Skip to content

Posts from the ‘Energy’ Category

Oil, Gas, Petrochemical Financial Woes Predate Pandemic — And Will Continue After, Despite Bailouts, Report Finds

Resilience.org 27 May 2020

The oil, gas, and petrochemical industries have taken a massive financial blow from the COVID-19 pandemic, a new report from the Center for International Environmental Law (CIEL) concludes, but its financial troubles preexisted the emergence of the novel coronavirus and are likely to extend far into the future, past the end to measures aimed at curbing the spread of the disease.

“Oil and gas are among the industries hardest hit by the current economic crisis, with leading companies losing an average of 45 percent of their value since the start of 2020,” the report finds. “These declines touch on nearly every facet of the oil and gas sector’s business, including the petrochemical sector that has been touted in recent years as the primary driver of the industry’s future growth.”
That’s to some degree because of the abrupt plunge in demand for oil resulting from shelter-in-place and quarantine measures that, as of early April, applied to over 3 billion of the world’s 7.8 billion people — including 90 percent of the United States. And the United States uses an outsize amount of gasoline — in 2017, the U.S. consumed one fifth of the gasoline used globally, the report notes. Nearly 70 percent of petroleum products are consumed for transportation, the report adds — meaning that the impact on demand resulting from quarantines is enormous.

But, before the pandemic, oil, gas, and petrochemical firms “showed clear signs of systemic weakness,” CIEL’s report says, listing factors like the industries’ poor stock market performance, high levels of debt, competition from cheaper renewable energy, slowing growth in demand for plastics, and growing awareness among investors of the impacts that action to slow climate change will have on the sector.
“The crash that we’re seeing in the oil and gas and petrochemicals industry is a recent intensification of what has been a very long-term trend,” said Carroll Muffett, president of CIEL. “If you look back over the last 5 years or more, we’ve seen the oil and gas industries significantly underperforming the broader Dow Jones on a long-term basis.”

Revenue Problems Predate Pandemic

The report includes recommendations that result from the industries’ prolonged struggles to satisfy investors.
“Public officials taking policy action to respond to COVID-19 and the economic collapse should not waste limited response and recovery resources on bailouts, debt relief, or similar supports for oil, gas, and petrochemical companies,” it concludes. “These efforts may succeed in diverting significant public resources to the sector and delaying the clean-energy transition; however, they are very unlikely to reverse the underlying trends driving the long-term decline of the oil, gas, and petrochemical industries.”

CIEL also noted that pension plan managers and other institutional investors have legal duties that may force them to keep an especially close eye on any oil, gas, or petrochemical projects in their portfolios.
“Because many investors, including pension funds, which are the largest category of equity investors globally, have fiduciary duties to their beneficiaries, they have legal obligations on top of the financial incentives to maximize profits: they must also reduce risk,” the report says. “As the risks of investing in the oil and gas sector become ever more apparent, more and more investors subject to fiduciary duties will likely choose to steer clear of these companies.”

The report notes that even before the pandemic began, global oil production was outpacing demand at a striking rate. “The International Energy Agency estimates that the oil industry had 2.9 billion barrels of oil in storage by the end of January 2020, just slightly below its all-time peak,” CIEL reported. “With government stockpiles holding an additional 1.5 billion barrels, roughly 4.4 billion barrels of oil were sitting in storage even before the first shutdowns of large sections of the economy began.”

“What is really critical to recognize is that that supply glut pre-existed the current crisis,” said Muffett. That glut comes in part from the past decade’s rush to drill for shale oil and gas, which left many drillers deep in debt at the end of 2019. Oil giants wrote down billions of dollars in assets at the end of last year, the report notes, including an $11 billion write-down by Chevron, much of it tied to the company’s Appalachian-region shale gas acreage, which left the oil giant with a $6.6 billion loss for the quarter.

“Critically, fracking isn’t profitable,” said Steven Feit, a CIEL staff attorney. “It has been a gigantic money pit kept afloat by external financing.”

