(Bloomberg) — Exxon Mobil Corp., which is struggling to maintain a $15 billion-a-year dividend program, indicated it incurred a fourth straight quarterly loss.

Exxon confirmed in a filing Wednesday it will take a writedown of as much as $20 billion on its upstream assets, a possibility first disclosed at the end of October. It also reported much smaller non-cash impairments related to its refining business.

There were some positives. Higher oil and gas prices had an impact of up to $1 billion on upstream profits compared with the third quarter. The chemicals segment saw an earnings boost of as much as $400 million due to improved margins. Exxon’s shares were little changed in after-hours trading in New York.

Still, a fourth-quarter loss would confirm Exxon’s challenges in covering both dividends and capital expenditures from operational cash flow, and remains reliant on debt. The last time the Irving, Texas-based company generated enough free cash to cover its payout was the third quarter of 2018, according to data compiled by Bloomberg.

Exxon is set to disclose its full quarterly results on Feb. 2, amid one of the most-punishing periods in the company’s 150-year history. Its stock cratered to a 22-year low during 2020 amid a worldwide glut of oil and collapsing demand that gutted cash flow, spurring widespread job cuts. Exxon was kicked out of the Dow Jones Industrial Average, warned it will incur the biggest writedown of its modern history, and was assailed by activist investors seeking better returns and more climate accountability.

Exxon, which has long prided itself on its decades-long record of annual dividend increases, may have opened the door to changing course in late November, according to Cowen & Co. analyst Jason Gabelman. Whereas company executives touted Exxon’s “reliable and growing dividend” during an October conference call, a Nov. 30 statement announcing writedowns and spending cuts only mentioned its commitment to a “reliable” payout, Gabelman said in a note to clients.

(Bloomberg) — Liquefied natural gas traders anticipate a swift demand recovery in 2021 after a year in which the coronavirus pandemic prompted dramatic price swings.

Colder weather in key importing nations, outages at major production hubs and congestion along global shipping routes already have combined to push spot prices in Asia to the highest level since 2014. That’s a more than sixfold jump from a record low in April, making Asian LNG the best performer among major commodities in 2020.

Demand for the fuel used in heating and power generation is growing faster than for any other fossil fuel as nations look for a cheap, reliable and cleaner alternative to coal. The pandemic derailed that growth for 2020, but China and India are emerging as major sources of demand.

“A lot of countries are looking to import LNG,” Tom Holmberg, a partner at law firm Baker Botts LLP in Washington D.C., said by phone. “I still think we are going to see growth in the LNG market.” Below are the key areas likely to shape the market in 2021:

Uneven Demand Recovery

Global LNG imports in 2020 were roughly equal to the previous year, according to ship-tracking data compiled by Bloomberg. That was a big disappointment for an industry that has enjoyed 10% annual growth rate since 2016.
However, global gas demand is expected to resume growth next year. LNG demand, which makes up roughly 10% of the total, may rebound even faster, depending on how Pakistan, India and Bangladesh perform, said Manas Satapathy, a managing director in Accenture’s Energy business.

Shipments of the fuel into Asia have mostly recovered since the height of the pandemic, and the region’s LNG demand will rebound sharply next year, according to S&P Global Platts.

On the last day of 2020, spot Asian LNG price – the Japan-Korea Marker benchmark – rallied above $15 per million British thermal units for the first time since April 2014. “It has been interesting to see how quickly Asian demand seems to have ramped up,” Holmberg said.
The picture in Europe is very different as countries grapple with a new surge of infections and lockdowns that sap energy demand. The continent is headed for a “very neutral recovery” in 2021, according to Satapathy.
Europe mainly relies on storage and pipeline gas shipments, which may be boosted with flows from a new link from Azerbaijan and the controversial Nord Stream 2 project that’s nearing completion.

Supply Woes

Unplanned maintenance at LNG export facilities from Australia to Qatar to Malaysia has led to a tighter than expected market in the second half of the year. And delays in navigating the Panama Canal curbed supplies to Asia. If these disruptions persist well into the year, then prices could remain elevated well above current levels.

