fully dispatchable, still beat the fossil fuel generators.

The graph above shows the cost of “bulk energy” on the left, and in the middle is what BloomberNEF describes as “dispatchable” generation, which includes what is usually described as the “base-load” coal and gas generators, and onshore wind and solar PV “firmed up” by storage to make them dispatchable.

To the right is what BloombergNEF refers to as “peaking plants”, and it is where it groups technologies like pumped hydro, open cycle gas, fast-start gas reciprocating engines and stand-alone batteries.

These two columns under dispatchability and flexibility deserve further explanation, because when the cost wind and solar plunged so dramatically in the last decade, and turned the tables on coal and gas on the cost of bulk energy, the fossil fuel spruikers have been hanging on to this idea of “baseload” and “back-up” to argue that the “intermittents” are still more expensive.

This week the federal Coalition government decided to dump 90 per cent of the coal projects that had been submitted to its big underwriting program, and chose instead a shortlist dominated by renewables backed by battery storage and pumped hydro, and some gas and just one coal upgrade.

The choice may have been driven more by politics than economics, given the project developers were asked for only a broad outline of their proposal and there is an election just a few weeks away.

But when the final detailed tenders come in later this year – assuming the program survives the upcoming election campaign – the economic case for favouring renewables and storage projects should be crystal clear, if the latest numbers from global analysts BloombergNEF are anything to go by.

The stunning fall in the costs of wind, solar and storage – estimated on a global scale – has already put the fossil fuel industry on notice, as we reported earlier this week.

Now, we can publish the BloombergNEF cost estimates for Australia, and they reveal an even more devastating outcome for the fossil fuel industry and their cheer leaders in politics and the media.

This graph above prepared by BloomberNEF shows how.

The headline number is the cost of “bulk energy”, where unsubsidised solar and wind easily beat coal and gas. Even the highest priced wind and solar is cheaper than the lowest cost estimate for coal, so the Coalition might as well save $10 million to taxpayers funds and stop the feasibility study for the new Queensland coal generator now. We already know it makes no sense.

But the BNEF numbers tell us a lot more, and reinforce the cost estimates produced by the CSIRO and the Australian Energy Market Operator last year, that found that wind and solar, even backed by hours of storage and fully dispatchable, still beat the fossil fuel generators.

The graph above shows the cost of “bulk energy” on the left, and in the middle is what BloomberNEF describes as “dispatchable” generation, which includes what is usually described as the “base-load” coal and gas generators, and onshore wind and solar PV “firmed up” by storage to make them dispatchable.

To the right is what BloombergNEF refers to as “peaking plants”, and it is where it groups technologies like pumped hydro, open cycle gas, fast-start gas reciprocating engines and stand-alone batteries.

These two columns under dispatchability and flexibility deserve further explanation, because when the cost wind and solar plunged so dramatically in the last decade, and turned the tables on coal and gas on the cost of bulk energy, the fossil fuel spruikers have been hanging on to this idea of “baseload” and “back-up” to argue that the “intermittents” are still more expensive.

Not so, says the BloomberNEF data, along with that of the CSIRO and AEMO. As BloombergNEF’s head of energy economics Elena Giannakopoulou observes, batteries in Australia are already cheaper than gas plants in providing peaking services.

In the right hand column, the comparison Bloomberg makes (on a $/MWh basis) is between stand-alone batteries and technologies that have been offering peaking services, namely open-cycle gas turbines (OCGTs) and gas reciprocating engines.

“And we see that there are markets today like Australia, U.K. and Japan where batteries are already cheaper than gas plants in providing peaking services,” she tells RenewEconomy by email.

The middle column is also interesting.

These costs reflect the combined system, wind or solar plus the battery, and include capex, and operating and maintenance costs for the power generating asset (ie solar or wind) and the battery.

The range in estimated costs for wind and solar plus storage reflects the number of hours of storage.

The cheapest is one hour, and the more expensive four hours. The reason why the batteries appear cheaper when paired with wind and solar, rather than stand-alone, is because they source the electricity for charging for free, as part of a combined asset.

“There is no charging cost here as batteries are charging from the renewable energy asset,” Giannakopoulou says. “The storage capacity here (ie output in MW and duration in hrs) is determined by the amount of electricity generated by solar/wind you want to “firm” ie ensure that is available when it’s not sunny or windy.

“These systems can now offer what we call “dispatchability” ie give solar and wind plants access to high value hours when they might otherwise be offline. As a result they compete with thermal plants that provide bulk electricity ie combined -cycle gas plants and coal plants.

“Already, in a number of major markets like Germany, the U.K. and the U.S., new solar and wind-plus-battery systems with, say, four hours of storage sized at 50 per cent of the generating plant capacity, can compete with new coal and gas plants on an unsubsidized cost-of-energy basis.

“In Australia, a wind-plus-battery system with 100 per cent dispatchability is already beating new coal and CCGT plants. And even in China, new solar- and wind-plus-battery systems with a low degree of dispatchability have reached cost parity with low-cost coal plants.”

Of course, not every wind and solar farm will need to have its own batteries or pumped hydro and match each MW of output with an equivalent in storage. Like the gas plants that have long provided back up for the fleet of coal generators, this is best provided on a system-wide basis.

And that is what is going to make the results of the government underwriting tender very interesting. On these estimates, it will be hard to see how the five fossil fuel plants beat the renewables plus storage proposals on costs.

Some of these proposals may depend on a “system” case, and the three pumped hydro projects in South Australia, for instance, are competing for what is for now a narrow window. (i.e. there is probably not room for all three.

But so far the government hasn’t bothered to seek advice of the Australian Energy Market Operator, which has put together its Integrated System Plan.

Even so, with costs of renewables and storage continuing to fall, as BloombergNEF reported earlier this week, they have fallen by between 10 per cent and 35 per cent just this past year – the argument for a new coal generator becomes even more a fantasy than it was at the start.

Finally, it should be noted that the headline on this story says that these cost falls will stun the fossil fuel industry. Actually, they won’t. They know full well that their technology is no longer competitive, as the heads of all the major utilities, and even their peak body, has admitted.

The only people that don’t know, or won’t accept, are the ideologues and ill-informed who insist on taking the Catweazle approach to modern technologies. One day, they may wake up, and they will be stunned by what they see.

Australia’s plunging wind, solar, storage costs stun fossil fuel industry

The Biggest Saudi Oil Field Is Fading Faster Than Anyone Guessed

Bloomberg, 2 April 2019

It was a state secret and the source of a kingdom’s riches. It was so important that U.S. military planners once debated how to seize it by force. For oil traders, it was a source of endless speculation. Now the market finally knows: Ghawar in Saudi Arabia, the world’s largest conventional oil field, can produce a lot less than almost anyone believed.

When Saudi Aramco on Monday published its first ever profit figures since its nationalization nearly 40 years ago, it also lifted the veil of secrecy around its mega oil fields. The company’s bond prospectus revealed that Ghawar is able to pump a maximum of 3.8 million barrels a day — well below the more than 5 million that had become conventional wisdom in the market. “As Saudi’s largest field, a surprisingly low production capacity figure from Ghawar is the stand-out of the report,” said Virendra Chauhan, head of upstream at consultant Energy Aspects Ltd. in Singapore.

The Energy Information Administration, a U.S. government body that provides statistical information and often is used as a benchmark by the oil market, listed Ghawar’s production capacity at 5.8 million barrels a day in 2017. Aramco, in a presentation in Washington in 2004 when it tried to debunk the “peak oil” supply theories of the late U.S. oil banker Matt Simmons, also said the field was pumping more than 5 million barrels a day, and had been doing so since at least the previous decade.

In his book “Twilight in the Desert,” Simmons argued that Saudi Arabia would struggle to boost production due to the imminent depletion of Ghawar, among other factors. “Field-by-field production reports disappeared behind a wall of secrecy over two decades ago,” he wrote in his book in reference to Aramco’s nationalization.
The new details about Ghawar prove one of Simmons’s points but he missed other changes in technology that allowed Saudi Arabia — and, more importantly, U.S. shale producers — to boost output significantly, with global oil production yet to peak.

