In the closing days of 2020, Indonesia’s upstream regulator SKK Migas approved the Plan of Development submitted by operator Repsol, allowing the gas-rich Kaliberau field in South Sumatra’s Sakakemang block to now chase a production timeline of 2024/2025. At an estimated 2 trillion cubic feet of recoverable reserves, higher even than the 2001 Cepu oil field discovery that included 1.7 tcf of natural gas, Kaliberau is central to Indonesia’s future gas ambitions. As the statement from SKK Migas pointedly noted: Repsol is required to ‘immediately execute the plan to start production as soon as possible.’
That’s pretty obvious. In an industry characterised by huge investment sums and long development times, all parties involved will want to be able to make a return on their capital as soon as possible. But this being Indonesia, there is another level of ambition at play here, one that had already complicated Kaliberau’s pathway toward development.
Discovered in January 2019, the onshore Kaliberau discovery was a truly pleasant surprise, given that region in South Sumatra has already been thoroughly explored in the past. So Spain’s Repsol, along with its partners Petronas and MOECO, must have been over the moon with the discovery, especially when initial estimates indicated recoverable reserves exceeding 2 tcf. Even better, Kaliberau is just a mere 25km from the Grissik gas plant, which currently processes output from ConocoPhillips’ maturing Corridor concession for sale to Sumatra, West Java and Singapore; Repsol is also a partner in Corridor, along with Pertamina, and all three have been seeking new gas sources to extend the life of Corridor past 2024. Kaliberau comes at just the right time. Indonesia’s government must also have been overjoyed, given that the country has been aggressively seeking to reclaim its glory days from the 70s and 80s of being an energy powerhouse. A find of this size plays well into Indonesia’s goal of doubling domestic natural gas production by 2030 to transform the country (back) into a major gas exporter.
That’s all great so far. No complications there. But Indonesia also has secondary objectives that complicate the matter. Successive governments since the Suharto regime fell in 1998 have used energy subsidies as a means of national development. Part of this is self-preservation, subsidised gasoline and diesel is incredibly popular with the citizenry, and it has proven to be political suicide to attempt abolishing them. But the less-consumer facing aspect of this is the linkages to which energy powers the rest of Indonesia’s economy. The industrial sector in Indonesia currently pays some of the highest gas prices in Southeast Asia – at over US$9/mmBtu, compared to equivalent rates of US$6-8/mmBtu in Malaysia, Thailand or even Singapore, even since natural gas subsidies were ‘reformed’ without much political backlash. This makes the industries that the Indonesian government sees as crucial drivers of the economy – petrochemicals, fertiliser and steel – uncompetitive internationally. Which is why the government introduced a new gas price regulation in April 2020, which aims to (re)lower domestic gas prices for industries through government-funded subsidies.
Even in the richest of countries, subsidies can be a problem. But in Indonesia, it is not just a drain, but a financial haemorrhage. Mainly because Indonesia’s quixotic policies to simultaneously boost upstream production and divert a significant amount of those volumes domestically at the lowest price possible has seen upstream oil and gas production crater since the 1990s, forcing Indonesia to turn to imports. And, as an importer, it has to pay market rates.
Which is why one of the major sticking points about Kaliberau was the gas sales price, which is capped at US$6/mmBtu under the new regulation. It is an issue faced by many other natural gas projects in Indonesia, Inpex’s Masela Block (which has also finally been approved) and Genting Oil’s Kasuri but the sheer size of Kaliberau makes it stand out. Repsol has reportedly been gunning for a US$7/mmBtu price to commercialise Kaliberau; not necessarily because that was the breakeven level, but because a project of this size will be competing for capital within Repsol’s global upstream portfolio. SKK Migas’ decision to approve Kaliberau makes no mention of the gas price agreed between Repsol and the Indonesian government, and indeed, it may never be revealed but the approval suggests that a compromise was reached.
That’s one problem solved, and Kaliberau (along with Masela and its associate Abadi LNG plant) will now go ahead. But the existential quandary faced by the Indonesian government that has resulted in prolonged haggling of sales prices has drawn out what could have been a more straightforward process. And it does factor into the radar of other players, especially international upstream explorers that could easily divert capital earmarked for drilling in Indonesia elsewhere where government policy and dictates are not as mercurial. Local players like Pertamina don’t have a choice, but then again, Pertamina is in no position to fund any major exploration alone. Indonesia remains an appealing upstream target, if only because there are still many riches yet to be discovered across the vast archipelago. But the government remains more of an adversity, not an ally, in the race to tap those assets. You could argue that it is their right to play that role. So yes, Indonesia may hold all the cards in this game. But what use is holding all the cards if nobody else wants to play? Or pay?
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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%.