The Gas Exporting Countries Forum, which represents 60% of global LNG exports, expects supply to climb by 6% to 7% next year, up from 2% to 2.5% in 2020. LNG trade was much more resilient to this year’s challenges than imports in the fuel’s gaseous form, the group said in its short-term outlook.

The market will likely remain oversupplied next year, according to Vitol SA and Trafigura Group Ltd., two of the biggest trading houses active in LNG. Beyond that they expect the market to tighten.

More Cancellations?

Traders will be watching to see if buyers of U.S. LNG scrap any cargoes next year. About 200 cargoes were canceled in the summer after the pandemic hit spot prices in Europe and Asia. While there’s unlikely to be a repeat of that in 2021, traders do expect some cancellations to help balance the market.

merican gas exports are rising to fresh records every month as new facilities come online. But any dip in demand could force suppliers to shut-in cargoes. The nation has become a swing supplier because its contracts allow for scrapping deliveries, which enables exports to quickly respond to volatile markets.

China-U.S. Relations Trade relations between the U.S. and China will be a key focus. China is the fastest-growing LNG importer, and the U.S. is ramping up exports. There’s few long-term supply deals between the two nations even though LNG was a focus of President Donald Trump.

Joe Biden takes over as president on Jan. 20. A number of proposed U.S. LNG projects are hoping for more normal relations to help them sign deals with Chinese buyers.

“This certainly affects the LNG markets, particularly the LNG coming from the U.S.,” Holmberg said. And with Chinese economy roaring back and offices open, Jack Fusco, chief executive officer of Cheniere Energy Inc, anticipates that “deal making environment looks good for 2021.”

Green Ambition Environmentalists are increasingly looking at natural gas as a major polluter. After years of focusing on coal and oil, they’re turning their attention to how to zero out emissions from all fossil fuels. That shift has suppliers, buyers and shippers thinking green initiatives to clean up activities linked to methane and greenhouse gas emissions.

Half of the carbon footprint in the life cycle of an LNG cargo comes from upstream, Fusco said. The LNG producer is pushing for more transparency on carbon emissions for the fuel.

“Our customers are going to want to be sure that they can validate and audit what we’re telling them our carbon signature is,” he said.

The world’s first supply contract that required a declaration of emissions was signed this year while so-called carbon-neutral cargoes started flowing to China and Japan as nations outline ambitious targets to effectively zero out emissions.

South Africa’s biggest pot of available cash — 1.91 trillion rand ($128 billion) of civil-servant pensions and unemployment funds managed by the Public Investment Corp. — is emerging as the key to rescuing the debt-stricken national power monopoly.

The money manager has approached its parent agency, the National Treasury, with a proposal to ease the 464 billion-rand load of obligations crushing Eskom Holdings SOC Ltd., signaling officials are gearing up for the complex financial and political operation to convert about 95 billion rand of Eskom debt held by the PIC into equity.

“There’s still a need to undertake a due diligence to confirm the viability of this proposal,” the Treasury said in a Dec. 11 response to questions from Bloomberg, its first statement connecting the PIC to an Eskom bailout. “It is important that the PIC be allowed space to follow its internal governance processes in line with its standard investment evaluation process to mitigate against any possible breach of governance or what could be perceived as political interference.”

While international investors are cheering efforts to contrive a durable fix for Eskom, the idea of tapping the fund is already drawing warnings over the potential fallout. The swap, which could put Eskom into technical default, would pit the government against its own employees, set a precedent that could see other flailing state-owned companies knocking on the PIC’s door and rattle a private sector concerned that its money could be next.

Speculation of a PIC role has intensified in recent weeks since President Cyril Ramaphosa told Bloomberg that “innovative ideas” were being discussed, and Finance Minister Tito Mboweni said the fund was willing to contribute to a solution for Eskom. Labor, business and the government last week agreed to work jointly to reduce the utility’s debt in the so-called Eskom Social Compact.

The scope of the task has increased since Goldman Sachs Group Inc. described the utility in 2017 as the biggest threat to South Africa’s economy, which is just exiting its longest recession in 28 years. Eskom’s inability to provide reliable power since 2008, when outages began, has crimped output and disrupted everything from aluminum smelters to household kitchens.

The deterioration was worsened by years of looting under Ramaphosa’s predecessor, Jacob Zuma, leading to the 2019 bailout that totaled 128 billion rand over three years. But that’s merely keeping the wolf from the door and the search for a long-term solution is under way for the too-big-to-fail operation.

‘Materially Cheap’

Plans to rescue Eskom, which has said it can’t afford to service more than 200 billion rand of debt, have also included dipping into the surpluses of state-run unemployment and compensation funds and converting some of its mostly government-guaranteed debt into sovereign bonds.

Credit analysts have been talking up Eskom as a 2021 top pick, citing the government’s efforts, says Lutz Roehmeyer, the chief investment officer at Capitulum Asset Management GmbH in Berlin, who holds Eskom dollar bonds and isn’t adding any more. “Investors are very bullish on the name and expect the sovereign to solve the problem,” he said.

JPMorgan Chase & Co. this week called Eskom bonds “materially cheap” compared with sovereign debt.

Multiple Bailouts

South Africa’s Eskom is surviving on government support.

“As long as debt declines and becomes more sustainable, that’s really the number one priority,” said Guido Chamorro, co-head of emerging-market hard-currency debt at Pictet Asset Management in London, which manages $10 billion in developing-nation assets, including Eskom 2028 notes. “There are 101 different ways to do it. I mean, the government as the sole shareholder could even assume the debt. Or use its lower funding costs to borrow and then transfer the funds to Eskom.”

The PIC is recovering from a government inquiry last year into how political meddling influenced decision-making. The probe led to the departure of several senior executives following disclosures that included bailing out one of the country’s biggest retailers ahead of a national election against the advice of its investment professionals.

While the Congress of South African Trade Unions, a key ally of the ruling African National Congress, has backed using PIC funds to help Eskom, other labor groups, including the 235,000-member Public Servants Association, and business leaders have opposed it.

Eskom’s own employee pension fund has signaled resistance to the idea. It doesn’t want to change the “risk-return characteristics” of its 2 billion rand investment in the company’s debt or add to the holding, said Chief Investment Officer Ndabezinhle Mkhize.

Pitfalls

All of the options being considered have their pitfalls. A debt-to-equity swap may have to be offered to all creditors and could be classified by ratings firms as a default. Converting Eskom debt into sovereign bonds could flood the market and unnerve holders of South Africa’s 2.62 trillion rand of junk-rated government bonds.

“We could lower the rating by one or more notches if the utility undertakes a debt restructuring, which, in our view, could be tantamount to a default,” Standard & Poors’ said in a Nov. 25 statement.

Eskom CEO Andre de Ruyter has been credited with improving operations since taking over January but has said the debt question is in the hands of the government. He has spoken of using green finance to help reduce coal use and cut its debt. He didn’t give specifics.

Ultimately, unpalatable as it might be, the government may find it just has to meet the utility’s obligations by paying off its debt at it falls due.

“Everybody knows Eskom needs to do something about its debt, no one knows what that looks like,” said Olga Constantatos, head of credit at Futuregrowth Asset Management, which has 194 billion rand under management, including Eskom debt. “It’s in a utility death spiral as well as a debt spiral.”

Producers need to maintain supply restraint amid a sluggish recovery if they’re to shrink stockpiles

The light at the end of the tunnel isn’t getting any closer for OPEC and allied oil-producing countries, as forecasts of the world’s need for their supplies next year are cut again.

The world’s three major oil agencies — the International Energy Agency, the U.S. Energy Information Administration and the Organization of Petroleum Exporting Countries — all reduced the outlook for global oil demand in 2021 in their latest monthly reports. With two of them also increasing their forecasts for non-OPEC crude production next year, the gap that needs to be filled with barrels from the OPEC countries continues to get smaller.

The most difficult period for the producer group will be the first half of the year, before vaccinations against the Covid-19 pandemic are sufficiently widespread to allow governments to lift restrictions on movement and gatherings that have had such a dramatic impact on people’s lives and on demand for oil in 2020.

In a normal year, the first quarter is typically the weakest for oil demand, and 2021 will still be far from normal. The usual early-year weakness will be compounded by the fact that, even in the affluent countries that have secured large quantities of the most advanced vaccines, the roll-out of inoculations will take time. Working-age people outside the key healthcare sector could be among the last to benefit, which may continue to dampen economic activity and energy demand.

All three forecasters see global oil demand in the first quarter of next year remaining between 4.5% and 5% below the level seen during the same period in 2019. Any quarter-on-quarter increase from the current period will be small, with the IEA seeing no growth at all.

In that context, the decision by the OPEC+ group of countries to limit the easing of their output cuts to just 500,000 barrels a day in January, about one-quarter of the initially planned increase, makes sense.

Among the three forecasters, only the EIA saw stockpiles continuing to fall in the first half of next year if the OPEC+ countries had gone ahead with the 1.9 million barrel a day output increase they had originally planned for January (see chart below).

Limiting the output increase to 500,000 barrels a day would suffice to drive the supply/demand balance into deficit, with stockpiles falling at a rate of between 800,000 barrels a day and 2 million barrels a day in 1Q21, according to the three outlooks. Stock draws in the second quarter would be between 1 million barrels and 2.4 million barrels a day and they would increase further in the second half of the year (see chart below).

The Old Plan

How global oil stockpiles would change if OPEC+ eased ouput as originally planned

Limiting the output increase to 500,000 barrels a day would suffice to drive the supply/demand balance into deficit, with stockpiles falling at a rate of between 800,000 barrels a day and 2 million barrels a day in 1Q21, according to the three outlooks. Stock draws in the second quarter would be between 1 million barrels and 2.4 million barrels a day and they would increase further in the second half of the year (see chart below).

The New Plan

How global oil stockpiles would change if OPEC+ doesn’t ease production limits any further after the increase agreed for January

The producer group has retained the ability to make further monthly adjustments to supply targets, either upward or downward, but the latest forecasts suggest that they may want to hold off on any further easing, unless oil demand recovers faster than expected.

Slow Drain

A weaker demand outlook means OPEC sees stockpiles falling more slowly than it did in October, despite a smaller easing of output cuts

Despite keeping a tighter rein on oil supply, the deteriorating global oil demand outlook means that OPEC’s own analysts now expect stockpiles to be higher throughout 2021 than they saw them just two months ago (see chart above). By the end of next year, even with no further easing of output cuts beyond the 500,000 barrels a day agreed for January, the producer group expects global oil stockpiles to be some 670 million barrels higher than they were at the end of 2019.

The goal of bringing inventories back down to more normal levels seems ever more elusive. Since July, when OPEC first began publishing its quarterly forecast for next year, its estimate of global demand over the five quarters from 4Q 2020 to 4Q 2021 has come down by an average 2 million barrels a day, while its assessment of non-OPEC output over the same period has risen by 1 million barrels a day. That combination has cut the anticipated call-on-OPEC crude by an average 3 million barrels a day. OPEC and its allies are going to have to maintain discipline amid supply restraint for longer than they had hoped.

Total stocks of crude and products, excluding oil stored in the strategic petroleum reserve, ended the year 6% above the seasonal average for the previous five years, down from a surplus of 14% at the start of July.

Excess petroleum inventories were still in the 74th percentile for all weeks since the start of 1995, on the high side, but down from a surplus in 92nd percentile at the middle of the year.

Total inventories, including the strategic petroleum reserve, have declined in 21 out of the last 26 weeks, by a total of 136 million barrels.

Gasoline and distillate stocks have shown the fastest return to normal while commercial crude stockpiles have faced a more sluggish adjustment.

By the end of December, gasoline inventories had been reduced to almost exactly in line with the five-year average, down from a surplus to the five-year average of nearly 13% in April.

Distillate stocks, which include road diesel and heating oil, had been reduced to a surplus of 7%, down from 29% at mid-year, according to weekly statistics from the U.S. Energy Information Administration.

Commercial crude stocks were still 10% above average, down from 19% in the middle of the year, indicating slower progress (“Weekly petroleum status report”, EIA, Jan. 6).

