Easwaran Kanason

Co - founder of NrgEdge
Last Updated: January 1, 2017
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Oil in 2017

With OPEC defying the pessimists and actually agreeing on a production freeze, oil prices have rallied. Will this be a good sign as we enter into 2017? The World Bank predicts that oil prices would average US$53-55/b over 2017, a sentiment echoed by the EIA in the US. Both have no issued new forecasts since OPEC’s agreement to slash production by 1.2 mb/d, but it is likely that the target range has now shifted to the a range of US$60-65/b.

With Saudi Arabia already informing its customers of cuts in their January 2017 deliveries, it seems there is will enough within OPEC to follow through on the agreement. The issue now moved from agreement to enforcement, and therein lies some thorns. Historically, the Gulf state – Saudi Arabia, UAE and Kuwait – have been the most disciplined in enforcing cuts, with members elsewhere – Venezuela, Ecuador and Angola – more likely to discreetly flout the quotas. OPEC is also meeting with some non-OPEC producers in Vienna this week to see if consensus can be made on non-OPEC cuts; Russia has publically agreed to a 300 kb/d cut (with caveats, of course), and OPEC says a non-OPEC cut of 600 kb/d is a ‘must.’

This might be an issue in the US, particularly with the new Trump administration that wishes to encourage drilling. While oil prices rose immediately in the wake of the OPEC announcement, they fell back quickly again as US oil production announced a weekly increase. The Baker Hughes survey of active oil rigs in the US has risen to its highest weekly level in almost a year, as onshore producers restarted rigs in response to higher price signal. From US$55/b last Thursday, crude oil prices are now in the low US$50s. Donald Trump’s provisional cabinet is full of climate skeptics and energy bulls and he has named Scott Pruitt as the head of the new American Environmental Protection Agency, with the fossil fuel industry ally is likely to call for further deregulation in American hydrocarbons. With Keystone XL back as a possibility and longer-term moves to open up drilling in new areas like the Arctic likely, it could unleash a new wave of oil in the market depressing prices. The US under Trump is not going to agree to any supply cuts, which may very well defeat the entire purpose of the OPEC exercise. Saudi Arabia’s attempt to wipe up US shale oil by keeping prices down has only kept the shale producers at bay, who will return once prices hit a decent level. This ebb and flow will persist, and we believe a general oversupply will endure.

Here’s our prediction. The OPEC quotas will hold, but the cuts will not be as deep as envisioned because some members – especially Iran – will take advantage of the situation to sneak extra sales. The big producers – Russia, Saudi Arabia, Iraq and Iran will focus on relative pricing to defend their market share. American production will continue to be nimbly driven by price signals, balancing out the cuts elsewhere. Oil prices will strengthen – probably to the US$55-60/b level – which is a good place to be, all things considered. It won’t be the dramatic recovery that many will hope for, but it won’t be a complete collapse either, and in this environment that’s good enough already.

Natural Gas in 2017

With OPEC and a group of major non-OPEC producers coming together to agree on shave up to 1.8 mb/d in their oil production, it is a rising tide that will lift all other energy commodities. This includes natural gas, once the red-headed cousin of oil but now a crowning beauty of its own.

In the natural gas space, this will lead to higher prices for pipeline gas, rising slightly from prices that are already relatively cheap. With a cold winter expected, natural gas demand will be high in the northern hemisphere as well, while domestic consumption in both Europe and the US is on a steady growth trend. However, the bigger impact will be in the LNG space.

On the LNG side, higher crude prices means higher LNG prices. Spot prices in Asia have already hit US$8.10/mmbtu in the last week, the highest since mid-2015, due to the OPEC agreement and cold weather in north Asia and Europe. LNG, though, is a contract market. It is estimated that some 80% of LNG sold in the world in based on long-term contracts linked to oil. Typically a function of oil, indexation may vary but the general rule of thumb is that a US$1/b increase leads to a US$0.07-0.15/mmbtu increase in oil-indexed LNG contract prices. But those are for existing contracts, inherited from the days when the seller was king and could command all sorts of price structures – S-curves, for example - to benefit them. Today, that is a thing of the past. With the glut of LNG currently existing and more still to come – Wheatstone and Gorgon in Australia being the two big ones in 2017 – LNG has been a buyer’s market for the last two years And the buyers are getting bolder.

Specifically, the Japanese buyers are getting bolder. If 2015 and 2016 were the years when Japanese buyers realised that a low price environment gave them far more clout, 2017 will be the year when they begin to assert themselves. Moves towards this are already happening. Japan is trying to render location destination clauses in existing long-term LNG contracts void through anti-competitive laws, which would free Japan buyers like Tokyo Gas and Chubu Electric to swap and re-route cargoes, instead of being locked into specific ports. Newer contracts will probably have to do away with the clauses altogether. This creates a more dynamic environment where buyers can move their LNG cargoes around based on supply and demand, effectively becoming traders. It is a step towards creating an Asia trading hub for LNG, with Singapore having already developed its own sport LNG price assessments and agreeing to work with Japan to possibly create a Singapore-Japan benchmark. China and Korea, both large LNG consumers as well, have also launched attempts of their own, with the Shanghai gas derivatives exchange starting up last month. Efforts towards this will continue, and 2017 will see a more vibrant LNG trading market.

Looking ahead, there is so much LNG coming onto the market that it is almost a tsunami. Canada’s projects on the BC Pacific Coast. The US Gulf of Mexico projects, with the newly-expanded Panama Canal as a conduit. The vast projects off Western Australia. Plenty of supply coming from Mozambique and Papua New Guinea as well. All of these volumes will be chasing Asian clients. LNG will be a buyer’s market for a long time to come, and 2017 will be the year that companies, utilities and governments will step up to expand and create infrastructure to support a gas-rich future.

Downstream Oil in 2017

The upstream portion of the oil industry is ending the year on a bit of a cheer, with rallying crude prices. In the downstream section, however, it has been a challenging year and 2017 repeats the same situation as 2016.

Looking specifically at Asia, refined oil product demand is slowing down. Part of this is due to the natural decline in Japan and South Korea, and part of this is due to a natural deceleration in China, where annual growth rates at 9-10% could never be sustained indefinitely. Demand growth in India and developing economies is improving, but years of high oil prices have pushed their infrastructure in different directions, not necessarily to the benefit of oil, even in a lower price environment.

Even if there is good demand growth, not all of it will benefit refineries. One bright spark in the downstream arena has been petrochemicals, with countries like China still adding capacity. Traditionally, these have depended on naphtha as their feedstock – hence the trend over the past decade for integrated refinery-petchem facilities. US shale gas remains a gamechanger here. There is so much ethane (and to a lesser extent, LPG liquids propane and butane) coming out of the US that prices are low and petrochemical operations in Asia are reconfiguring to focus on natural gas liquids as feedstock. BP estimates that a third of global downstream demand growth may bypass refineries altogether, placing further pressure on refineries.

This is not good for refiners. In general, refined oil product cracks in Asia have been at historical lows in 2016, thought there are few bright spots like naphtha. Though this will ebb and flow depending on shortages and seasonal demand, the overall trend is shrinking cracks. Cheap oil prices have not caused an equivalent surge in Asian oil demand. In fact, there is simply too much product sloshing around the market. This is been exacerbated in 2016 when Chinese independent refiners – the teapots – were granted licences to import crude for the first time, leading to them raising runs to records levels and lifting Chinese exports. Far from being a ‘sink’ for refined products, China is now becoming a net exporter. However, in a move last week, China removed export quotas for the teapots, effectively preventing them from exporting any of their products. Their import licences may still be held steady, but the teapots will now have to consider the limited domestic market when planning runs. This could improve the supply glut in Asia somewhat, but traditional product ‘sinks’ are evolving on their own.

Vietnam’s second refinery, Nghi Son, is supposed to start up in mid-2017. It will face delays. And if Dong Quat is any precedent, Nghi Son will face production troubles in its first year. So Vietnam will remain a reliable product ‘sink’ in 2017, but this will dissipate when Nghi Son comes onstream. India, where oil product growth has been strong this year, will also absorb major amounts of products, but the Indian refiners – IOC, BPCL and HPCL – all have extensive capacity upgrade plans over the next five years, removing this window. Indonesia continues to claim ambitious refining plans that could potentially eliminate the need for imports, but it has been spouting this line for a decade now and there seems to be little movement beyond announcement in this arena, leaving Indonesia a large ‘sink’ for the time being. But Indonesian oil product specs are generally lower than the average Asian standards, limiting the refineries it can buy product from. There will be growth else – notably Myanmar and Bangladesh – but this will be unable to offset the declines in Japan and South Korea.

