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Last Updated: November 30, 2017
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The United States continues trend toward exporting more gasoline than it imports


Despite record high gasoline consumption, the United States is on pace to export more gasoline than it imports for the second year in a row. Changes in regional markets, increased demand for exports, and high refinery runs are once again leading to the United States to be a net exporter in 2017.


In 2016, the United States became a net exporter of gasoline for the first time on an annual basis with net gasoline exports of 56,000 barrels per day (b/d). Through September 2017 (the most recently available monthly data), the United States averaged net gasoline exports of 55,000 b/d. The shift toward net exports of gasoline on an annual basis has been a long-running trend.


U.S. gasoline imports and exports are highly seasonal. The United States has typically been a net importer of gasoline in spring and summer months, when domestic consumption increases, and a net exporter in winter months, when demand is lower. However, for every month between April and August 2017, the United States set either record low net imports or record high net exports (Figure 1). Almost year-round net gasoline exports is a major change for U.S. gasoline markets, which is the result of one long-term trend and two more recent trends.

Figure 1. U.S. total motor gasoline trade


Changes in trends of gasoline production and consumption in the Midwest United States, in part, have driven this trend. Historically, the U.S. Gulf Coast (Petroleum Administration for Defense District (PADD) 3) supplied refined products to other regions of the United States where demand exceeded supply, such as the Midwest (PADD 2) and the U.S. East Coast (PADD 1). While the East Coast still relies on supplies from the Gulf Coast and still remains a large net importer of gasoline—619,000 b/d in 2016, the Midwest has reduced its need to draw supplies from the Gulf Coast in recent years. Midwest refineries now are running at higher rates and increased capacity, resulting in more Midwest gasoline demand being met from in-region production. Between 2006 and 2016, Midwest receipts of gasoline from the Gulf Coast declined by 278,000 b/d to 273,000 b/d.


Because of logistical and economic constraints on sending increasing gasoline supplies from the Gulf Coast to other regions, the volumes of gasoline no longer demanded by the Midwest have become available for export. With the Rocky Mountain (PADD 4) and U.S. West Coast (PADD 5) relying largely on in-region or domestic supplies, the balance of U.S. net gasoline imports or exports is between East Coast imports and Gulf Coast exports. Between 2013 and 2016, Gulf Coast gasoline exports increased by 236,000 b/d (54%), while East Coast imports increased by 41,000 b/d (7%), resulting in a shift for the United States as a whole.

Figure 2. PADD total motor gasoline trade


Available Gulf Coast gasoline supplies come at a time when both domestic and nearby fuel markets are experiencing increasing demand for multiple petroleum products, including gasoline. A majority of the growth in U.S. gasoline exports has been to markets in Mexico and Central and South America. In the first half of 2017, Mexico accounted for 53% of the 755,000 b/d of U.S. total motor gasoline exports. Low utilization of Mexican refineries and the ongoing market reforms of Mexico’s retail fuel distribution have resulted in continued increased demand for gasoline supplies from the U.S. Gulf Coast.


At the same time, U.S. domestic gasoline consumption has been increasing to record levels. U.S. gasoline consumption, as measured by product supplied, set a new monthly record high of 9.8 million b/d in August 2017. To meet the combined record domestic gasoline demand and the increased export demand for multiple petroleum products—including gasoline—U.S. refineries have been running at increasingly higher rates. U.S. gross refinery inputs set a record high of 17.8 million b/d for the week ending August 25 and have been higher than the five-year range for a majority of 2017 (Figure 3).

Figure 3. U.S. gross refinery inputs


If the trends of increasing demand from export markets and U.S. refineries producing near record levels of gasoline continues, the United States is likely to become a monthly net exporter of gasoline more consistently.


U.S. average regular gasoline prices fall, diesel prices increase


The U.S. average regular gasoline retail price fell nearly 4 cents from the previous week to $2.53 per gallon on November 27, up 38 cents from the same time last year. The Midwest price fell eight cents to $2.42 per gallon, the Gulf Coast price fell over two cents to $2.26 per gallon, the East Coast and West Coast prices each fell nearly two cents to $2.51 per gallon and $3.04 per gallon, respectively, and the Rocky Mountain price fell less than one cent, remaining at $2.54 per gallon.


The U.S. average diesel fuel price increased over 1 cent to $2.93 per gallon on November 27, 51 cents higher than a year ago. The Rocky Mountain and Gulf Coast prices each increased over two cents to $3.03 per gallon and $2.71 per gallon, respectively, the East Coast and Midwest prices each increased one cent to $2.91 per gallon and $2.88 per gallon, respectively, and the West Coast price increased less than one cent, remaining at $3.38 per gallon.


Propane inventories decline


U.S. propane stocks decreased by 0.6 million barrels last week to 73.2 million barrels as of November 24, 2017, 10.4 million barrels (12.5%) lower than the five-year average inventory level for this same time of year. Gulf Coast, Midwest, and Rocky Mountain/West Coast inventories decreased by 0.5 million barrels, 0.3 million barrels, and 0.2 million barrels, respectively, while East Coast inventories rose by 0.5 million barrels. Propylene non-fuel-use inventories represented 3.5% of total propane inventories.


Residential heating oil and propane prices continue to increase


As of November 27, 2017, residential heating oil prices averaged $2.85 per gallon, over 2 cents per gallon more than last week and almost 45 cents per gallon higher than last year’s price at this time. The average wholesale heating oil price for this week is just under $2.04 per gallon, nearly 1 cent per gallon less than last week but 45 cents per gallon higher than a year ago.


Residential propane prices averaged $2.43 per gallon, almost 2 cents per gallon more than last week and nearly 36 cents per gallon higher than a year ago. Wholesale propane prices averaged $1.12 per gallon, unchanged from last week but 48 cents per gallon higher 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