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Last Updated: June 21, 2018
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Headline crude prices for the week beginning 18 June 2018 – Brent: US$75/b; WTI: US$65/b

  • As OPEC prepares for its meeting in Vienna on June 22, oil prices are also facing a new challenge – the growing trade spat between the US and China
  • After China retaliated to the US’ imposition of tariffs on US$50 billion worth of imports last week, and the US mulls action on another US$200 billion, there is worry that China will reply with targets on US crude and LNG.
  • On the OPEC side, there is an emerging consensus that some form of output increase will be on the cards – supported by Saudi Arabia and Russia – though the size may be ‘modest’ to appease opposition from Iran and Iraq.
  • The figure being bandied about is some 300-600,000 b/d – smaller than Russia’s favoured increase of 1.5 mmb/d and far smaller than the 1.8 mmb/d cut agreed in November 2016.
  • Rosneft has expressed ‘comfort’ with the current price range of US$70-80/b, an indication that OPEC will aim to keep crude at this level even with an agreement on an output hike.
  • Beyond the June meeting, Saudi Arabia is said to be planning a leaders’ summit for the OPEC and NOPEC countries later this year, a step in formally institutionalising co-operation between the two oil blocks.
  • In the US, oil has seen some inventory drops, but the US active oil rig count continues to grow by one site last week, which was offset by the loss of three gas rigs, bringing the total active count to 1,059.
  • The standoff between the US and China over trade issues is uncharted territory. If the trade war continues to escalate, crude prices will continue to be affected by the vortex, placing additional pressure on prices and prompting investors to seek safe havens.
  • Crude price outlook: An output rise at OPEC is expected, and with trade issues dominating headlines, we expect some downward pressure on prices. Brent should stay at US$74-75/b while WTI may widen its discount to US$63-64/b as the infrastructure crunch persists in the Permian.

Headlines of the week

Upstream

  • Encouraged by mega-test finds in Guyana, ExxonMobil has begun developing drilling at three of its projects in Guyana, which should start producing some 500,000 b/d of oil by 2020.
  • As upstream in East Africa slowly but surely heats up, Kenya has approved a new petroleum law defining oil revenue sharing, with 75% going to the state.
  • Petrobras has sold 25% of the Roncador oil field in Brazil’s Campos basin to Equinor for US$2 billion, bringing Equinor’s equity output to 100,000 b/d.
  • ExxonMobil is reportedly taking ‘baby steps’ to create an in-house crude and fuels trading unit, though current plans call for an operation size that pales in comparison to the trading units of Shell, BP and Total.

Downstream

  • Fresh from mega-refinery deals in China, India and Malaysia, Saudi Aramco states that it will continue downstream investment with the goal of ‘8-10 mmb/d of participated refinery capacity and significant chemicals by 2040’
  • As the Chinese city of Tianjin gears up to be the pilot city in introducing an ethanol-gasoline fuel mix by September – part of a wider biofuels initiative by Beijing using local corn stock to reduce pollution – Sinopec’s Tianjin refinery says it is ready to produce some 120,000 tons of the biofuel by October.
  • New tax rules have clipped the wings of China’s independent oil refiners – the teapots – moving from a profit bonanza to shrinking margins and losses.
  • A massive blockade by farmers’ unions of refineries and depots in France has left some fuel stations dry, as the protest of imported biofuels continues.
  • Venezuela may refine foreign crude for the first time ever for domestic fuel demand and to fulfil exports, as the upstream sector buckles under pressure.
  • In a sign that China is looking to diversify its crude diet away from Russia and Saudi Arabia, chemical producer Hengli has purchased crude from Brazil to fuel startup at its new 400,000 b/d refinery in Dalian.

Natural Gas/LNG

  • Chevron has started up the second train of Wheatstone LNG, as it plays catch up with other Australian LNG projects after severe cost-blowouts and delays.  
  • Total, along with Sonatrach, Repsol and Alnaft, has signed a new concession contract for the Tin Fouyé Tabankort gas and condensate field in Algeria, extending the life of the current contract by 25 years.
  • Shell has sold its entire stake in the Petronas-operated MLNG Tiga LNG plant in Malaysia to the Sarawak state government for US$750 million.
  • Phillips 66 is planning a US$1.5 billion expansion of its NGL project in Sweeny, Texas, including two new 150,000 b/d fractionators.
  • Centrica and Tokyo Gas have signed non-binding agreements to purchase some 2.6 mtpa LNG from Anadarko’s Mozambique project, which should support the project’s upcoming FID.
  • The planned gas pipeline linking Israel to Egypt is one step closer to fruition, as Delek Drilling, Noble Energy and an Egyptian company agree to purchase 37% of East Mediterranean Gas, giving the partners control over the pipeline.

Corporate

  • Oasis Management has taken stakes in Japan’s Idemitsu Kosan and Show Shell Sekiyu, reviving the possibility of a merger between the two refiners that has been scuppered by Idemitsu’s founding family.

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EIA forecasts less power generation from natural gas as a result of rising fuel costs

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.

January, 20 2021
U.S. oil and natural gas production to fall in 2021, then rise in 2022

U.S. monthly crude oil and natural gas production

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.

U.S. monthly crude oil production

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.

January, 15 2021
So, Why Is Saudi Arabia Doing This?

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%.

Market Outlook:

  • Crude price trading range: Brent – US$55-57/b, WTI – US$51-53/b
  • Global crude oil benchmarks jumped several levels to a new higher range, as Saudi Arabia supplemented OPEC+’s decision to allow a minor increase in supply quotas for February and March with a massive 1 mmb/d voluntary cut over the same period
  • There are signs that the elevated level of crude pricing is tempting American drillers back to work, with Baker Hughes reporting a massive 67-site gain in active rigs over the first week of 2021; this will present another headache for OPEC+ when it comes time to debate the supply deal path forward for April and beyond
January, 14 2021