The prospectus offered no information about why Ghawar can produce today a quarter less than 15 years ago — a significant reduction for any oil field. The report also didn’t say whether capacity would continue to decline at a similar rate in the future. In response to a request for comment, Aramco referred back to the bond prospectus without elaborating.

Lost Crown

The new maximum production rate for Ghawar means that the Permian in the U.S., which pumped 4.1 million barrels a day last month according to government data, is already the largest oil production basin. The comparison isn’t exact — the Saudi field is a conventional reservoir, while the Permian is an unconventional shale formation — yet it shows the shifting balance of power in the market.

Ghawar, which is about 174 miles long — or about the distance from New York to Baltimore — is so important for Saudi Arabia because the field has “accounted for more than half of the total cumulative crude oil production in the kingdom,” according to the bond prospectus. The country has been pumping since the discovery of the Dammam No. 7 well in 1938. On top of Ghawar, which was found in 1948 by an American geologist, Saudi Arabia relies heavily on two other mega-fields: Khurais, which was discovered in 1957, and can pump 1.45 million barrels a day, and Safaniyah, found in 1951 and still today the world’s largest offshore oil field with capacity of 1.3 million barrels a day. In total, Aramco operates 101 oil fields.

The 470-page bond prospectus confirms that Saudi Aramco is able to pump a maximum of 12 million barrels a day — as Riyadh has said for several years. The kingdom has access to another 500,000 barrels a day of output capacity in the so-called neutral zone shared with Kuwait. That area isn’t producing anything now due a political dispute with its neighbor.

While the prospectus confirmed the overall maximum production capacity, the split among fields is different to what the market had assumed. As a policy, Saudi Arabia keeps about 1 million to 2 million barrels a day of its capacity in reserve, using it only during wars, disruptions elsewhere or unusually strong demand. Saudi Arabia briefly pumped a record of more than 11 million barrels a day in late 2018. “The company also uses this spare capacity as an alternative supply option in case of unplanned production outages at any field and to maintain its production levels during routine field maintenance,” Aramco said in its prospectus.

Costly Strategy

For Aramco, that’s a significant cost, as it has invested billions of dollars into facilities that aren’t regularly used. However, the company said the ability to tap its spare capacity also allows it to profit handsomely at times of market tightness, providing an extra $35.5 billion in revenue from 2013 to 2018. Last year, Saudi Energy Minister Khalid Al-Falih said maintaining this supply buffer costs about $2 billion a year.
Aramco also disclosed reserves at its top-five fields, revealing that some of them have shorter lifespans than previously thought. Ghawar, for example, has 48.2 billion barrels of oil left, which would last another 34 years at the maximum rate of production. Nonetheless, companies are often able to boost the reserves over time by deploying new techniques or technology. In total, the kingdom has 226 billion barrels of reserves, enough for another 52 years of production at the maximum capacity of 12 million barrels a day.

The Saudis also told the world that their fields are aging better than expected, with “low depletion rates of 1 percent to 2 percent per year,” slower than the 5 percent decline some analysts suspected. Yet, it also said that some of its reserves — about a fifth of the total — had been drilled so systematically over nearly a century that more than 40 percent of their oil has been already extracted, a considerable figure for an industry that usually struggles to recover more than half the barrels in place underground.

https://www.bloomberg.com/news/articles/2019-04-02/saudi-aramco-reveals-sharp-output-drop-at-super-giant-oil-field

Is this the day that solar and wind changed the W.A. grid forever?

Renew Economy, 22 February 2019

The Australian Energy Market Operator has been fretting about the increase in the penetration of rooftop solar for some time now, and perhaps most of all in Western Australia, one of the world’s biggest “stand alone” grids, where the solar uptake is accelerating rapidly.

The state now has more than 1GW of rooftop solar on its main grid, which is located in the south-west corner of the state, and which is known as the South West Interconnected System (SWIS).
That makes rooftop solar the biggest source of electricity by capacity, and the uptake is growing at 35 per cent a year, according to AEMO.

It also has a growing amount of large-scale wind and solar capacity, as construction resumes following a three-year hiatus engineered by the previous Coalition government, and reforms are made that will facilitate access for renewables to the grid.

