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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TODAY IN ENERGY: The U.S. leads global petroleum and natural gas production with record growth in 2018

U.S. petroleum and natural gas production increased by 16% and by 12%, respectively, in 2018, and these totals combined established a new production record. The United States surpassed Russia in 2011 to become the world's largest producer of natural gas and surpassed Saudi Arabia in 2018 to become the world's largest producer of petroleum. Last year’s increase in the United States was one of the largest absolute petroleum and natural gas production increases from a single country in history.

For the United States and Russia, petroleum and natural gas production is almost evenly split; Saudi Arabia's production heavily favors petroleum. Petroleum production is composed of several types of liquid fuels, including crude oil and lease condensate, natural gas plant liquids (NGPLs), and bitumen. The United States produced 28.7 quadrillion British thermal units (quads) of petroleum in 2018, which was composed of 80% crude oil and condensate and 20% NGPLs.

estimated petroleum and natural gas production in selected countries

Source: U.S. Energy Information Administration, based on International Energy Statistics
Note: Petroleum includes crude oil, condensate, and natural gas plant liquids.

U.S. crude oil production increased by 17% in 2018, setting a new record of nearly 11.0 million barrels per day (b/d), equivalent to 22.8 quadrillion British thermal units (Btu) in energy terms. Production in the Permian region of western Texas and eastern New Mexico contributed to most of the growth in U.S. crude oil production. The United States also produced 4.3 million b/d of NGPLs in 2018, equivalent to 5.8 quadrillion Btu. U.S. NGPL production has more than doubled since 2008, when the market for NGPLs began to expand.

U.S. dry natural gas production increased by 12% in 2018 to 28.5 billion cubic feet per day (Bcf/d), or 31.5 quadrillion Btu, reaching a new record high for the second year in a row. Ongoing growth in liquefied natural gas export capacity and the expanded ability to reach new markets have supported increases in U.S. natural gas production.

Russia’s crude oil and natural gas production also reached record levels in 2018, encouraged by increasing global demand. Russia exports most of the crude oil that it produces to European countries and to China. Since 2016, nearly 60% of Russia’s crude oil exports have gone to European member countries in the Organization for Economic Cooperation and Development (OECD). Russia’s crude oil is also an important source of supply to China and neighboring countries.

Russia’s natural gas production increased by 7% in 2018, which exceeded the growth in exports. The Yamal liquefied natural gas (LNG) export facility, which loaded its first cargo in December 2017, can liquefy more than 16 million tons of natural gas annually and accounts for almost all of the recent growth in Russia’s LNG exports. Since 2000, more than 80% of Russia’s natural gas exports have been sent to Europe.

Saudi Arabia’s annual average crude oil production increased slightly in 2018, but it remained lower than in 2016, when Saudi Arabia’s crude oil output reached a record high. Saudi Arabia’s crude oil production reached an all-time monthly high in November 2018 before the December 2018 agreement by the Organization of the Petroleum Exporting Countries (OPEC) to extend production cuts.

In addition to exporting and refining crude oil, Saudi Arabia consumes crude oil directly for electricity generation, which makes Saudi Arabian crude oil consumption highest in the summer when electricity demand for space cooling is relatively high. Since 2016, Saudi Arabia’s direct crude oil burn for electric power generation has decreased for a number of reasons, including demand reductions from a partial withdraw of power subsidies, greater use of residual fuel oil, and increased availability of domestic natural gas.

Crude oil exports account for about 60% of Saudi Arabia’s total economic output. China, along with Japan, South Korea, Taiwan, and the United States remain critical markets for Saudi Arabia’s petroleum exports.

August, 21 2019
Your Weekly Update: 12 - 16 August 2019

Market Watch 

Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b

  • Saudi Arabia’s overtures to further stabilise prices was met with a largely positive response by the market, allowing crude prices to claw back some ground after being hammered by demand concerns
  • Saudi officials reportedly called other members in the OPEC and OPEC+ producer clubs to discuss options on how to stem the recent rout in prices, with an anonymous official quoted as saying that it ‘would not tolerate continued price weakness’
  • Reports suggest that Saudi Arabia plans to keep its oil exports at below 7 mmb/d in September according to sales allocations, which was seen as a stabilising factor in crude price trends
  • This came after crude prices fell as the US-China trade war entered a new front, causing weakness in the Chinese Yuan, although President Trump has floated the idea of delaying the new round of tariffs beyond the current implementation timeline of September 1
  • Crude had also fallen in response to a slide in American crude oil stockpiles and a receding level of tensions in the Persian Gulf
  • In a new report, the International Energy Agency said that the outlook for global oil demand is ‘fragile’ on signs of an economic slowdown; there is also concern that China will target US crude if the US moves ahead with its tariff plan
  • The US active rig count lost another 8 rigs – 6 oil and 2 gas – the sixth consecutive weekly loss that brought the total number of active rigs to 934
  • Demand fears will continue to haunt the market, which will not be offset so easily of Saudi-led efforts to limit production; as a result, crude prices will trade rangebound with a negative slant in the US$56-58/b range for Brent and US$52-54/b for WTI