This is a death knell for major export-oriented refinery projects in Asia. Projects like Petronas’ RAPID in Malaysia, due for startup in 2019, will go ahead, but fewer will make it off the drawing board. New refineries will be contained to net importer countries, as they try to reduce their import burden, as we have seen this year in Pakistan, Uganda and Middle East countries moving up the value chain. Product demands will also continue to move up the barrel, placing more pressure on simple, topping refineries. 2016 saw a slew of refinery sales and closures in Europe – even low oil prices couldn’t help a determined structural trend – and that is a likely future for Asian downstream. There will be no major surprised downstream in 2017, just confirmation of ongoing trends.

Corporate Oil in 2017

Rex Tillerson, head of ExxonMobil since 2006, is packing his bags and heading to the White House to serve as Donald Trump’s Secretary of State. As part of his job, he will be jetting around the world promoting American interests. That’s not much different in scope from his current position, except that corporate deal-making is very different from diplomacy.

It’s an indication that 2017 will be a pivot away from prevailing corporate trends in the energy business. Under Tillerson, US ties with Russia are likely to get closer, as the Trump administration places business and capitalist interests above issues such as healthcare, environment and social justice that have taken the forefront. Tillerson will pass his seat to Darren Woods, the current head of refining at ExxonMobil, with the company likely to be the only one that will pursue a diversified strategy among the supermajors. Under Woods, ExxonMobil’s refining arm has remained strong despite low margins, having already embarked on a divestment drive that saw the company dispose of peripheral assets in marginal markets.

ExxonMobil, like Shell and Chevron, will remain global brands. But the assets will no longer be controlled by them. Shell has been following ExxonMobil’s move, selling its downstream and upstream assets globally to pay for its pricey acquisition of the BG Group. Natural gas and chemicals are in Shell’s future, with downstream now of lesser concern; Shell, like ExxonMobil in Latin America, will now merely licences its name to third-party players. BP has already done the same over the last decade, with its logo now a rarity in retail across the world, though oddly enough it is tying up with Reliance in India. Chevron’s divestment extends further than downstream, moving into smaller-scale upstream assets, with its attempt to exit Bangladesh and Thailand in recent months. 2016 has been a year of divestments and debt-paring among the supermajors as they seek to become leaner and meaner, just like Petrobras, though for completely different reasons. Meanwhile, France’s Total still has ambitions of being a global behemoth that the supermajors once were, picking up assets in Asia and Africa. This will continue in 2017, with the directions clear. Shell to natural gas and chemicals, BP to LNG, Chevron to large-scale upstream and ExxonMobil everywhere, with top priority to sort out its acquisition of InterOil in PNG.

The vacuum left by the supermajors particularly in downstream has been picked up by global traders. Players like Vitol, Glencore and Gunvor have been extending their trading empires to actual retail participation since 2013, and the move will continue in 2017. Some might even try to set up brands of their own, instead of piggy-backing on existing ones (and their associated licensing fees).

Meanwhile, the national counterparts of the supermajors, the major NOCs, will still find 2017 a challenging year. Oil prices have risen, but nowhere near the level that required to balance national budgets. Saudi Aramco and to a lesser extent Adnoc and KPC have the reserves to see through the storm, but PDVSA is in trouble. Iraq and Iran will flout OPEC supply quotas to sneak a few extra sales to resume what they see as their rightful position, while Libya tries to rebuild its infrastructure and Nigeria tries its hand at privatisation. Indonesia’s Pertamina will continue to flounder in too many directions, Malaysia’s Petronas will remain weak and Brazil’s Petrobras will continue its fire sale to reduce its huge debts. China’s triad – PetroChina, Sinopec and CNOOC – will continue to extend their tendrils oversees, while Japan’s bloated energy sector will try to consolidate. And largely fail, resulting in a friendly informal cooperation instead. Russia has a lot of debt issues simmering under Putin’s bluster. India’s state players are probably in the best position, where energy demand is sprinting ahead.

Higher crude oil prices will be a good way to start off 2017 for most energy companies; but there’s still a lot of work to be done. Much like the global political landscape, corporate energy players will become more insular, focusing on specific areas of profit instead of a broad-based strategy. The notion of an integrated player with tentacles in every pie is over. With the possible exception of ExxonMobil.

Have a productive year ahead!