The isolated nature of the SWIS, both in its physical characteristics and some say in the culture of many in the industry, makes W.A. a fascinating case study.

And rooftop solar is particularly attractive because the west gets gets a lot of sun, and because consumers are finally being asked to pay the true cost of the fossil-fuel based grid, which was hugely subsidised by the government that has decided it can no longer foot the $500 million a year cost of making the electricity bills appear slightly more palatable.

But that rapid switch to rooftop solar is creating a very big “duck” curve that the grid operator is having to learn how to manage, as are others around the world where solar is a growing share of production.
The duck curve relates to the fall in demand in the middle of the day – driven by the uptake of rooftop solar – and the “ramping” needed to catch up with grid demand as it rises quickly as the sun sets in late afternoon, early evening.

The operator says that on October 18 last year, it was forced, for the first time, to call in “backup load following ancillary services” – broadly the equivalent of the directions that AEMO has grown accustomed to issuing in South Australia and more recently Victoria.

The operator said this was the result of volatile wind output, which delivered swings of up to 50MW in short time periods during the morning, compounded by variations of up to 100MW in the output from rooftop solar in the late morning as cloud cover moving across the south-west corner and Perth in particular.

At 11.30am, local time, the operator called on 50MW of Backup LFAS Down and 50MW of Backup LFAS Up, for a period of 3.5 hours to meet what it expected to be a volatile load profile. AEMO says it was justified because – as the arrow is pointing to in the above graph – a band of clouds around 1pm reduced solar PV output and caused a 300MW increase in demand, and its passing caused a 250MW reduction in demand in the next time interval (1.30pm). The back-up call was not costly – around $36,000 – although a second back-up call, on December 26, at 1am, caused on this occasion by rapid changes in wind output, was imposed for 8.5 hours (35.5MW) and cost around $81,000.

AEMO says the increasing level of penetration of rooftop PV and other renewable generation is going to increase the amount of volatility experienced on the power system going forward, and the number of directions. AEMO boss Audrey Zibelman addressed this issue at a symposium at UNSW this week, when she said that in Western Australia there is sometimes “too much rooftop solar that is not managed”, causing voltage to drop at a distribution level, and leading to curtailment of rooftop solar output.

“We have to start introducing the solutions now to make sure it works – otherwise we will be in the unenviable position of saying we can’t do any more,” Zibelman said. Those solutions include a shift to “orchestration”, which will allow networks owners and grid operators to use smart inverters to help manage distributed solar output. Battery storage, demand management and aggregated systems through smart controls of devices such as pool pumps could also do the trick.

“We want to be able to use all these investment, in a way to provide a private benefit and a public benefit and integrate then into the system,” Zibelman said. “It’s important for markets to be able to reward people to do that so that they are getting payments for the service. We have to get cracking.”

Is this the day that solar and wind changed the W.A. grid forever?

‘What about the plug?’ Australia’s electric car infrastructure stalled by policy paralysis

The Guardian, 4 February 2019

Why has it taken so long just to move past the bare minimum needed to support what is now an expanding sector?

Most electric car owners will charge at home or at work but one in three will still be reliant on public charging stations. Last September, Sylvia Wilson became the second person in the country to drive around Australia in an electric car. The entire 20,396 kilometre trip took the 70-year-old 110 days in her Tesla S75 and cost just $150.90.

Her success served as an answer to critics who have long argued “range anxiety” – the worry about whether an electric car’s battery will die out of reach of a charging station – is a factor stopping more people buying electric cars. “The reality is that if you can see the lights on or that the kettle works, then you can charge. Even in the remotest places, you can still charge the car. In a way there are more places to charge an EV [electric vehicle] than there are a fossil-fuel car,” Wilson told Guardian Australia at the time.

While Wilson showed what’s possible with existing infrastructure, industry insiders and engineers have been left wondering why it’s taken so long for Australia just to move past the bare minimum needed to support an expanding electric car sector.

Behyad Jafari, chief executive of the Electric Vehicle Council, says the failure to so far provide this infrastructure – from charging stations and uniform standards for components, to the tools needed to maintain each vehicle – is a symptom of political paralysis that has taken hold in Canberra. “Let’s be clear here, these aren’t electric vehicle problems, they’re Australian policy problems,” says Jafari. “In the absence of that, companies are left wondering, well what the hell do we do?”

According to modelling commissioned by the Clean Energy Finance Corporation, most electric car owners will charge at home or at their place of work but roughly one in three will still be reliant on public charging stations. With just 783 charging stations around the country in 2018, compared with 6,400 petrol stations, building the infrastructure to support the widespread take-up of electric vehicles will cost $1.7bn.

Tim Washington is a director of Jetcharge and a cofounder of Chargefox, one of the biggest companies in Australia which supplies and installs charging stations across the country.

Washington says most of the infrastructure needed to support the mass uptake of electric cars is already in place, because most people living in a city only drive up to 30 kilometres a day. “Public charging stations are a visual signal to the public that you are now able to charge the car. People are very used to seeing petrol stations and they have confidence in buying a petrol car because they have a petrol station,” says Washington. “People immediately think service station-style charging stations. That’s just not the case. A lot of the charging infrastructure is invisible infrastructure. It’s not apparent to the public eye to where the vast majority of charging stations are. “They’re in homes, in basements, in commercial building car parks, in public car parks – in all the places where you don’t see a traditional fuel source – and that’s all that required for a healthy uptake of electric vehicles.”

The problem for companies like his, Washington says, is that the infant nature of the industry and the way people will use the technology makes it a risky investment. “One of the troubles for public infrastructure providers is that you invest all this money to encourage people to come to electric, but once you invest this money, people will charge at home,” Washington says. “It’s classic market failure.”

To get around this, state and local governments have so far been eager to support the building of new charging stations, but often the support they can provide is limited by their resources and their authority.
Instead, help must come from Canberra which for the last few years has been slow to respond to the growth of the new industry – despite some recognition of its potential. Indeed, one of the recommendations in the select committee report on electric vehicles released this week is that the federal government work with “operators in the charging infrastructure industry to develop a comprehensive plan for the rollout of a national public charging network”.

Last October the federal energy minister, Angus Taylor, announced $6m to support Chargefox in building a network of ultra-fast charging stations along the highways that link Brisbane, Sydney, Canberra, Melbourne and Adelaide, and four around Perth. These stations have the ability to take recharge times from eight hours down to 15 minutes in some cases.

While it was a welcome announcement, the government has so far failed to address other infrastructure issues that aren’t the most obvious – or headline grabbing. An early example involved the humble plug. With no clear standard in Australia, global manufacturers had no guide for how to build their cars for the local market. In some ways it risked repeating what happened at federation when each state mandated its own rail gauges, making it impossible to take a train across state lines in one continuous trip.

“It had been an understood issue for quite a number of years before but then there hadn’t been any action,” says Jafari. Instead, industry players themselves had to organise to decide on a voluntary standard that was later communicated in a technical document released by the Federal Chamber of Automotive Industries. While it was a good news story for the industry, it should never have been left to get that far.

Now researchers such as Professor Iftekhar Ahmad from Edith Cowan University are looking ahead to stop future problems before they happen. “Electric cars will increase what’s called high peak-to-average demand. When the owners go home and plug in, we’ll see high peak demand during those hours,” says Ahmad. “The current distribution network is not designed for high peak. When you think about putting so much load on the network, the infrastructure lifetime can be shortened and also it can put too much stress on transformers.”

While several fixes have been proposed, Ahmad says the problem can be overcome with proper planning.
“It has to be well planned,” he says. “It’s not currently happening in a coordinated fashion and the perspective from the government [and] the utilities is that there’s not enough cars in the market to think about it.
“It will happen, there is no stopping it. If you go to Beijing or Europe, you will see them everywhere and if enough planning can be done, electric cars have a huge potential to complement our renewable energy system.”

https://www.theguardian.com/environment/2019/feb/04/what-about-the-plug-australias-electric-car-infrastructure-stalled-by-policy-paralysis

Fracked Shale Oil Wells Drying Up Faster than Predicted, Wall Street Journal Finds

DeSmog, 10 January 2019

In 2015, Pioneer Natural Resources filed a report with the federal Securities and Exchange Commission, in which the shale drilling and fracking company said that it was “drilling the most productive wells in the Eagle Ford Shale” in Texas. That made the company a major player in what local trade papers were calling “arguably the largest single economic event in Texas history,” as drillers pumped more than a billion barrels of fossil fuels from the Eagle Ford. Its Eagle Ford wells, Pioneer’s filing said, were massive finds, with each well able to deliver an average of roughly 1.3 million barrels of oil and other fossil fuels over their lifetimes.

