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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Headline crude prices for the week beginning 10 February 2020 – Brent: US$53/b; WTI: US$49/b
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The final set of financial numbers for 2019, and for an interesting decade in terms of oil prices, came to an end as a tale of two parts. With the quarter characterised by stubborn crude prices despite OPEC+’s efforts and slumping gas prices amid a global glut, it was always going to be a challenging quarter. Most numbers from supermajors and majors came in as disappointing, but there were several bright spots where even the most optimistic expectations were exceed.
Shell, the first to report, set the tone for the cycle, showing a 48% fall in net profits from a 19% y-o-y drop in revenue. Citing weaker refining and chemical margins from slowing global growth with China and the US still locked in a trade war, the weaker results led Shell to scale back the pace of its US$25 billion share buyback programme. With only US$1 billion of shares to be bought back in Q12020 – down from the regular US$2.75 billion per quarter. Shell warned that the programme’s schedule was still at risk due to the softening global economy. It is likely that Shell will miss its deadline of completing the buyback by end-2020; investors were not impressed, and sent Shell’s share prices down to a two-year low in response.
The US supermajors came next, with both ExxonMobil and Chevron failing to meet market expectations. For ExxonMobil, revenue and net profits were both down by 5%, with the company blaming the ‘tough environment’ and depressed margins for its oil, gas, refining and chemicals businesses that will spill into 2020. Its financials, however, were boosted by the sale of its non-strategic assets in Norway, and noted that its oil extraction in Guyana was going ahead of schedule and could have a positive impact on Q1 financials. Unlike ExxonMobil, Chevron did not have strategic asset sales to fall back on. In fact, it went the opposite way. Having warned investors that it was preparing to take a major write-down on a collection of assets, including shale gas production in Appalachia and deepwater projects in the Gulf of Mexico, the final charge came in at US$10.4 billion. That wiped Chevron’s profits out, reporting a net loss of US$6.6 billion for Q419. Segment performance was stable, beating analyst expectations in some cases. But the pressure of low oil and gas prices will persist.
Things then got better. In the final results for retiring CEO Bob Dudley, who will be replaced by Bernard Looney, BP reported net profits of US$2.57 billion, exceeding even then highest analyst estimate. With a solid upstream performance and boosted by its in-house trading arm, BP bucked the negative trend, allowing it to raise its dividend level, a notion that it had rejected in the last quarter, while also completing a US$1.5 billion share buyback programme. Rounding off the quintet, Total also exceed the expectations of the market. Although the French company was also affected by slumping natural gas prices, along with strikes at its French refineries, record production boosted net profits to US$3.17 billion, almost unchanged y-o-y. The ramp-up of key natural gas projects, Yamal in Russia and Ichthys in Australia, along with the start of the Egina and Kaombo crude oil projects in West Africa, raised upstream output by 9% over a quarter where all other rivals saw their production decline.
When the decade started in 2010, crude oil prices were riding high at US$80/b. It would soon peak at nearly US$120/b in 2011, stay elevated for 3 years, halving by end-2014, slumping down to US$30/b in 2016 before beginning a gradual recovery. This 10-year see-saw ride has been mirrored in the financial performance of the energy supermajors. With a new decade starting with plenty of uncertainty, the fiscal discipline adopted since 2015 by the supermajors will be key to supporting their business activities going forward in troubled times.
Supermajor Financials Q4 2019: