Possibly discontent with the (lack of) progress with China over a new trade deal, US President Donald Trump is turning its sights elsewhere. After slapping tariffs on steel from close allies in North America and the European Union and embarking on an ever-escalating trade war with China, it is now the turn of Mexico.
In a surprise move, President Trump announced that imports of all Mexican goods into the US would now be subject to a 5% tariff. And this would rise unless Mexico stops the flow of illegal immigration across the Rio Grande, with US officials confirming that the tariffs would reach to 25% by October. This came as a blindside to the market. Not only was the North American Free Trade Agreement (NAFTA) successfully renegotiated only recently, some American manufacturers had only just recalibrated their supply chains away from China to Mexico as a result of the trade war. The new tariffs on Mexico have been described as ‘very disruptive’, threatening a symbiotic relationship that has largely benefitted the USA.
Most of all in energy. US refineries along the Gulf Coast have long been geared to process heavy crude from Mexico, Venezuela and Canada. With Canadian oil sands stuck in Alberta over a lack of pipeline infrastructure and Venezuela being persona non grata, Mexican oil is increasingly prized by refineries owned by ExxonMobil, Chevron, Marathon Oil and more. Some 630,000 b/d of Mexican crude is shipped to US refineries that are too finely calibrated for those grades to be easily replaced. A back-of-the-envelope calculation suggests that the tariffs will add about US$3/b to the cost of Maya crude to the US, slashing current refining margins by half. This will be passed on to the American consumer, just ahead of the summer driving season. And these Gulf refineries also send more than a million barrels of fuels back to Mexico (which has a net fuel deficit), worth some US$20 billion in revenue. Natural gas trade will also be affected – threatening the 20 pipelines sending some 5 bcf/d across the southern border, along with new LNG projects in Mexico that are dependent on American shale gas.
While Mexico has made overtures to mitigate the flow of illegal immigration, it is not likely to just take the bullet. Reprisal tariffs are likely, mainly on US fuels and, crucially, US corn that impacts the two key America industries supporting Trump: energy and farming. Crude prices have already tumbled in response to the Mexican tariffs, with fears that it could cut the legs off already weak global energy demand.
And there’s more. President Trump has ordered that India’s status as a preferential trade partner be removed, which would result in the imposition of tariffs on a package of currently 2,000 duty-free products. While India is in a weaker bargaining position than China in capitulating to American demands, it is currently a major destination for American crude after sanctions on Iranian crude and the flourishing US LNG export industry is also banking on increased demand from India. Reprisal moves from India, where Prime Minister Narendra Modi has just won a resounding election victory, must be expected, particularly since Modi campaigned on a nationalist campaign reminiscent of a diluted Trump message.
And if it is China, India and Mexico today, who else will it be tomorrow? The US’ trade war stance may score short-term political points but it adds much more fragility to the market. In the meantime crude oil imports from Mexico will be subject to a 5% tariff, which will rise to 10% on July 1 and continue rising towards 25% in October, if the immigration issue is not resolved.
US Trade War Tariff Targets:
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In its latest Short-Term Energy Outlook (STEO), released on January 12, the U.S. Energy Information Administration (EIA) forecasts that generation from natural gas-fired power plants in the U.S. electric power sector will decline by about 8% in 2021. This decline would be the first annual decline in natural gas-fired generation since 2017. Forecast generation from coal-fired power plants will increase by 14% in 2021, after declining by 20% in 2020. EIA forecasts that generation from nonhydropower renewable energy sources, such as solar and wind, will grow by 18% in 2021—the fastest annual growth rate since 2010.
The shift from coal to natural gas marked a significant change in the energy sources used to generate electricity in the United States in the past decade. This shift was driven primarily by the sustained low natural gas price. In 2020, natural gas prices were the lowest in decades: the nominal price of natural gas delivered to electric generators averaged $2.37 per million British thermal units (Btu). For 2021, EIA forecasts the average nominal price of natural gas for power generation will rise by 41% to an average of $3.35 per million Btu, about where it was in 2017. In contrast, EIA expects nominal coal prices will rise just 6% in 2021.
