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Just a few days ago, Chevron sent a tremor through the LNG industry when it announced that it was putting its stake in Australia’s giant North West Shelf project up for sale, having received ‘unsolicited approaches from a range of credible buyers’. The term to zoom in on is ‘unsolicited’. Meaning that Chevron wasn’t actively considering selling its stake in Australia’s oldest LNG project, but had been cajoled into starting a formal sales process by attractive offers. And that itself says a lot about the state of the LNG industry going forward.
A bit of history. The North West Shelf Project kicked off in the 1980s, then the largest engineering project in the world and remains the largest LNG project in Australia, even after the new wave of Western Australian LNG projects over the last decade. Formed as an equal joint venture between Chevron, Woodside Petroleum, BHP Billiton, BP, Shell and Japan Australia (owned by Mitsubishi Corporation and Mitsui & Co) – each holding a 1/6th stake – the North West Shelf brought together gas producing assets in the huge Carnarvon Basin, tying together fields like Perseus, North Rankin and Goodwyn into total reserves of 33 tcf. It put Australian LNG in the headlines, established the healthy LNG trade relationship between Japan and Australia, and transformed the economy of Western Australia;
Three decades later, the North West Shelf is still Australia’s most prodigious LNG-producing project. But one thing has changed. The natural gas drawn from its fields is drying up, or – to use a more appropriate term – evaporating. There’s still plenty of gas in the Carnarvon Basin, but not enough to power LNG production fully for the foreseeable future. Which is why NWS has started to shift its focus to tolling. In this context, it essentially means that the NWS will sells its liquefaction and associated infrastructure capacity to other gas producers in the region, who will process their natural gas into LNG through NWS before selling it on to their own customers. That would flip the NWS – in its current structure – from having full control over assets and production to being a landlord, renting out its infrastructure for someone else to use.
And there are plenty of ‘someone’s around. BHP and Woodside Petroleum’s Scarborough natural gas development is a perfect example, with Woodside also have its Browse project. These assets are nearby, and tying them to the NWS facilities is considerably more economic than having to build a new liquefaction plant from scratch. Even Chevron has its own assets in the area – the giant Gorgon and Wheatstone LNG project – but due to geography and proximity, has developed these as independent projects with individual facilities. The problem is that the potential third-party assets to be tied into NWS are owned by some of the NWS’ own stakeholders. This would upset the delicate balance between the NWS partners – who designed the structure to be equal and equitable.
With this significant misalignment between Chevron and its partners, it makes sense that Chevron would want to sell out of the project, particularly since the sale could fetch as much as US$4 billion, which is a nice chunk of change to help Chevron weather the current Covid-19 storm. It won’t just be Chevron considering this; BP and Shell will be thinking about this as well, although the Japanese partners are likely to remain to continue siphoning the LNG back home. While the potential suitors have not been named, the most likely candidate is Woodside, who could use its additional clout to convince the remaining NWS partners to agree on feeding Browse gas into NWS, a proposal that it has had difficulties with so far. Key Asian LNG buyers could be potential suitors as well, particularly Korean or Chinese companies that are keen to secure LNG assets for their own growing demand.
This problem won’t be unique to the North West Shelf. It is one that most giant LNG projects that were developed in the 1980s and 1990s must confront soon: with associated natural gas reserves running low, these projects must now look for alternative sources to continue LNG production. For some, circumstances may dictate that decommissioning makes more sense. But for others, like the North West Shelf, the presence of other nearby assets is a double-edged sword: it means that the project can keep running, but will have change its business model to adapt. That means ruffling a few feathers. Chevron might be one of the first to take this step, but it certainly will not be the last.
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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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