 

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Financial Review: 2019

Key findings

  • Brent crude oil daily average prices were $64.16 per barrel in 2019—11% lower than 2018 levels
  • The 102 companies analyzed in this study increased their combined liquids and natural gas production 2% from 2018 to 2019
  • Proved reserves additions in 2019 were about the same as the 2010–18 annual average
  • Finding plus lifting costs increased 13% from 2018 to 2019
  • Occidental Petroleum’s acquisition of Anadarko Petroleum contributed to the largest reserve acquisition costs incurred for the group of companies since 2016
  • Refiners’ earnings per barrel declined slightly from 2018 to 2019

See entire annual review

May, 26 2020
From Certain Doom To Cautious Optimism

A month ago, the world witnessed something never thought possible – negative oil prices. A perfect storm of events – the Covid-19 lockdowns, the resulting effect on demand, an ongoing oil supply glut, a worrying shortage of storage space and (crucially) the expiry of the NYMEX WTI benchmark contract for May, resulted in US crude oil prices falling as low as -US$37/b. Dragging other North American crude markers like Louisiana Light and Western Canadian Select along with it, the unique situation meant that crude sellers were paying buyers to take the crude off their hands before the May contract expired, or risk being stuck with crude and nowhere to store it. This was seen as an emblem of the dire circumstances the oil industry was in, and although prices did recover to a more normal US$10-15/b level after the benchmark contract switched over to June, there was immense worry that the situation would repeat itself.

Thankfully, it has not.

On May 19, trade in the NYMEX WTI contract for June delivery was retired and ticked over into a new benchmark for July delivery. Instead of a repeat of the meltdown, the WTI contract rose by US$1.53 to reach US$33.49/b, closing the gap with Brent that traded at US$35.75b. In the space of a month, US crude prices essentially swung up by US$70/b. What happened?

The first reason is that the market has learnt its lesson. The meltdown in April came because of an overleveraged market tempted by low crude oil prices in hope of selling those cargoes on later at a profit. That sort of strategic trading works fine in a normal situation, but against an abnormal situation of rapidly-shrinking storage space saw contract holders hold out until the last minute then frantically dumping their contracts to avoid having to take physical delivery. Bruised by this – and probably embarrassed as well – it seems the market has taken precautions to avoid a recurrence. Settling contracts early was one mechanism. Funds and institutions have also reduced their positions, diminishing the amount of contracts that need to be settled. The structural bottleneck that precipitated the crash was largely eliminated.

The second is that the US oil complex has adjusted itself quickly. Some 2 mmb/d of crude production has been (temporarily) idled, reducing supply. The gradual removal of lockdowns in some US states, despite medical advisories, has also recovered some demand. This week, crude draws in Cushing, Oklahoma rose for the second consecutive week, reaching a record figure of 5.6 million barrels. That increase in demand and the parallel easing of constrained storage space meant that last month’s panic was not repeated. The situation is also similar worldwide. With China now almost at full capacity again and lockdowns gradually removed in other parts of the world, the global crude marker Brent also rose to a 2-month high. The new OPEC+ supply deal seems to be working, especially with Saudi Arabia making an additional voluntary cut of 1 mmb/d. The oil world is now moving rapidly towards a new normal.

How long will this last? Assuming that the Covid-19 pandemic is contained by Q3 2020, then oil prices could conceivably return to their previous support level of US$50/b. That is a big assumption, however. The Covid-19 situation is still fragile, with major risks of additional waves. In China and South Korea, where the pandemic had largely been contained, recent detection of isolated new clusters prompted strict localised lockdowns. There is also worry that the US is jumping the gun in easing restrictions. In Russia and Brazil – countries where the advice to enforce strict lockdowns was ignored as early warning signs crept in – the number of cases and deaths is still rising rapidly. Brazil is a particular worry, as President Jair Bolosnaro is a Covid-19 skeptic and is still encouraging normal behaviour in spite of the accelerating health crisis there. On the flip side, crude output may not respond to the increase in demand as easily, as many clusters of Covid-19 outbreaks have been detected in key crude producing facilities worldwide. Despite this, some US shale producers have already restarted their rigs, spurred on by a need to service their high levels of debt. US pipeline giant Energy Transfer LP has already reported that many drillers in the Permian have resumed production, citing prices in the high-US$20/b level as sufficient to cover its costs.

