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Last Updated: January 16, 2020
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monthly Henry Hub natural gas spot prices

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that average U.S. natural gas prices will be 9% lower in 2020 than in 2019. EIA expects lower natural gas prices will be the result of continued production growth primarily in response to the following factors:

  • Improved drilling efficiency and cost reductions
  • Higher associated gas production from oil-directed rigs
  • Increased takeaway pipeline capacity from the Appalachian and Permian production regions  

This production growth outpaces the growth in domestic demand and exports.

EIA expects the natural gas spot price for the U.S. benchmark Henry Hub will average $2.33 per million British thermal units (MMBtu) in 2020, about 24 cents lower than the 2019 average of $2.57/MMBtu. Following a year of decline, EIA expects 2021 natural gas prices to rise by 9% because of upward pricing pressure from declining growth in natural gas production.

annual U.S. natural gas consumption and production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

EIA expects record volumes of U.S. dry natural gas production to continue through 2020, from an estimated 92.0 billion cubic feet per day (Bcf/d) in 2019 to 94.7 Bcf/d in 2020. Most U.S. production will come from the Appalachian Basin in the Northeast, followed by the Permian Basin in western Texas and New Mexico and the Haynesville shale formation in eastern Texas. Cost reductions in drilling and well completions and improved drilling efficiency will support continued record-production levels in 2020. In addition, a growing share of natural gas production is coming from oil wells that produce natural gas, also called associated gas. Increased takeaway capacity from the highly productive Appalachian and Permian production regions will further enable growth. However, in 2021, EIA expects dry natural gas production to decline by less than 1% to 94.1 Bcf/d in response to lower forecast natural gas spot prices in 2020, which would reduce Appalachian Basin production.

Total U.S. natural gas consumption remains relatively unchanged compared with 2019 levels in the STEO forecast, increasing 1.7% in 2020, but decreasing 1.2% in 2021 to an average 85.7 Bcf/d in 2021. EIA forecasts natural gas consumption to decrease slightly in the residential and commercial sectors as a result of expected milder weather that will require less energy for space heating in the winter and air conditioning in the summer. Based on forecasts by the National Oceanic and Atmospheric Administration, EIA forecasts 1.8% fewer heating degree days (HDD) in 2020 compared with 2019, which had a colder-than-normal first quarter.

EIA expects U.S. natural gas use in the electric power sector to increase by 1.3% in 2020 as a result of natural gas-fired generation additions that continue to displace coal-fired generation. However, in 2021, because of a forecast of higher natural gas spot prices and increased competition from renewables, EIA estimates that natural gas consumption in the electric power sector will decline by 3.2% in 2021. EIA expects the natural gas share of electricity generation in 2021 to be 37%, about the same as its 2019 share, while coal’s share of electricity generation will fall from 24% in 2019 to 21% in 2021.

Natural gas consumption in the U.S. industrial sector will continue to grow in 2020, increasing by 4.6%. New methanol plants that use natural gas as feedstock are scheduled to come online in 2020, which will support the increased industrial sector consumption. In 2021, EIA expects industrial sector consumption to flatten because of higher industrial sector natural gas prices.

annual U.S. natural gas trade

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

The United States became a net exporter of natural gas on an annual basis for the first time in 2018, and EIA expects that this trend will continue during the forecast period. In 2020, net exports will average 7.3 Bcf/d—an increase of 2.0 Bcf/d over the 2019 levels. EIA expects 2021 net exports to rise further to 8.9 Bcf/d as new liquefied natural gas (LNG) projects enter service. The remaining trains at the Cameron LNG and Freeport LNG facilities, located along the Gulf Coast, and the Elba Island LNG facility in Georgia will be placed into service in 2020. EIA expects LNG exports to increase from an estimated 5.0 Bcf/d in 2019 to 6.5 Bcf/d in 2020 and up to 7.7 Bcf/d in 2021, more than double the 2018 level.

EIA forecasts that gross exports of natural gas by pipeline will continue to grow, increasing to 8.1 Bcf/d in 2020 and 8.5 Bcf/d in 2021, or 8.8% higher than the 2019 level. Most of the increase will be driven by increasing natural gas demand and by pipeline projects in Mexico that are scheduled to come online by the end of 2021. EIA expects imports of LNG to remain flat through 2021, and imports by pipeline will continue to decrease through 2020, when Appalachian production and takeaway capacity displace imported natural gas from Canada in the U.S. Midwest markets.

natural gas production supply consumption demand exports imports STEO EIA
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Saudi Aramco Moves Into Russia’s Backyard

International expansions for Saudi Aramco – the largest oil company in the world – are not uncommon. But up to this point, those expansions have followed a certain logic: to create entrenched demand for Saudi crude in the world’s largest consuming markets. But Saudi champion’s latest expansion move defies, or perhaps, changes that logic, as Aramco returns to Europe. And not just any part of Europe, but Eastern Europe – an area of the world dominated by Russia – as Saudi Aramco acquires downstream assets from Poland’s PKN Orlen and signs quite a significant crude supply deal. How is this important? Let us examine.