High Yield Junk

By 2025, over $200 billion of debts amassed by the oil and gas industry are scheduled to come due — including $40 billion that the industry must repay this year alone. Much of that debt already looked risky going into the crisis.

A new Friends of the Earth (FOE) report, titled “The Big Oil Money Pit,” highlighted the ways that the federal bailout of the high-yield market could allow energy companies “to benefit disproportionately” from efforts by the Federal Reserve to use $75 billion of a “$500 billion corporate slush fund” to buy corporate debt.

“High-yield” debts generally offer investors higher returns because of the higher risks associated with that debt.

FOE’s report identifies a dozen shale drillers that might qualify for that federal bailout, including Apache, Devon Energy, EOG Resources, and Pioneer Natural Resources, estimating that the 12 firms might qualify for over $24 billion in benefits a piece. ExxonMobil, Chevron, and Conoco, it estimates, could qualify for an additional $19.4 billion.
The report notes that some of the fine print in the bailout plan makes Continental Resources — the company founded by Trump advisor and confidant Howard Hamm — eligible for federal support despite the fact that S&P downgraded its debt to junk-grade on March 27, 2020.
Even companies that don’t qualify for that federal support could receive help from another piece of the bailout plan, FOE adds.
“Because the junk bond market is now 11 percent energy companies (predominantly oil and gas), any attempt to bolster the entire sector is going to benefit heavily indebted frackers,” the report predicts.
“The thing to keep in mind is that in the world of high-yield debt, the oil and gas industry is actually the single largest issuer of junk debt,” said Lukas Ross, senior policy analyst at FOE.

FOE pointed to $6.9 million in bonds issued by Chesapeake Energy and $37.4 million in bonds issued by Range Resources as examples of debts that could benefit from what it termed “a back-door bailout for the accumulated bad debts of the fracking industry.”

“The big question is, can the oil and gas industry convert its political power into economic survival,” Ross added.

Pollution and the Pandemic

Oil, gas, and petrochemical lobbyists have sought a broad array of other government responses to the pandemic, as highlighted by a third report, recently released by UK think tank InfluenceMap.
“It’s not just financial bailouts that are underway, there’s regulatory intervention,” said Dylan Tanner of InfluenceMap. “The rules of the game in many ways are changing.”

The industries have sought the rollback of pollution controls in many countries as a part of the response to the COVID-19 pandemic, the report notes, including requests to curtail or delay programs designed to cut climate changing pollution.

https://www.resilience.org/stories/2020-05-27/oil-gas-petrochemical-financial-woes-predate-pandemic-and-will-continue-after-despite-bailouts-report-finds/