Headlines of the week

Upstream

  • Nearly all Anadarko shareholders have approved the Occidental Petroleum deal, completing the controversial takeover bid despite investor Carl Icahn’s attempts to derail the purchase
  • Crude oil inventories in Western Canada have fallen by 2.75 million barrels m-o-m to its lowest level since November 2017, as the production limits in Alberta appear to be doing their job in limiting a supply glut while output curbs are slowly being loosened on the arrival of more rail and pipeline capacity
  • Mid-sized Colorado players PDC Energy and SRC Energy – both active in the Denver-Julesburg Basin – are reportedly in discussion to merge their operations
  • Pemex has been granted approval by the National Hydrocarbon Commission to invest US$10 billion over 25 years to develop onshore and offshore exploration opportunities in Mexico
  • Qatar Investment Authority has acquired a ‘significant stake’ in major Permian player Oryx Midstream Services from Stonepeak Infrastructure Partners for some US$550 million, as foreign investment in the basin increases
  • PDVSA and CNPC’s Venezuelan joint venture Sinovensa has announced plans to expand blending capacity – lightening up extra-heavy Orinoco crude to medium-grade Merey – from a current 110,000 b/d to 165,000 b/d
  • BHP has approved an additional US$283 million in funding for the Ruby oil and gas project in Trinidad and Tobago, with first production expected in 2021
  • CNPC, ONGC Videsh and Petronas have reportedly walked away from their onshore acreage in Sudan, blaming unpaid oil dues on production from onshore Blocks 2A and 4 that have already reached more than US$500 million

Midstream/Downstream

  • Expected completion of Nigeria’s huge planned 650 kb/d Dangote refinery has been delayed to the end of 2020, with issues importing steel and equipment cited
  • Saudi Aramco’s US refining arm Motiva announced plans to shut several key units at its 607 kb/d Port Arthur facility in Texas for a 2-month planned maintenance, affecting its 325 kb/d CDU and the naphtha processing plant
  • ADNOC has purchased a 10% stake in global terminal operator VTTI, expanding its terminalling capacity in Asia, Africa and Europe
  • A little-known Chinese contractor Wison Engineering Services has reportedly agreed to refurbish Venezuela’s main refineries in a barter deal for oil produced, in a bid for Venezuela to evade the current US sanctions on its crude exports
  • Swiss downstream player Varo Energy will increase its stake in the 229 kb/d Bayernoil complex in Germany to 55% after purchasing BP’s 10% stake
  • India has raised the projected cost estimate of its giant planned refinery in Maharashtra – a joint venture between Indian state oil firms with Saudi Aramco and ADNOC – to US$60 billion, after farmer protests forced a relocation

Natural Gas/LNG

  • The government of Australia’s New South Wales has given its backing to South Korea’s Epik and its plan to build a new LNG import terminal in Newcastle
  • Kosmos Energy is proposing to build two new LNG facilities to tap into deepwater gas resources offshore Mauritania and Senegal under development
  • In the middle of the Pacific, the French territory of New Caledonia has started work on its Centrale Pays Project, a floating LNG terminal with an accompanying 200-megawatt power plant, with Nouvelle-Caledonia Energie seeking a 15-year LNG sales contract for roughly 200,000 tons per year
August, 16 2019
The State of the Industry: Q2 2019

The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.

In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.

As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.

 After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.

And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.

So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.

Supermajor Financials: Q2 2019

  • ExxonMobil – Revenue (US$69.1 billion, down 6% y-o-y), Net profit (US$3.1 billion, down 22.5% y-o-y)
  • Shell - Revenue (US$90.5 billion, down 6.5% y-o-y), Net profit (US$3 billion, down 50% y-o-y)
  • Chevron – Revenue (US$36.3 billion, down 10.4% y-o-y), Net profit (US$4.3 billion, up 26% y-o-y)
  • BP - Revenue (US$73.7 billion, down 4.11% y-o-y), Net profit (US$2.8 billion, flat y-o-y)
  • Total - Revenue (US$51.2 billion, down 2.5% y-o-y), Net profit (US$2.89 billion, down 18.6% y-o-y)
August, 14 2019