It seems to be the gift that keeps giving. The Guyanese goose that laid the golden egg. Just 4 years after first oil was struck in the South American nation of Guyana, which turned the sleepy former British colony into a hotbed of upstream activity, new discoveries are still piling up, seemingly on a monthly basis.
Just a week ago, ExxonMobil announced that it had made its 14th discovery at the offshore Staebroek block. Successful strikes at the Tripletail-1 well now brings total recoverable reserves at the block to over 6 billion barrels of oil equivalent, a startling amount in a world where findings this huge are now far and few in between. Having been the power behind exploration in Guyana, ExxonMobil is now poised to deliver first commercial oil from the Liza Phase 1 development by 2020. Volumes will be an initial 120,000 b/d, ramping up to 750,000 b/d by 2025 through the Liza Destiny FPSO. A second project has been approved, Liza Phase 2, starting in 2022 at an initial 220,000 b/d and a third, Payara, is currently going through governmental approvals and could start as early as 2023.
And it isn’t just ExxonMobil (and its partners) that are gleeful. Tullow Oil has also struck payload in Guyana, with the Orinduik licence providing two discoveries in the past two months. The back-to-back discoveries centred around the Jethro-1 and Joe-1 wells have been described as having a ‘multi-billion barrel potential’, and this has only served to elevated global interest in this stretch of the Pacific Ocean.
This might change. The discoveries by ExxonMobil could bring as much as US$300 million in revenue by 2020. This is equivalent to a third of Guyana’s current tax revenue. In a country where the average monthly wage is around US$400, those are huge numbers. And tax revenue from ExxonMobil’s own projects alone could surge to US$5 billion by 2025.
One might think that this dazzling change would be sufficient. But as with all petrostates that have seen overnight success, questions are now being asked. And the most pertinent question is: is Guyana being taken for a ride? Consider that the country’s petroleum laws were written in the 1980s, at a time when the country was more intent to promoting foreign investment and potential oil, rather than eking out maximum state revenue from proven oil. New laws have been proposed, which would grant the state a greater share in the spoils but none have been passed yet. The Guyanese Department of Energy is woefully underfunded, with an annual budget of reportedly only US$2 million. A comprehensive regulatory body to oversee all exploration and production has not even been set up yet. What has been set up is a sovereign wealth fund to soak up the expected oil riches.
It seems to be a recipe for corruption. Both in how the money will be spent, and how the exploration rights were sold off in the first place. Moves to update the petroleum laws, possibly retroactively, are in the works. But this could end badly. With no domestic infrastructure, Guyana is dependent on foreign expertise to create oil wealth. And if the state pushes back too hard as Papua New Guinea’s new government attempted to do against Total, there could be a severe backlash. Guyana is not prepared for its oil riches, that much is certain. And as the state gets to grips with this newfound paradigm, it should be looking to countries like Norway and Malaysia as examples of their path forward, instead of Indonesia, Papua New Guinea or even Uganda, where populist policies have stalled development.
Guyana’s Current Oil Tax Policy:
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Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.
Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.
When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.
This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.
In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.
The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.
By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)
Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b
Headlines of the week
Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.
The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can.
This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.
The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.
The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis.
Current OPEC membership: