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Crude oil inputs to Mexico’s petroleum refineries declined for the fifth consecutive year in 2018, falling to nearly 600,000 barrels per day (b/d), a 50% drop from 2013 levels. This decline in crude oil processing has coincided with a decrease in domestic production of the light crude oil that the country’s refineries are better suited to process. Mexico has increasingly relied on imports of petroleum products from the United States to satisfy domestic demand.
Petróleos Mexicanos (Pemex), Mexico’s national oil company, owns and operates the country’s six petroleum refineries, which have a combined atmospheric crude oil distillation capacity of about 1.6 million b/d. On an aggregate basis, performance at Pemex refineries has declined over the past five years after maintaining an average refinery utilization rate near or above 75% between 1990 and 2013. By 2018, the utilization rate of Mexico’s refinery network fell to less than 40%.
Pemex’s refineries are mostly configured to process light crude oil. Of its six refineries, three (Minatitlan, Cadereyta, Madero) are equipped with coker units to produce lower-sulfur gasoline from heavy crude oil. The 35% decrease in Mexican light crude oil production between 2013 and 2018 has resulted in limitations on crude oil refinery inputs. Inputs of light crude oil to Pemex refineries fell below 400,000 b/d in 2018, about a 50% reduction from 2013 levels.
Refineries require periodic maintenance to ensure optimal operation of processing units that refine crude oil into petroleum products such as motor gasoline and diesel. Crude oil inputs at Pemex refineries since 2014 have been further constrained by operational issues associated with the company’s refineries.
Pemex maintains control over much of Mexico’s petroleum product imports and distribution. Declines in domestic production of liquid transportation fuels have increased Mexico’s reliance on foreign sources of refined petroleum products. Pemex imports of motor gasoline increased about 230,000 b/d between 2013 and 2018, offsetting similar declines in domestic production at Pemex refineries.
Source: U.S. Energy Information Administration, based on data published by Petróleos Mexicanos
Mexican imports from the United States have helped to offset a large share of Pemex’s shortfall in motor gasoline production, supplying about 535,000 b/d in 2018, more than double the level of imports in 2013. Mexico receives the largest share of U.S. motor gasoline exports, with much of the remainder destined for Central and South American countries.
U.S. refineries along the Gulf Coast are able to process heavy Mexican crude oil blends with a high yield of finished, low-sulfur motor gasoline. Pemex currently obtains some of its motor gasoline from the United States through its joint venture with Shell at the 340,000 b/d refinery in Deer Park, Texas. The joint venture, which was recently extended through 2033, includes an agreement for Pemex to provide a share of heavy crude oil in exchange for finished petroleum products.
In September 2018, the Mexican government announced an initiative called the National Refining Plan to help Mexico achieve energy independence by 2022. The plan includes upgrades and reconfigurations at Pemex’s six refineries, as well as construction in Dos Bocas of a seventh refinery, which is designed to process 340,000 b/d of heavy crude oil. If achieved, Pemex refineries would be able to process 1.86 million b/d of crude oil to produce an estimated 781,000 b/d of motor gasoline and 560,000 b/d of diesel fuel.
Principal contributors: Steve Hanson, Neil Agarwal
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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%.
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