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Last Updated: November 24, 2016
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Tighter marine fuel sulfur limits will spark changes by both refiners and vessel operators.

The sulfur content of transportation fuels has been declining for many years due to increasingly stringent regulations. In the United States, federal and state regulations limit the amount of sulfur present in motor gasoline, diesel fuel, and heating oil. New international regulations limiting sulfur in fuels for ocean-going vessels, set to take effect in 2020, have further implications for both refiners and vessel operators at a time of high uncertainty in future crude oil prices, which will be a major factor in their decisions.

Bunker fuelthe fuel typically used in large ocean-going vesselsis a mixture of petroleum-based oils. Residual oilthe long-chain hydrocarbons remaining after lighter and shorter hydrocarbon fractions such as gasoline and diesel have been separated from crude oilcurrently makes up the largest component of bunker fuel. The sulfur content of crude oil tends to be more concentrated in heavier hydrocarbon molecules, with heavier petroleum products such as residual oil having higher sulfur content than lighter ones like gasoline and diesel.

The International Maritime Organization (IMO), the 171-member state United Nations agency that sets standards for marine fuels, decided in October to move forward with a plan to reduce the maximum amount of sulfur and other pollutants present in marine fuels used on the open seas from 3.5% by weight to 0.5% by weight by 2020. This decision follows several other marine fuel regulations limiting sulfur content, such as the implementation of Emissions Control Area (ECA) requirements in coastal waters and specific sea-lanes in North America and Europe, where the maximum sulfur content of fuels was limited to 0.1% by weight starting in July 2015 (Figure 1).

Additionally, the state of California and the European Union have regulations on the sulfur content of marine fuels, and the types of fuel used when ships are at dock, waiting to dock, or are maneuvering within port. For example, a vessel approaching the port of San Francisco may have to change its fuel mix twice: once when going from the open seas higher-sulfur fuel of mostly residual oil, to an ECA compliant lower-sulfur fuel mix, and again to a marine diesel fuel compliant with California's ocean-going vessel regulations for use within ports (Figure 2).

The IMO sulfur limits that take effect in 2020 will affect the fuel used in the open seas, the largest portion of the approximately 3.9 million barrels per day of global marine fuel use, according to the International Energy Agency, presenting several challenges for both refiners and shippers.

The first challenge for refiners is to increase the supply of lower-sulfur blendstocks to the bunker fuel market. Refiners have several potential paths. One approach is to divert more low sulfur distillates into the bunker fuel market. Another option would be to use low sulfur intermediate refinery feedstocks in bunker blends. In both cases, care is required to assure that new fuels continue to meet specifications for use in marine engines.
A second challenge for refiners is what to do with the high sulfur residual oil that can no longer be blended into bunker fuel. Adding capacity to desulfurize residual oil is one option, but the economics do not currently appear to be attractive. An alternative strategy is to build or expand refinery units that take heavy hydrocarbons, such as residual oil, and upgrade them into lighter, more valuable products, but this would require large investments. In either of these cases, refineries would be faced with investments and costs that are acceptable only if there is certainty of future demand from the shipping industry.

Vessel operators also have several choices for compliance with the new IMO sulfur limits. For example, IMO regulations allow for the installation of scrubbers, which remove pollutants from ships exhaust, allowing them to continue to use higher-sulfur fuels. Some ship owners that operate primarily in coastal areas, such as cruise lines and ferries, opted to install scrubbers on their vessels as the new ECA regulations came into force. The possibility of widespread scrubber installations, which would allow for continued use of higher sulfur residual oils, could make refiners hesitant about making large investments to build refining units capable of upgrading the residual oils.

Ships also have the option of switching to new lower sulfur blends or to non-petroleum based fuels. Some newer ships and some currently being built have engines that would allow them to use liquefied natural gas (LNG) rather than petroleum-based products. However, the infrastructure to support use of LNG as a shipping fuel is currently limited in both scale and availability.
Vessel operators and shippers will also likely be faced with the higher costs as the sulfur content in marine fuels decreases and the role of distillate in the bunker fuel market increases. An example of the price difference between fuels can be observed at the refining and trading hub in Northwest Europe, known as the ARA, collectively the cities Amsterdam and Rotterdam, in the Netherlands and Antwerp, in Belgium. Prices for low sulfur gasoil, a type of distillate, in the ARA has averaged over $20 per barrel more than high sulfur fuel oil (residual oil for use as a fuel) to date in 2016. Fuel blends used to meet the new IMO regulations are likely to price somewhere in between these two fuels (Figure 3).