The large expected rise in natural gas prices is the primary driver in EIA’s forecast that less electricity will be generated from natural gas and more electricity will come from coal-fired power plants in 2021 than in recent years. EIA expects about 36% of total U.S. electricity generation in 2021 will be fueled by natural gas, down from 39% in 2020. The forecast coal-fired generation share in 2021 rises to 22% from 20% last year. However, these forecast generation shares are still different from 2017, when natural gas and coal each fueled 31% of total U.S. electricity generation.
Significant growth in electricity-generating capacity from renewable energy sources in 2021 is also likely to affect the mix of fuels used for power generation. Power developers are scheduled to add 15.4 gigawatts (GW) of new utility-scale solar capacity this year, which would be a record high. An additional 12.2 GW of wind capacity is scheduled to come online in 2021, following 21 GW of wind capacity that was added last year. Much of this new renewable generating capacity will be located in areas that have relied on natural gas as a primary fuel for power generation in recent years, such as in Texas.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that annual U.S. crude oil production will average 11.1 million b/d in 2021, down 0.2 million b/d from 2020 as result of a decline in drilling activity related to low oil prices. A production decline in 2021 would mark the second consecutive year of production declines. Responses to the COVID-19 pandemic led to supply and demand disruptions. EIA expects crude oil production to increase in 2022 by 0.4 million b/d because of increased drilling as prices remain at or near $50 per barrel (b).
The United States set annual natural gas production records in 2018 and 2019, largely because of increased drilling in shale and tight oil formations. The increase in production led to higher volumes of natural gas in storage and a decrease in natural gas prices. In 2020, marketed natural gas production fell by 2% from 2019 levels amid responses to COVID-19. EIA estimates that annual U.S. marketed natural gas production will decline another 2% to average 95.9 billion cubic feet per day (Bcf/d) in 2021. The fall in production will reverse in 2022, when EIA estimates that natural gas production will rise by 2% to 97.6 Bcf/d.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
EIA’s forecast for crude oil production is separated into three regions: the Lower 48 states excluding the Federal Gulf of Mexico (GOM) (81% of 2019 crude oil production), the GOM (15%), and Alaska (4%). EIA expects crude oil production in the U.S. Lower 48 states to decline through the first quarter of 2021 and then increase through the rest of the forecast period. As more new wells come online later in 2021, new well production will exceed the decline in legacy wells, driving the increase in overall crude oil production after the first quarter of 2021.
Associated natural gas production from oil-directed wells in the Permian Basin will fall because of lower West Texas Intermediate crude oil prices and reduced drilling activity in the first quarter of 2021. Natural gas production from dry regions such as Appalachia depends on the Henry Hub price. EIA forecasts the Henry Hub price will increase from $2.00 per million British thermal units (MMBtu) in 2020 to $3.01/MMBtu in 2021 and to $3.27/MMBtu in 2022, which will likely prompt an increase in Appalachia's natural gas production. However, natural gas production in Appalachia may be limited by pipeline constraints in 2021 if the Mountain Valley Pipeline (MVP) is delayed. The MVP is scheduled to enter service in late 2021, delivering natural gas from producing regions in northwestern West Virginia to southern Virginia. Natural gas takeaway capacity in the region is quickly filling up since the Atlantic Coast Pipeline was canceled in mid-2020.
Just when it seems that the drama of early December, when the nations of the OPEC+ club squabbled over how to implement and ease their collective supply quotas in 2021, would be repeated, a concession came from the most unlikely quarter of all. Saudi Arabia. OPEC’s swing producer and, especially in recent times, vocal judge, announced that it would voluntarily slash 1 million barrels per day of supply. The move took the oil markets by surprise, sending crude prices soaring but was also very unusual in that it was not even necessary at all.
