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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This winter, natural gas prices have been at their lowest levels in decades. On Monday, February 10, the near-month natural gas futures price at the New York Mercantile Exchange (NYMEX) closed at $1.77 per million British thermal units (MMBtu). This price was the lowest February closing price for the near-month contract since at least 2001, in real terms, and the lowest near-month futures price in any month since March 8, 2016, according to Bloomberg, L.P. and FRED data.
In addition, according to Natural Gas Intelligence data, the daily spot price at the Henry Hub national benchmark was $1.81/MMBtu on February 10, 2020, the lowest price in real terms since March 9, 2016. Henry Hub spot prices have ranged between $1.81/MMBtu and $2.84/MMBtu this winter heating season (since November 1, 2019), generally because relatively warm winter weather has reduced demand for natural gas for heating. Natural gas production growth has outpaced demand growth, reducing the need to withdraw natural gas from underground storage.
Dry natural gas production in January 2020 averaged about 95.0 billion cubic feet per day (Bcf/d), according to IHS Markit data. IHS Markit also estimates that in January 2020 the United States saw the third-highest monthly U.S. natural gas production on record, down slightly from the previous two months.
IHS Markit estimates that U.S. natural gas consumption by residential, commercial, industrial, and electric power sectors averaged 96 Bcf/d for January, which was about 4.4 Bcf/d less than the average for January 2019, largely because of decreases in residential and commercial consumption as a result of warmer temperatures.
However, IHS Markit estimates that overall consumption of natural gas (including feed gas to liquefied natural gas (LNG) export facilities, pipeline fuel losses, and net exports by pipeline to Mexico) averaged about 117.5 Bcf/d in January 2020, an increase of about 0.2 Bcf/d from last year. This overall increase is largely a result of an almost doubling of LNG feed gas to about 8.5 Bcf/d.
Because supply growth has outpaced demand growth, less natural gas has been withdrawn from storage withdrawals this winter. Despite starting the 2019–20 heating season with the third-lowest level of natural gas inventory since 2009, by January 17, 2020, working natural gas inventories reached relatively high levels for mid-winter. The U.S. Energy Information Administration’s (EIA) data on natural gas inventories for the Lower 48 states as of February 7, 2020, reflect a 215 Bcf surplus to the five-year average. In EIA’s latest short-term forecast, more natural gas remains in storage levels than the previous five-year average through the remainder of the winter.
According to the National Oceanic and Atmospheric Administration (NOAA), January 2020 was the fifth-warmest in its 126-year climate record. Heating degree days (HDDs), a temperature-based metric for heating demand, have been relatively low this winter, which is consistent with a warmer winter. During some weeks in late December and early January, the United States saw 25% to 30% fewer HDDs than the 30-year average. This winter, through February 8, residential natural gas customers in the United States have seen 11% fewer HDDs than the 30-year average.
Source: U.S. Energy Information Administration, based on National Oceanic and Atmospheric Administration Climate Prediction Center data
Headline crude prices for the week beginning 10 February 2020 – Brent: US$53/b; WTI: US$49/b
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