Three years later, The Wall Street Journal checked the numbers, investigating how those massive wells are turning out for Pioneer.
Turns out, not so well. And Pioneer is not alone.Those 1.3 million-barrel wells, the Journal reported, “now appear to be on a pace to produce about 482,000 barrels” apiece — a little over a third of what Pioneer told investors they could deliver. In Texas’ famed Permian Basin, now the nation’s most productive shale oil field, where Pioneer predicted 960,000 barrels from each of its shale wells in 2015, the Journal concluded that those “wells are now on track to produce about 720,000 barrels” each.

Not only are the wells already drying up at a much faster rate than the company predicted, according to the Journal’s investigative report, but Pioneer’s projections require oil to flow for at least 50 years after the well was drilled and fracked — a projection experts told the Journal would be “extremely optimistic.”

Fracking every one of those wells required a vast amount of chemicals, sand, and water. In Karnes County, Texas, one of the two Eagle Ford counties where Pioneer concentrated its drilling in 2015, the average round of fracking that year drank up roughly 143,000 barrels of water per well.

A Billion Missing Barrels

And while Pioneer has become one of the most active drillers in the Permian, it’s hardly alone in booking projections that the Journal found were dubious. “Two-thirds of projections made by the fracking companies between 2014 and 2017 in America’s four hottest drilling regions appear to have been overly optimistic, according to the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in Texas and North Dakota,” it reported. “Collectively, the companies that made projections are on track to pump nearly 10 percent less oil and gas than they forecast for those areas, according to the analysis of data from Rystad Energy AS, an energy consulting firm.” “That is the equivalent of almost one billion barrels of oil and gas over 30 years,” the Journal added, “worth more than $30 billion at current prices.”

The problems the Journal focused on will be familiar to those who’ve turned a critical eye to shale reserves in the past: The most productive areas, or “sweet spots,” are smaller than first expected and companies predicted that wells would dry up slower than they have. DeSmog launched its latest series covering shale’s financial woes in April 2018 and our coverage extends back over a half-decade.
For the Journal, the take-aways were financial. “So far, investors have largely lost money,” the newspaper pointed out, adding that a review of 29 drillers showed companies have spent $112 billion more than they earned from drilling in the past decade. “Since 2008, an index of U.S. oil and gas companies has fallen 43 percent, while the S&P 500 index has more than doubled in that time, including dividends.”
The industry’s defenders argue that spending money now to make money later is simply how business works — this year’s “losses” are actually investments in future profits. But because shale drilling is relatively new, even the experts are left guessing about how much oil will be flowing from the wells 10, 20, or 30 years after fracking — and investors have become frustrated as shale drillers have largely failed to turn the corner and start racking up profits instead of continuing to operate in the red.

“The industry’s only hope of paying off debt and rewarding equity investors is for oil prices to rise high enough for long enough that they can generate consistent cash flow without breaking the bank on capex [capital expenditures],” said Clark Williams-Derry, director of energy finance at the Sightline Institute. “But they’ll have real problems — sweet spots are getting depleted, wells are declining faster than they’d hoped, pipelines are still constrained causing deep discounts in some markets, co-produced gas is close to worthless, and any sustained rebound will boost the cost for drilling services (i.e., higher prices mean higher costs).” “Plus,” he added, “investors need to worry about long-term cleanup costs.”