NEARING BALANCE

Oil producers and refiners have adjusted at an exceptionally fast pace following the record shock to oil consumption caused by the first wave of the coronavirus and the associated lockdowns.

On the crude side, excess inventories have been cut by lower output from domestic shale producers and a fall in imports especially from Saudi Arabia.

On the products side, stocks have been cut by slower crude processing and a decision to focus on gasoline at the expense of middle distillates such as diesel and jet fuel.

In final week of December, U.S. refineries processed 14% less crude than average for the previous five years, even though domestic consumption was down by just 7%.

Processing restrictions are likely to persist in for the next 2-3 months which should ensure stocks of products end the first quarter below average.

Lower product stocks will support higher refining margins and a sharp increase in crude processing during the second quarter.

Based on futures prices, refining margins for gasoline and distillate delivered at the end of the second quarter have already risen by 40% and 60% from their post-crisis lows.

The principal risk to rebalancing comes from a resurgence in coronavirus and the possibility of new lockdowns to contain it, which could force fresh cuts in margins and processing.

DISTILLATE REBOUND

Consumption of petroleum products has recovered strongly, ending the year 7% below the five-year average up from a deficit over 30% at one point in April.

The strongest rebound has come in distillate, where consumption ended the year running above the five-year average.

Distillate use is closely linked to the business cycle, especially manufacturing and freight transportation, so it has bounced back in line with the surge in manufacturing.

The resurgence in diesel use is consistent with the widespread reactivation of manufacturing reported in the Institute for Supply Management’s monthly surveys and the Federal Reserve’s industrial production index.

Gasoline consumption has also recovered, ending the year 10% below the five-year average, but improvement has stalled and even reversed since the end of third quarter, when consumption was down 5%.

Gasoline consumption has been hit by the new wave of coronavirus infections and reimposition of travel restrictions and work from home orders.

The worst-affected segment remains jet fuel, however, where consumption ended the year 35% below the five-year average as a result of international travel restrictions and nervousness about flying during the epidemic.

But the reduction in excess distillate inventories and the strength of diesel demand is encouraging refiners to end their focus on gasoline production and target a more normal distribution of product outputs.

U.S. refiners boosted their combined production of distillate and jet to 74% of their output of gasoline in the final week of the year, up from a recent low of just 55% in mid-October.

If manufacturing and freight transport remain strong, while private motoring is hit by renewed coronavirus controls, refiners will shift to prioritise distillate consumption by the end of the first quarter.

The Nordic region’s pace-setting push into green transport is set to extend from cars to the air-travel market.

Iceland this month signaled plans to move toward carbon-free domestic flights by the end of the decade, while Sweden’s Heart Aerospace aims to deliver an electric plane specifically designed to ply routes linking remote Scandinavian settlements within six years.

The Gas Exporting Countries Forum (GECF) has joined a growing global consensus that blue hydrogen production from natural gas, coupled with carbon capture or CCUS technologies will play a “significant” role in the world’s transition to a sustainable energy future.
This was highlighted by GECF secretary-general Yury Sentyurin at a special virtual event ‘Blue Hydrogen Strategy’, organised by it. The event made special note of the potential for enriched natural gas, which is a blend of natural gas with hydrogen.
The hydrogen economy is the use of hydrogen as a fuel, but is subject to intensive comparison, particularly between “various colours” of hydrogen. The most popular green hydrogen is obtained from renewables but is sub-scale, while the blue is produced from natural gas after pairing with carbon capture.
“Looking at the alternative of blue hydrogen, it builds on natural gas and we already have this technology in place and the network to carry this volume is in place, for example through pipelines for natural gas,” Steinar Eikaas, Equinor’s vice president for Low Carbon Solutions.
Currently, the cost of producing blue hydrogen is 50-100% above natural gas production; however the resultant fuel is completely carbon dioxide free. The cost of green hydrogen, meanwhile, is 2-5 times above blue hydrogen.
Energy experts believe that hydrogen is the next frontier as it can fill the same purpose as, for example, natural gas, and decarbonise many of the same sectors fuelled traditionally by hydrocarbons.
“When it comes to the type of hydrogen, blue hydrogen has advantages simply because the infrastructure already exists and the oil and gas industry has the investment muscle,” he said.
Giving a European example, he said the European Union’s new hydrogen strategy, announced this July, has set very aggressive target of 40 gigawatts of green hydrogen by 2030 but left another 40 gigawatts for imports, thereby leaving the opportunity for blue hydrogen to fill in the gap. According to the latest available figures from the GECF Global Gas Outlook 2050 (2020 edition), natural gas is projected to remain the fastest growing fossil fuel with a share of 28% in the global energy mix by 2050 against the current 23%. Along the way, it will play a vital role in decarbonisation options, such as the blue hydrogen.
Referring to the Global Gas Outlook 2050, the GECF Head of Energy Economics and Forecasting Department Sokolov, said the forum developed a dedicated scenario called the “Hydrogen Scenario”, the results of which suggest blue and green hydrogen to dominate the future of hydrogen production.
“According to the results of the scenario, almost half of the produced hydrogen will be sourced from natural gas by 2050, in the form of blue hydrogen. It is also forecasted that more than 10% of the total natural gas production in 2050 will be consumed by hydrogen,” he added.

Brent crude topped $50 a barrel last week for the first time since March, a milestone for an oil market that’s been grinding its way back out of a deep slump for months.

Things aren’t back to normal yet, but the positive signals are proliferating. The enormous glut of fuel that accumulated this year on everything from tiny barges to giant supertankers is being steadily depleted.

But there’s more to this than a realignment of supply and demand — huge financial flows are also driving the price rally. In a world that’s expecting to see travel recover sharply next year, crude has become a hot Covid-vaccine trade.

“Oil is the cheapest of all reflation assets,” said Amrita Sen, co-founder of London-based consultant Energy Aspects Ltd. “With vaccines slowly rolling out, we expect investors to start returning to the oil sector and for prices to continue firming.”

In some corners of the world, the recovery in demand is almost complete. India’s largest refiner said last week its plants are processing at full capacity and it’s expecting a v-shaped rebound in fuel use. Consumption of gasoline is also at or near pre-Covid levels in China and Japan, the world’s second and fourth biggest oil consumers.

European motorists are hitting the roads again as governments relax national lockdowns in countries including the U.K., Spain, and France, according to an index of road usage and traffic compiled by Bloomberg News. Road freight is sharply higher as companies rebuild inventories and the Christmas shopping season gets in full swing.

As demand is recovering, the Organization of Petroleum Exporting Countries and its allies are keeping tight limits on production. The group canceled January’s 1.9-million-barrel-a-day supply hike and will instead add no more than 500,000 barrels a day to the market each month in the new year. Estimates for U.S. shale oil output are still falling.

Cargoes of crude are changing hands at higher prices from the North Sea to the U.S. shale heartland of Midland, Texas as consumers trawl the globe for extra supplies. Saudi Arabia raised the cost of its oil for Asia — a benchmark for the world’s refiners — by the most since August last week.

Hot Money

A more subtle shift in the market has also got traders excited. For most of December, nearby crude futures have been trading at a premium to later-dated ones, a price structure known as backwardation.

That buying of contracts at the front of the so-called price curve is evidence that managed money is flowing into the market, Eagle Commodities said in a note. The steeper the backwardation, the greater the return from holding futures from one month into the next, which encourages further buying in a “self-reinforcing cycle,” the brokerage said.

In recent weeks, cash has poured back into energy markets. Holdings of energy contracts rose by $3.6 billion through early December, according to JPMorgan Chase & Co., driven by inflows into Brent and West Texas Intermediate. Investors pumped money into U.S. exchange-traded energy funds last week, with a swing of almost $400 million from the prior period’s outflows.

Price Risks

“Right now, oil has priced in that promising future,” said Victor Shum, vice president of energy consulting at IHS Markit Ltd. in Singapore. “While we have to deal with the immediate dark Covid winter.“

There are reasons to think $50 could be oil’s ceiling for now. The price could tempt producers from Baghdad to Oklahoma to increase production. There are already tensions within OPEC+, with some members chafing at the cartel’s self-imposed supply limits.