First, the deal itself and its history. As part of the current Polish government’s plan to strengthen its national ‘crown jewels’ in line with its more nationalistic stance, state energy firm PKN Orlen announced plans to purchase its fellow Polish rival (and also state-owned) Grupa Lotos. The outright purchase fell afoul of EU anti-competition rules, which meant that PKN Orlen had to divest some Lotos assets in order to win approval of the deal. Some of the Lotos assets – including 417 fuel stations – are being sold to Hungary’s MOL, which will also sign a long-term fuel supply agreement with PKN Orlen for the newly-acquired sites, while PKN Orlen will gain fuel retail assets in Hungary and Slovakia as part of the deal. But, more interestingly, PKN Orlen has chosen to sell a 30% stake in the Lotos Gdansk refinery in Poland (with a crude processing capacity of 210,000 bd) to Saudi Aramco, alongside a stake in a fuel logistic subsidiary and jet fuel joint venture supply arrangement between Lotos and BP. In return, PKN Orlen will also sign a long-term contract to purchase between 200,000-337,000 b/d of crude from Aramco, which is an addition to the current contract for 100,000 b/d of Saudi crude that already exists. At a maximum, that figure will cover more than half of Poland’s crude oil requirements, but PKN Orlen has also said that it plans to direct some of that new supply to several of its other refineries elsewhere in Lithuania and the Czech Republic.

For Saudi Aramco, this is very interesting. While Aramco has always been a presence in Europe as a major crude supplier, its expansion plans over the past decade have been focused elsewhere. In the US, where it acquired full ownership of the Motiva joint venture from Shell in 2017. In doing so, it acquired control of Port Arthur, the largest refinery in North America, and has been on a petrochemicals-focused expansion since. In Asia, where Aramco has been busy creating significant nodes for its crude – in China, in India and in Malaysia (to serve the Southeast Asia and facilitate trade). And at home, where the focus has on expanding refining and petrochemical capacity, and strengthen its natural gas position. So this expansion in Europe – a mature market with a low ceiling for growth, even in Eastern Europe, is interesting. Why Poland, and not East or southern Africa? The answer seems fairly obvious: Russia.

The current era of relatively peaceful cooperation between Saudi Arabia and Russia in the oil sphere is recent. Very recent. It was not too long ago that Saudi Arabia and Russia were locked in a crude price war, which had devastating consequences, and ultimately led to the détente through OPEC+ that presaged an unprecedented supply control deal. That was through necessity, as the world faced the far ranging impact of the Covid-19 pandemic. But remove that lens of cooperation, and Saudi Arabia and Russia are actual rivals. With the current supply easing strategy through OPEC+ gradually coming to an end, this could remove the need for the that club (by say 2H 2022). And with Russia not being part of OPEC itself – where Saudi Arabia is the kingpin – cooperation is no longer necessary once the world returns to normality.

So the Polish deal is canny. In a statement, Aramco stated that ‘the investments will widen (our) presence in the European downstream sector and further expand (our) crude imports into Poland, which aligns with PKN Orlen’s strategy of diversifying its energy supplies’. Which hints at the other geopolitical aspect in play. Europe’s major reliance on Russia for its crude and natural gas has been a minefield – see the recent price chaos in the European natural gas markets – and countries that were formally under the Soviet sphere of influence have been trying to wean themselves off reliance from a politically unpredictable neighbour. Poland’s current disillusion with EU membership (at least from the ruling party) are well-documented, but its entanglement with Russia is existential. The Cold War is not more than 30 years gone.

For Saudi Aramco, the move aligns with its desire to optimise export sales from its Red Sea-facing terminals Yanbu, Jeddah, Shuqaiq and Rabigh, which have closer access to Europe through the Suez Canal. It is for the same reason that Aramco’s trading subsidiary ATC recently signed a deal with German refiner/trader Klesch Group for a 3-year supply of 110,000 b/d crude. It would seem that Saudi Arabia is anticipating an eventual end to the OPEC+ era of cooperative and a return to rivalry. And in a rivalry, that means having to make power moves. The PKN Orlen deal is a power move, since it brings Aramco squarely in Russia’s backyard, directly displacing Russian market share. Not just in Poland, but in other markets as well. And with a geopolitical situation that is fragile – see the recent tensions about Russian military build-up at the Ukrainian borders – that plays into Aramco’s hands. European sales make up only a fraction of the daily flotilla of Saudi crude to enters international markets, but even though European consumption is in structural decline, there are still volumes required.

How will Russia react? Politically, it is on the backfoot, but its entrenched positions in Europe allows it to hold plenty of sway. European reservations about the Putin administration and climate change goals do not detract from commercial reality that Europe needs energy now. The debate of the Nord Stream 2 pipeline is proof of that. Russian crude freed up from being directed to Eastern Europe means a surplus to sell elsewhere. Which means that Russia will be looking at deals with other countries and refiners, possibly in markets with Aramco is dominant. That level of tension won’t be seen for a while – these deals takes months and years to complete – but we can certainly expect that agitation to be reflected in upcoming OPEC+ discussions. The club recently endorsed another expected 400,000 b/d of supply easing for January. Reading the tea leaves – of which the PKN Orlen is one – makes it sound like there will not be much more cooperation beyond April, once the supply deal is anticipated to end.

End of Article

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Market Outlook:

-       Crude price trading range: Brent – US$86-88/b, WTI – US$84-86/b

-       Crude oil benchmarks globally continue their gain streak for a fifth week, as the market bounces back from the lows seen in early December as the threat of the Omicron virus variant fades and signs point to tightening balances on strong consumption

-       This could set the stage for US$100/b oil by midyear – as predicted by several key analysts – as consumption rebounds ahead of summer travel and OPEC+ remains locked into its gradual consumption easing schedule 

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