After a day’s extension to the negotiations, the OPEC+ club had actually already agreed on the path forward for their supply deal through the remainder of Q1 2021. The nations of OPEC+ agreed to ease their overall supply quotas by 75,000 b/d in February and 120,000 b/d in March, bringing the total easing over three months to 695,000 b/d after the UAE spearheaded a revised increase of 500,000 b/d for January. The increases are actually very narrow ones; there were no adjustments for quotas for all OPEC+ members with the exception of Russia and Kazakshtan, who will be able to pump 195,000 additional barrels per day between them. That the increases for February and March were not higher or wider is a reflection of reality: despite Covid-19 vaccinations being rolled out globally, a new and more infectious variant of the coronavirus has started spreading across the world. In fact, there may even be at least of these mutations currently spreading, throwing into question the efficacy of vaccines and triggering new lockdowns. The original schedule of the April 2020 supply deal would have seen OPEC+ adding 2 million b/d of production from January 2021 onwards; the new tranches are far more measured and cognisant of the challenging market.
Then Saudi Arabia decides to shock the market by declaring that the Kingdom would slash an additional million barrels of crude supply above its current quota over February and March post-OPEC+ announcement. Which means that while countries such as Russia, the UAE and Nigeria are working to incrementally increase output, Saudi Arabia is actually subsidising those planned increases by making a massive additional voluntary cut. For a member that threw its weight around last year by unleashing taps to trigger a crude price war with Russia and has been emphasising the need for strict compliant by all members before allowing any collective increases to take place, this is uncharacteristic. Saudi Arabia may be OPEC’s swing producer, but it is certainly not that benevolent. Not least because it is expected to record a massive US$79 billion budget deficit for 2020 as low crude prices eat into the Kingdom’s finances.
So, why is Saudi Arabia doing this?
The last time the Saudis did this was in July 2020, when the severity of the Covid-19 pandemic was at devastating levels and crude prices needed some additional propping up. It succeeded. In January 2021, however, global crude prices are already at the US$50/b level and the market had already cheered the resolution of OPEC+’s positions for the next two months. There was no real urgent need to make voluntary cuts, especially since no other OPEC member would suit especially not the UAE with whom there has been a falling out.
The likeliest reason is leadership. Having failed to convince the rest of the OPEC+ gang to avoid any easing of quotas, Saudi Arabia could be wanting to prove its position by providing a measure of supply security at a time of major price sensitivity due to the Covid-19 resurgence. It will also provide some political ammunition for future negotiations when the group meets in March to decide plans for Q2 2021, turning this magnanimous move into an implicit threat. It could also be the case that Saudi Arabia is planning to pair its voluntary cut with field maintenance works, which would be a nice parallel to the usual refinery maintenance season in Asia where crude demand typically falls by 10-20% as units shut for routine inspections.
It could also be a projection of soft power. After isolating Qatar physically and economically since 2017 over accusations of terrorism support and proximity to Iran, four Middle Eastern states – Saudi Arabia, Bahrain, the UAE and Egypt – have agreed to restore and normalise ties with the peninsula. While acknowledging that a ‘trust deficit’ still remained, the accord avoids the awkward workarounds put in place to deal with the boycott and provides for road for cooperation ahead of a change on guard in the White House. Perhaps Qatar is even thinking of re-joining OPEC? As Saudi Arabia flexes its geopolitical muscle, it does need to pick its battles and re-assert its position. Showcasing political leadership as the world’s crude swing producer is as good a way of demonstrating that as any, even if it is planning to claim dues in the future.
It worked. It has successfully changed the market narrative from inter-OPEC+ squabbling to a more stabilised crude market. Saudi Arabia’s patience in prolonging this benevolent role is unknown, but for now, it has achieved what it wanted to achieve: return visibility to the Kingdom as the global oil leader, and having crude oil prices rise by nearly 10%.