U.S. average regular gasoline and diesel retail prices decline
The U.S. average regular gasoline retail price dropped three cents from the previous week to $2.16 per gallon on November 21, up six cents from the same time last year. The Gulf Coast price fell six cents to $1.92 per gallon, while the West Coast, Rocky Mountain, and East Coast prices each fell five cents to $2.59 per gallon, $2.19 per gallon, and $2.17 per gallon, respectively. The Midwest price rose two cents to $2.01 per gallon.

The U.S. average diesel fuel price dropped two cents to $2.42 per gallon, down two cents from the same time last year. The Rocky Mountain price fell four cents to $2.46 per gallon, while the West Coast and Midwest prices each fell three cents to $2.73 per gallon and $2.36 per gallon, respectively. The Gulf Coast price dipped two cents to $2.30 per gallon, and the East Coast price fell a penny to $2.44 per gallon.

Propane inventories gain U.S. propane stocks increased by 1.8 million barrels last week to 102.7 million barrels as of November 18, 2016, 3.5 million barrels (3.3%) lower than a year ago. Gulf Coast and Rocky Mountain/West Coast inventories increased by 1.7 million barrels and 0.1 million barrels, respectively, while East Coast and Midwest inventories remained virtually unchanged. Propylene non-fuel-use inventories represented 4.0% of total propane inventories.

Residential heating oil price unchanged while residential propane price increases as of November 21, 2016, residential heating oil prices averaged around $2.38 per gallon, virtually unchanged from last week and less than one cent per gallon higher than last year at this time. The average wholesale heating oil price is $1.55 per gallon, nearly eight cents per gallon higher than last week and 13 cents per gallon more than a year ago.

Residential propane prices averaged nearly $2.06 per gallon, one cent per gallon more than last week and almost 11 cents per gallon more than one year ago. Wholesale propane prices averaged $0.62 per gallon, about the same price as last week but 13 cents per gallon more than last year's price.

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The Competition For The LNG Crown

The year 2020 was exceptional in many ways, to say the least. All of which, lockdowns and meltdowns, managed to overshadow a changing of the guard in the LNG world. After leapfrogging Indonesia as the world’s largest LNG producer in 2006, Qatar was surpassed by Australia in 2020 when the final figures for 2019 came in. That this happened was no surprise; it was always a foregone conclusion given Australia’s massive LNG projects developed over the last decade. Were it not for the severe delays in completion, Australia would have taken the crown much earlier; in fact, by capacity, Australia already sailed past Qatar in 2018.

But Australia should not rest on its laurels. The last of the LNG mega-projects in Western Australia, Shell’s giant floating Prelude and Inpex’s sprawling Ichthys onshore complex, have been completed. Additional phases will provide incremental new capacity, but no new mega-projects are on the horizon, for now. Meanwhile, after several years of carefully managing its vast capacity, Qatar is now embarking on its own LNG infrastructure investment spree that should see it reclaim its LNG exporter crown in 2030.

Key to this is the vast North Field, the single largest non-associated gas field in the world. Straddling the maritime border between tiny Qatar and its giant neighbour Iran to the north, Qatar Petroleum has taken the final investment decision to develop the North Field East Project (NFE) this month. With a total price tag of US$28.75 billion, development will kick off in 2021 and is expected to start production in late 2025. Completion of the NFE will raise Qatar’s LNG production capacity from a current 77 million tons per annum to 110 mmtpa. This is easily higher than Australia’s current installed capacity of 88 mmtpa, but the difficulty in anticipating future utilisation rates means that Qatar might not retake pole position immediately. But it certainly will by 2030, when the second phase of the project – the North Field South (NFS) – is slated to start production. This would raise Qatar’s installed capacity to 126 mmtpa, cementing its lead further still, with Qatar Petroleum also stating that it is ‘evaluating further LNG capacity expansions’ beyond that ceiling. If it does, then it should be more big leaps, since this tiny country tends to do things in giant steps, rather than small jumps.

Will there be enough buyers for LNG at the time, though? With all the conversation about sustainability and carbon neutrality, does natural gas still have a role to play? Predicting the future is always difficult, but the short answer, based on current trends, it is a simple yes. 