The backwardation that’s attracting speculators could also draw real barrels into the market, because the price structure isn’t profitable for any traders still storing physical crude.

On the west coast of South Africa, a supertanker loaded oil from the tanks at the Saldanha Bay storage terminal earlier this month before sailing to Asia. It’s a reminder that there are still plenty of barrels left over from the spring surplus.

Relentless Asian buying may pause at some point, especially with Lunar New Year celebrations starting in early February. Higher-cost crude will start to dampen the profitability of refiners in the region. A standard refining process in Singapore is now loss-making when using five of the eight oil grades tracked by Oil Analytics Ltd.

For now, positive trends in fuel consumption are buoying traders’ desire for both real and paper barrels. And there could be more hot money coming down the pipe.

At the start of 2021, billions of dollars of commodities investments will be affected by a broader rebalancing of portfolios. The move could attract $8 billion of inflows into Brent and WTI futures, according to Citigroup.

“There’s been a distinct shift in the financial oil market,” said Michael Tran, an analyst at RBC Capital Markets. Speculators are buying futures and holding onto them, scared that they’ll miss out on a further rally, he said.

— With assistance by Sarah Chen, and Sharon Cho

The International Gas Union (IGU) has welcomed analysis in the International Energy Agency’s latest World Energy Outlook (WEO), demonstrating the vital economic and environmental role natural gas will play in a sustainable energy future.
In this year’s Stated Policies Scenario (STEPS), the share of natural gas in global primary energy demand expands to about 25% by 2040. Gas will also retain a critical role in the Sustainable Development Scenario (SDS), retaining the 23% share in energy in two decades’ time that it held last year.
The WEO also states that “There is a robust long-term case for gases in the energy system. In the SDS, there are services that gases provide that it would be difficult to provide cost effectively using other sources. These include high temperature heat for industry, winter heat for buildings and seasonal flexibility for power systems.”
Furthermore, “gas infrastructure is a valuable asset that can be repurposed over time to deliver large volumes of bio-methane or, with modifications, low-carbon hydrogen.”
IGU President, Professor Dr Joe M Kang, said the report again confirms the critical role gas will play in the global energy transition.
“Natural gas is a clean and versatile energy source that unlocks an opportunity for the planet to reliably meet the globally growing energy demand, reducing GHG emissions and urban pollution and allowing economies to grow,” Kang said.
“Gas demand has fared better than oil and coal amid the continuing fallout from the Covid-19 pandemic. The WEO recognises that without structural changes in the way energy is produced and consumed and prudent policy choices, the emissions reductions seen this year will be short-lived. The gas industry has a critical role to play.
“Switching to gas from dirtier fuels, like coal, oil, or conventional biomass is possible now and can be achieved quickly, with immediate benefits of cleaner air, safer environment, cut emissions, and solid path to the integration of clean technologies for continued reductions in emissions.”
Further findings and projections relating to the natural gas market in the WEO include:
n Natural gas demand will decline by only 3% in 2020 as a result of the Covid-19 pandemic, proving more resilient than oil and coal, which will see annual falls in consumption of 8% and 7% respectively. Less gas use in commercial and public buildings has been offset by increased residential consumption, while the decline in industrial demand was mitigated by fuel switching.
n In STEPS, global gas demand will expand by 15% by 2030 from the 2019 level, and by 30% by 2040. This growth will be driven by gains in south and east Asia, supported by competitive prices, a push to improve air quality and manufacturing growth.
n Even in a ‘delayed recovery scenario’, gas demand recovers to the pre-pandemic level in 2024, and climbs 24% by 2040.
n Significant investment in new gas infrastructure will also be key, with the IEA predicting that $70bn will be needed annually.
n While China and India will account for around 45% of the demand increase over the next decade, growth will also be robust in Southeast Asia and the Middle East.
n In carbon-intensive economies, gas use can reduce emissions by replacing coal. In countries planning a pathway to net-zero emissions, the gas industry will need to demonstrate progress in methane abatement, via alternative gases such as bio-methane and low-carbon hydrogen, and technologies like carbon capture, utilisation and storage.