Calling in the Experts

And the pressure on the experts charged with preparing oil and gas production estimates for drillers is enormous. As the first shale wells get older and more production history rolls in, engineers have developed models they say can make better predictions — but the Journal suggested those tools haven’t been widely adopted. “Why aren’t we doing this?” one engineer demanded repeatedly after John Lee, one of the most prominent reserves experts in the U.S., gave a talk in Houston in July about making more accurate shale projections. “‘Because we own stock,’ replied another engineer, sparking laughter,” the Journal reported.

The Journal’s reporting frequently cited Rystad Energy, an independent oil and gas consulting firm, as the source of more conservative projections — but, as DeSmog has previously reported, Rystad isn’t the only large independent firm to find troubling indications that shale wells are on track to produce only a fraction of their “proved” reserves. Wood Mackenzie, another major oil consulting firm, studied the Permian’s Wolfcamp shale, where early projections predicted that production from a five-year-old well should be declining at a rate of 5 to 10 percent. Those wells, the firm found, are actually declining by roughly 15 percent a year — a significantly larger drop than expected and an ominous sign for any companies projecting wells can last 50 years.

And fracking giant Schlumberger — which like Halliburton specializes in performing hydraulic fracturing jobs on wells other companies drill — has begun calling attention to a problem with much more immediate impacts: The sweet spots are getting too crowded. For years, the industry has said that it can minimize impacts by drilling multiple wells from the same well pad — but in parts of the Permian, wells drilled later on or near existing well pads have proved roughly 30 percent less productive compared to the first well drilled.

“[T]he well-established market consensus that the Permian can continue to provide 1.5 million barrels per day of annual production growth for the foreseeable future is starting to be called into question,” Schlumberger’s CEO Paal Kibsgaard said in an October 2018 earnings call. “At present, our industry has yet to understand how reservoir conditions and well productivity change as we continue to pump billions of gallons of water and billions of pounds of sand into the ground each year.” Kibsgaard warned that similar problems are beginning to show up in the Eagle Ford as well.

The Long-Term Costs of a Boom and a Bust

Karnes County is still the most active part of the Eagle Ford, with 562 drilling permits issued last year. After a heady oilfield boom, oil prices plunged in 2015 and 2016, leading to the layoffs of thousands of workers and royalty checks drying up. This past year, drilling has re-emerged, albeit at a slower pace. “It’s not a boom, but there’s a resurgence here in the Eagle Ford,” Rick Saldana, an energy company superintendent told the Houston Chronicle in October.
Investors have faced a rocky ride. Sanchez Energy, the Eagle Ford’s third largest driller, has now been warned twice by the New York Stock Exchange that it will be de-listed if its stock price, now at roughly $0.26 a share, doesn’t soon rise above $1.

But other impacts of the boom and bust cycle run deeper. In nearby Dilley, Texas, a former oilfield man-camp, built to house Eagle Ford workers, was turned into the “the South Texas Family Residential Center” in December 2014 by a private prison company. It’s now the nation’s largest immigration detention center for families, housing up to 2,400 people, half of them children.

And while over the past decade, Wall Street and other investors poured billions into fracking — the Journal tallied $112 billion more spent than earned from production at 29 major drillers — the U.S. more broadly has failed to seriously invest in a rapid transition away from climate-changing fossil fuels. That leaves the U.S. at risk of being left behind as the rest of the world focuses its efforts to innovate on renewable energy prospects that don’t dry up like oil wells. Bethany McLean, a financial journalist famous for first breaking the Enron story, recently told Fortune about conversations she’d had with major private equity investors as she researched her new book Saudi America. “They are all trying to figure out when we’ll be able to see the end of the oil age, because as soon as that happens, the price of oil will go into secular decline (as it did with coal),” she said. “Other countries, namely China, are frantically investing in renewables. For us to crow about our oil wealth, and not focus on renewables, is for us to miss the opportunity to be leaders in the world as it’s going to be.”

https://www.desmogblog.com/2019/01/10/fracking-shale-oil-wells-drying-faster-predicted-wall-street-journal

Chasing China: Chile drives Latin America’s electric vehicle revolution

Sydney Morning Herald, 10 December 2018
A massive cargo ship docked in the Chilean port of San Antonio at the end of November. It carried it its belly the first 100 electric buses from China that Chileans hope will revolutionise their public transport system.
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