The recovery is ongoing. But what is likely to happen is an erratic recovery, with intermittent bouts of mini-booms and mini-busts. Consultancy IHS Markit Energy Advisory envisions a choppy recovery with ‘stop-and-go rallies’ over 2020 – particularly in the winter flu season – heading towards a normalisation only in 2021. It predicts that the market will only recover to pre-Covid 19 levels in the second half of 2021, and a smooth path towards that only after a vaccine is developed and made available, which will be late 2020 at the earliest. The oil market has moved from certain doom to cautious optimism in the space of a month. But it will take far longer for the entire industry to regain its verve without any caveats.

Market Outlook:

  • Crude price trading range: Brent – US$33-37/b, WTI – US$30-33/b
  • Demand recovery has underpinned a rally in oil prices, on hopes that the worst of the demand destruction is over
  • Chinese oil demand is back to the 13 mmb/d level, almost on par year-on-year
  • News that development of potential Covid-19 vaccines are reaching testing phase also cheered the market
  • The US active oil and gas rig count lost another 35 rigs to 339, down 648 sites y-o-y

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May, 23 2020
EIA expects record liquid fuels inventory builds in early 2020, followed by draws

quarterly global liquid fuels productionand consumption balance

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

As mitigation efforts to contain the 2019 novel coronavirus disease (COVID-19) pandemic continue to lead to rapid declines in petroleum consumption around the world, the production of liquid fuels globally has changed more slowly, leading to record increases in the amount of crude oil and other petroleum liquids placed into storage in recent months. In its May Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global inventory builds will be largest in the first half of 2020. EIA estimates that inventory builds rose at a rate of 6.6 million barrels per day (b/d) in the first quarter and will increase by 11.5 million b/d in the second quarter because of widespread travel limitations and sharp reductions in economic activity.

After the first half of 2020, EIA expects global liquid fuels consumption to increase, leading to inventory draws for at least six consecutive quarters and ultimately putting upward pressure on crude oil prices that are currently at their lowest levels in 20 years.

As with the March and April STEO, EIA’s forecast reductions in global oil demand arise from three main drivers: lower economic growth, less air travel, and other declines in demand not captured by these two categories, largely related to reductions in travel because of stay-at-home orders. Based on incoming economic data and updated assessments of lockdowns and stay-at-home orders across dozens of countries, EIA has further lowered its forecasts for global oil demand in 2020 in the May STEO. The STEO is based on macroeconomic projections by Oxford Economics (for countries other than the United States) and by IHS Markit (for the United States).

changes in quarterly global petroleum liquids consumption

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

In the May STEO, EIA forecasts global liquid fuels consumption will average 92.6 million b/d in 2020, down 8.1 million b/d from 2019. EIA forecasts both economic growth and global consumption of liquid fuels to increase in 2021 but remain lower than 2019 levels. Any lasting behavioral changes to patterns in transportation and other forms of oil consumption once COVID-19 mitigation efforts end, however, present considerable uncertainty to the increase in consumption of liquid fuels, even if gross domestic product (GDP) growth increases.

Members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) agreed to new production cuts in early April that will remain in place throughout the STEO forecast period ending in 2021. EIA assumes OPEC members will mostly adhere to announced cuts during the first two months of the agreement (May and June) and that production compliance will relax later in the forecast period as stated production cuts are reduced and global oil demand begins growing.

EIA forecasts OPEC crude oil production will fall to less than 24.1 million b/d in June, a 6.3 million b/d decline from April, when OPEC production increased following an inconclusive meeting in March. If OPEC production declines to less than 24.1 million b/d, it would be the group’s lowest level of production since March 1995. The forecast for June OPEC production does not account for the additional voluntary cuts announced by Saudi Arabia’s Energy Ministry on May 11.

EIA expects OPEC production will begin increasing in July 2020 in response to rising global oil demand and prices. From that point, EIA expects a gradual increase in OPEC crude oil production through the remainder of the forecast and for production to rise to an average of 28.5 million b/d during the second half of 2021.

changes in quarterly global petroleum liquids production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

EIA forecasts the supply of non-OPEC petroleum and other liquid fuels will decline by 2.4 million b/d in 2020 compared with 2019. The steep decline reflects lower forecast oil prices in the second quarter as well as the newly implemented production cuts from non-OPEC participants in the OPEC+ agreement. EIA expects the largest non-OPEC production declines in 2020 to occur in Russia, the United States, and Canada.

May, 20 2020