Supermajors such as Shell, BP and Total have set carbon neutral targets for their operations by 2050. Under the Paris Agreement, many countries are also aiming to reduce their carbon emissions significantly as well; even the USA, under the new Biden administration, has rejoined the accord. But carbon neutral does not mean zero carbon. It means that the net carbon emissions of a company or of a country is zero. Emissions from one part of the pie can be offset by other parts of the pie, with the challenge being to excise the most polluting portions to make the overall goal of balancing emissions around the target easier. That, in energy terms, means moving away from dirtier power sources such as coal and oil, towards renewables such as solar and wind, as well as offsets such as carbon capture technology or carbon trading/pricing. Natural gas and LNG sit right in the middle of that spectrum: cleaner than conventional coal and oil, but still ubiquitous enough to be commercially viable.

So even in a carbon neutral world, there is a role for LNG to play. And crucially, demand is expected to continue rising. If ‘peak oil’ is now expected to be somewhere in the 2020s, then ‘peak gas’ is much further, post-2040s. In 2010, only 23 countries had access to LNG import facilities, led by Japan. In 2019, 43 countries now import LNG and that number will continue to rise as increased supply liquidity, cheaper pricing and infrastructural improvements take place. China will overtake Japan as the world’s largest LNG importer soon, while India just installed another 5 mmtpa import terminal in Hazira. More densely populated countries are hopping on the LNG bandwagon soon, the Philippines (108 million people), Vietnam (96 million people), to ensure a growing demand base for the fuel. Qatar’s central position in the world, sitting just between Europe and Asia, is a perfect base to service this growing demand.

There is competition, of course. Russia is increasingly moving to LNG as well, alongside its dominant position in piped natural gas. And there is the USA. By 2025, the USA should have 107 mmtpa of LNG capacity from currently sanctioned projects. That will be enough to make the USA the second-largest LNG exporter in the world, overtaking Australia. With a higher potential ceiling, the USA could also overtake Qatar eventually, since its capacity is driven by private enterprise rather than the controlled, centralised approach by Qatar Petroleum. The appearance of US LNG on the market has been a gamechanger; with lower costs, American LNG is highly competitive, having gone as far as Poland and China in a few short years. But while the average US LNG breakeven cost is estimated at around US$6.50-7.50/mmBtu, Qatar’s is even lower at US$4/mmBtu. Advantage: Qatar.

But there is still room for everyone in this growing LNG market. By 2030, global LNG demand is expected to grow to 580 million tons per annum, from a current 360 mmtpa. More LNG from Qatar is not just an opportunity, it is a necessity. Traditional LNG producers such as Malaysia and Indonesia are seeing waning volumes due to field maturity, but there is plenty of new capacity planned: in the USA, in Canada, in Egypt, in Israel, in Mozambique, and, of course, in Qatar. In that sense, it really doesn’t matter which country holds the crown of the world’s largest exporter, because LNG demand is a rising tide, and a rising tide lifts all 😊

Market Outlook:

  • Crude price trading range: Brent – US$64-66/b, WTI – US$60-63/b
  • Despite the thaw after Texas saw a devastating big freeze, the slow ramp-up in restoring US Gulf Coast oil production and refining has supported crude oil prices, with Brent moving above the US$65/b level and WTI now in the low US$60/b level
  • Some Wall Street analysts, including Goldman Sachs, are predicting that oil prices could climb above US$70/b level based on current fundamentals, as the short-term spike gives ways to accelerating consumption trends
  • However, much will depend on OPEC+’s approach to managing supply in Q2, with a meeting set for early March; Saudi Arabia is once again urging caution, but there are many other members of the club champing at the bit to increase output and capitalise on the rising price environment


March, 01 2021
EIA forecasts the U.S. will import more petroleum than it exports in 2021 and 2022

Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.

EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.

Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.

U.S. quarterly crude oil production, net trade, and refinery runs

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021

EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.

EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.

February, 18 2021
The Perfect Storm Pushes Crude Oil Prices

In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?

To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.

Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.

That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.

Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.

 

For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.

That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.

Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.

Market Outlook:

  • Crude price trading range: Brent – US$58-61/b, WTI – US$60-63/b
  • Better longer-term prospects for fuels demand over 2021 and a severe winter storm in the southern United States that idled many upstream and downstream facilities sent global crude oil prices to their highest levels since January 2021
  • Falling levels at key oil storage locations worldwide are also contributing to the crude rally, with crude inventories in Cushing falling to a six-month low and reports of drained storage tanks in the US Gulf Coast, the Caribbean and East Asia
February, 17 2021