Surrounded by global energy powerhouses like Saudi Arabia, Abu Dhabi and even Qatar, Bahrain is a minnow in the Middle East. With output of only 43,000 b/d last year – not including its 150,000 b/d share of the Abu Safah field shared with Saudi Arabia – Bahrain has been hit hard since the oil price crash in 2014. So much for the place where the first Arabian Gulf oil was discovered in 1932 by Standard Oil of California.
Plans to boost domestic oil production back to 100,000 b/d could get things back on track. But greater riches await. Last year, Bahrain announced its largest-ever oil and gas discovery in the Khalij al-Bahrain Basin – a find that could dramatically boost the tiny Gulf Kingdom’s profile. Even on a P50 basis (ie. with 50% certainty), initial estimates suggest that the discovery holds at least 80 billion barrels of oil and 10-20 tcf of natural gas, huge numbers for such a small producer.
There’s a problem though. Those giant figures refer to reserves instead of extractable reserves, meaning that only a fraction will be able to be recovered. More so than that, the resources in ‘tight oil’ and ‘tight gas’ formations. While that may be familiar in the USA with the advent of the shale revolution, it is new territory in the Arabian Gulf. According to service firms Halliburton and Schlumberger, Khalij al-Bahrain straddles the line between a conventional and unconventional play and because of this, the new oilfield could prove very technically challenging and very high-cost to develop.
Which is where expertise from half a world away comes in. Khalij al-Bahrain is very similar to the conditions in the Eagle Ford and Permian basins in the USA, which are now producing prodigious amounts of shale oil, shale gas and also plenty of natural gas liquids. Which is why Bahrain is now woo-ing American firms with shale know-how – from specialist players like Pioneer to supermajors like ExxonMobil and Chevron – to assist. The Kingdom’s National Oil and Gas Authority (NOGA) sent a delegation led by the Oil Minister to Texas recently, and has also held talks with US service companies and the US Chamber of Commerce. It hopes to be able to attract technical expertise through collaborations unusual to this part of the world; instead of service contracts common to the Middle East, Bahrain is instead looking to pursue production-sharing contracts instead. This would allow international collaborators a greater share of revenues – instead of a fixed-fee service contract – as well as allow the reserves to be booked onto respective balance sheets. It’s an attractive proposition because this is an attractive opportunity. Bahrain’s free trade agreement with the US helps a lot as well.
At stake isn’t just increased upstream revenue for Bahrain. It is an opportunity to re-invent its energy industry. Described as a ‘bathtub area’, Khalij al-Bahrain is a very shallow offshore field. If successfully developed, it would be the first ever commercial offshore shale oil producing assets – moving the shale revolution from inland to underwater. Bahrain is looking to drill 2-4 test wells this year, aiming for output in five years at an initial 200,000 b/d. But more than just selling the oil as crude, Bahrain is looking downstream. Together with the shale oil, there are also signs of significant rich gas and NGLs flows. With Bahrain itself planning expansion of its petrochemicals capacity – and its proximity to some of the region’s largest petchem plants – this could be a dawn of a new age for Middle Eastern energy in the country where it all started. With a little help from American friends, of course.
Khalij al-Bahrain Field:
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In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.
In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.
Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.
We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.
Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.
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The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.
How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.
The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.
The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.
On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.
But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.
For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.
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