Shutting Down Oil Wells, a Risky and Expensive Option

Resilience.org  28 May 2020

The temporary shutting in of wells is the one thing that oil companies are trying to avoid at all costs. That’s because restarting production is expensive and wells are not guaranteed to return to their flow rate. The doubts are so great that some experts wonder whether the current round of shut downs, far from preserving the resource, won’t accelerate oil depletion instead. Some Russian engineers are even considering burning excess oil, rather than downsizing production.
The COVID-19 crisis resulted in a quick and dramatic drop in demand for oil, estimated to be in the 25 to 30 per cent range in April. Much of this decline is expected to be reversed by the end of the year, but faced with a massive drop in oil prices and a lack of storage tanks, oil companies face a difficult dilemma: should they ride out this unprofitable streak or should they decrease production to cut their losses?
To the lay person, the option to cut production seems obvious. But an oil well is not a tap with a flow that can be adjusted as needed. Either it operates at full capacity or not at all. Valves are installed, but they’re only used during brief maintenance periods or emergency stops. Oil companies know that the decision to shut down for an extended period has three serious consequences:
reopened wells may never return to their previous production rate
pumping equipment must be repaired and refitted at great cost
other facilities, such as refineries and pipelines, cannot be kept in operation without some minimal level of production.
Impact on wells
An oil field is a complex structure, where different grades of oil have settled over time in a porous type of rock such as sandstone. Drilling and pumping releases this mixture of oil and gas. Any cessation of the extraction process may result in the clogging of this porous rock with sediment or paraffin, which means that production may permanently be reduced by half, or even stop completely, when pumping resumes. This loss of productivity does not always occur and it is sometimes possible to repair part of the damage by injecting chemicals into the well. But it’s easy to understand why oil companies would seek to avoid damage to their property and costly remediation work.
In addition to the geological constraints, the shut down process is risky in and of itself. To close a well, a special drilling rig is used to inject a thick mud at the well head to block the flow of oil and gas. This blocks the pores of the rock to a lesser degree, alters the pressure inside the well and inevitably complicates any attempt to resume production. The well itself is also plugged by pouring cement into it.
To restart production, it is necessary to bring a new rig, drill the cement plug, and pump the sludge blocking the well head. The hope is that oil will start to flow again. If this fails, you have to drill a new well, inject chemicals or even perform hydraulic fracturation (fracking). These steps are costly and labour intensive. If all oil companies try to resume operations at the same time, there aren’t enough work teams around to handle the workload. At the end of the last similar crisis, some restoration work had to wait up to two years.
The Alberta oil sands are fraught with comparable challenges. The bitumen is separated from the sand by injecting steam into the ground. The heat and pressure levels must remain constant, otherwise the bitumen may clog in the underground reservoir and in collection pipes. At best, resuming production may require months of work, at worst, shutdown can permanently diminish the throughput of the facility.
Offshore drilling platforms have their own challenges. When pumping ceases, the pressure builds up quickly, causing methane hydrates to form and to clog pipes. Underwater pipelines that transport oil to the coast are particularly at risk. Relaunching production at offshore facilities is so difficult that it is considered to be the very last option for oil companies.
An enormous price tag
Decommissioning a well is expensive. In the case of a high-flow well, simply removing the submersible electronic pump costs about $150,000. For a medium-flow well, the bill is around $75,000. The underground environment is corrosive and a chemical treatment costing $2,000-$5,000 must also be applied to protect equipment that cannot be removed from the well.
Resuming production is also tremendously expensive. Cleaning the well of accumulated water costs anywhere from $10,000 to $20,000. In a high-flow well, repairing the submersible pump costs about  $150,000 and replacing it costs double, just for equipment. The bill can reach up to $400,000 or $500,000 when you include labour costs. Even in a low-throughput well, repairing the equipment costs at least $50,000.
The bill for the chemicals used to restore a conventional well that has lost some flow ranges from $50,000 to $100,000. If the hydraulic fracturing of a shale oil well has to be redone, you’ll have to dish out an additional $3-$5 million.
Bear in mind that the fate of thousands of wells is currently at stake. In North Dakota, 6,200 wells are already closed, most of them with moderate flow and dependent on hydraulic fracturing. Given the high restart costs, the bill could reach up to a billion dollars. In Louisiana, nearly 17,000 wells will probably be shut down because of the crisis. In Texas, the numbers are even higher.
The cost is difficult enough to justify for wells with an average throughput. It cannot be justified at all for old wells reaching the end of their life, which often produce less than 10 barrels per day. These wells must continue producing or simply cease operating forever. Since there are so many of them, amounting to almost 11 per cent of US oil production, the loss could be significant for the industry.
Other considerations
Most refineries cannot operate below 60 or 70 per cent of their baseline capacity. A few select ones can go as low as 50 per cent, but no less. If oil production keeps decreasing, some refineries will have to close, temporarily or permanently. Production at US refineries has already fallen by 30 per cent, which means that they’ve already almost reached the shutdown point. The risk is all the greater as the demand for oil in the U.S. has declined from 18 to 5 million barrels per day during the COVID crisis.
Here again, we are talking about equipment which must continue operating as it will fall into disrepair when not in use. For some old and marginally profitable refineries it may therefore be financially impossible to resume operations after a shut down. It is estimated that the United States could permanently lose one to two million barrels per day of refining capacity after the crisis.
Another worrying piece of infrastructure is the Trans-Alaska pipeline. If a throughput of at least 400,000 barrels per day cannot be maintained, the oil flows so slowly that the surrounding permafrost generates a cooling effect. Under these conditions, ice crystals and paraffin are likely to form, which can block the pipes and damage the pumps. Oil production has been declining for years in Alaska and the pipeline is already used at minimum capacity. A moderate drop in production would therefore lead to a pipeline shut down, making any further oil production impossible for lack of transportation. In short, all of Alaska’s oil production could dry up at once.
Decisions, decisions
In this context, it is understandable that oil companies are so reluctant to decrease production, even when they are in debt or bankrupt and even when oil is so cheap that they have to sell below the break even price. Resuming production is expensive and there is a risk of a permanent drop in production on startup, making the investment less attractive. Some Russian producers even say they would prefer burning unsold oil to shutting down wells. In addition, certain land use contracts require oil companies to pump the oil, under penalty of seeing their drilling rights transferred to their competitors!
Some analysts believe that the oil industry will emerge from the crisis in such bad shape that it won’t be able to finance the restart of the closed wells. As no sufficient alternative to oil will be deployed by the time the crisis is over, some are starting to suggest that a partial nationalization of the US oil industry might be in order.
What about peak oil?
When the crisis began, some observers believed that COVID-19 would delay peak oil (or its effects, as some analysts suggest it was reached in October 2018) due to diminishing oil demand. It now seems the opposite could be true and that we could actually be moving closer to peak oil. Some wells will be permanently closed and others will never return to their former production level. In addition, financially unsound oil companies will find it difficult to launch new projects.
We can therefore expect the current glut of oil to give way gradually to an increasing shortage. Gas station pumps are not going to dry up overnight, but prices are likely to rise again and oil might become too scarce and too expensive to fuel significant economic growth. Activists will welcome this fall in fossil fuels production, but we must bear in mind that a low intensity energy crisis could also hamper our ability to carry out an efficient energy transition.

https://www.resilience.org/stories/2020-05-28/shutting-down-oil-wells-a-risky-and-expensive-option/

The Covid-19 crisis is causing the biggest fall in global energy investment in history

International Energy Agency 27 May 2020

Impacts are felt across the energy world, from fuel and power supply to efficiency, with serious implications for energy security and clean energy transitions

The Covid-19 pandemic has set in motion the largest drop in global energy investment in history, with spending expected to plunge in every major sector this year – from fossil fuels to renewables and efficiency – the International Energy Agency said in a new report released today.

The unparalleled decline is staggering in both its scale and swiftness, with serious potential implications for energy security and clean energy transitions. At the start of 2020, global energy investment was on track for growth of around 2%, which would have been the largest annual rise in spending in six years. But after the Covid-19 crisis brought large swathes of the world economy to a standstill in a matter of months, global investment is now expected to plummet by 20%, or almost $400 billion, compared with last year, according to the IEA’s World Energy Investment 2020 report.

“The historic plunge in global energy investment is deeply troubling for many reasons,” said Dr Fatih Birol, the IEA’s Executive Director. “It means lost jobs and economic opportunities today, as well as lost energy supply that we might well need tomorrow once the economy recovers. The slowdown in spending on key clean energy technologies also risks undermining the much-needed transition to more resilient and sustainable energy systems.”

The World Energy Investment 2020 report’s assessment of trends so far this year is based on the latest available investment data and announcements by governments and companies as of mid-May, tracking of progress on individual projects, interviews with leading industry figures and investors, and the most recent analysis from across the IEA. The estimates for 2020 then quantify the possible implications for full-year spending, based on assumptions about the duration of lockdowns and the shape of the eventual recovery.

A combination of falling demand, lower prices and a rise in cases of non-payment of bills means that energy revenues going to governments and industry are set to fall by well over $1 trillion in 2020, according to the report. Oil accounts for most of this decline as, for the first time, global consumer spending on oil is set to fall below the amount spent on electricity.  

Companies with weakened balance sheets and more uncertain demand outlooks are cutting back on investment while projects are also being hampered by lockdowns and disrupted supply chains. In the longer-term, a post-crisis legacy of higher debt will present lasting risks to investment. This could be particularly detrimental to the outlook in some developing countries, where financing options and the range of investors can be more limited. New analysis in this year’s report highlights that state-owned enterprises account for well over half of energy investments in developing economies.

Global investment in oil and gas is expected to fall by almost one-third in 2020. The shale industry was already under pressure, and investor confidence and access to capital has now dried up: investment in shale is anticipated to fall by 50% in 2020. At the same time, many national oil companies are now desperately short of funding. For oil markets, if investment stays at 2020 levels then this would reduce the previously-expected level of supply in 2025 by almost 9 million barrels a day, creating a clear risk of tighter markets if demand starts to move back towards its pre-crisis trajectory.

Power sector spending is on course to decrease by 10% in 2020, with worrying signals for the development of more secure and sustainable power systems. Renewables investment has been more resilient during the crisis than fossil fuels, but spending on rooftop solar installations by households and businesses has been strongly affected and final investment decisions in the first quarter of 2020 for new utility-scale wind and solar projects fell back to the levels of three years ago. An expected 9% decline in investment in electricity networks this year compounds a large fall in 2019, and spending on important sources of power system flexibility has also stalled, with investment in natural gas plants stagnating and spending on battery storage levelling off.

“Electricity grids have been a vital underpinning of the emergency response to the health crisis – and of economic and social activities that have been able to continue under lockdown,” Dr Birol said. “These networks have to be resilient and smart to ward against future shocks but also to accommodate rising shares of wind and solar power. Today’s investment trends are clear warning signs for future electricity security.”

Energy efficiency, another central pillar of clean energy transitions, is suffering too. Estimated investment in efficiency and end-use applications is set to fall by an estimated 10-15% as vehicle sales and construction activity weaken and spending on more efficient appliances and equipment is dialled back.

The overall share of global energy spending that goes to clean energy technologies – including renewables, efficiency, nuclear and carbon capture, utilisation and storage  – has been stuck at around one-third in recent years. In 2020, it will jump towards 40%, but only because fossil fuels are taking such a heavy hit. In absolute terms, it remains far below the levels that would be required to accelerate energy transitions.

“The crisis has brought lower emissions but for all the wrong reasons. If we are to achieve a lasting reduction in global emissions, then we will need to see a rapid increase in clean energy investment,” said Dr Birol. “The response of policy makers – and the extent to which energy and sustainability concerns are integrated into their recovery strategies – will be critical. The IEA’s upcoming World Energy Outlook Special Report on Sustainable Recovery will provide clear recommendations for how governments can quickly create jobs and spur economic activity by building cleaner and more resilient energy systems that will benefit their countries for decades to come.”

The Covid-19 crisis is hurting the coal industry – with investment in coal supply set to fall by one-quarter this year – but does not pose an existential threat. Although decisions to go ahead with new coal-fired plants have come down by more than 80% since 2015, the global coal fleet continues to grow. Based on available data and announced projects, approvals of new coal plants in the first quarter of 2020, mainly in China, were running at twice the rate observed over 2019 as a whole.

https://www.iea.org/news/the-covid-19-crisis-is-causing-the-biggest-fall-in-global-energy-investment-in-history

How Much Energy Does The US Consume & Where Does It Come From? — Pew Research

The US Energy Information Agency said this week that it expects 42 gigawatts of new electricity generating capacity to start commercial operation in 2020.

Solar and wind will account for almost 32 GW of the new capacity. Wind will account for the largest share of these additions at 44%, followed by solar at 32%, and natural gas at 22%. The remaining 2% will come from hydroelectric generators and battery storage.

Read more

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

css.php