Easwaran Kanason

Co - founder of PetroEdge
Last Updated: April 8, 2019
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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: 

  • Discovered April 2018
  • Location: Shallow water offshore Bahrain’s West Coast
  • Estimated reserves: 80 billion barrels of tight oil, 10-20 tcf of tight gas (P50 basis)
  • Commercialisation strategy; Test well drilling 2019-2020; commercial production 2023/2024

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In 2018, the United States consumed more energy than ever before

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Primary energy consumption in the United States reached a record high of 101.3 quadrillion British thermal units (Btu) in 2018, up 4% from 2017 and 0.3% above the previous record set in 2007. The increase in 2018 was the largest increase in energy consumption, in both absolute and percentage terms, since 2010.

Consumption of fossil fuels—petroleum, natural gas, and coal—grew by 4% in 2018 and accounted for 80% of U.S. total energy consumption. Natural gas consumption reached a record high, rising by 10% from 2017. This increase in natural gas, along with relatively smaller increases in the consumption of petroleum fuels, renewable energy, and nuclear electric power, more than offset a 4% decline in coal consumption.

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum consumption in the United States increased to 20.5 million barrels per day (b/d), or 37 quadrillion Btu in 2018, up nearly 500,000 b/d from 2017 and the highest level since 2007. Growth was driven primarily by increased use in the industrial sector, which grew by about 200,000 b/d in 2018. The transportation sector grew by about 140,000 b/d in 2018 as a result of increased demand for fuels such as petroleum diesel and jet fuel.

Natural gas consumption in the United States reached a record high 83.1 billion cubic feet/day (Bcf/d), the equivalent of 31 quadrillion Btu, in 2018. Natural gas use rose across all sectors in 2018, primarily driven by weather-related factors that increased demand for space heating during the winter and for air conditioning during the summer. As more natural gas-fired power plants came online and existing natural gas-fired power plants were used more often, natural gas consumption in the electric power sector increased 15% from 2017 levels to 29.1 Bcf/d. Natural gas consumption also grew in the residential, commercial, and industrial sectors in 2018, increasing 13%, 10%, and 4% compared with 2017 levels, respectively.

Coal consumption in the United States fell to 688 million short tons (13 quadrillion Btu) in 2018, the fifth consecutive year of decline. Almost all of the reduction came from the electric power sector, which fell 4% from 2017 levels. Coal-fired power plants continued to be displaced by newer, more efficient natural gas and renewable power generation sources. In 2018, 12.9 gigawatts (GW) of coal-fired capacity were retired, while 14.6 GW of net natural gas-fired capacity were added.

U.S. fossil fuel energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Renewable energy consumption in the United States reached a record high 11.5 quadrillion Btu in 2018, rising 3% from 2017, largely driven by the addition of new wind and solar power plants. Wind electricity consumption increased by 8% while solar consumption rose 22%. Biomass consumption, primarily in the form of transportation fuels such as fuel ethanol and biodiesel, accounted for 45% of all renewable consumption in 2018, up 1% from 2017 levels. Increases in wind, solar, and biomass consumption were partially offset by a 3% decrease in hydroelectricity consumption.

U.S. energy consumption of selected fuels

Source: U.S. Energy Information Administration, Monthly Energy Review

Nuclear consumption in the United States increased less than 1% compared with 2017 levels but still set a record for electricity generation in 2018. The number of total operable nuclear generating units decreased to 98 in September 2018 when the Oyster Creek Nuclear Generating Station in New Jersey was retired. Annual average nuclear capacity factors, which reflect the use of power plants, were slightly higher at 92.6% in 2018 compared with 92.2% in 2017.

More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

April, 17 2019
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April, 17 2019
A New Frontier for LNG Pricing and Contracts

How’s this for a first? As the world’s demand for LNG continues to grow, the world’s largest LNG supplier (Shell) has inked an innovative new deal with one of the world’s largest LNG buyers (Tokyo Gas), including a coal pricing formula link for the first time in a large-scale LNG contract. It’s a notable change in an industry that has long depended on pricing gas off crude, but could this be a sign of new things to come?

Both parties have named the deal an ‘innovative solution’, with Tokyo Gas hailing it as a ‘further diversification of price indexation’ and Shell calling it a ‘tailored solutions including flexible contract terms under a variety of pricing indices.’ Beneath the rhetoric, the actual nuts and bolts is slightly more mundane. The pricing formula link to coal indexation will only be used for part of the supply, with the remainder priced off the conventional oil & gas-linked indexation ie. Brent and Henry Hub pricing. This makes sense, since Tokyo Gas will be sourcing LNG from Shell’s global portfolio – which includes upcoming projects in Canada and the US Gulf Coast. Neither party provided the split of volumes under each pricing method, meaning that the coal-linked portion could be small, acting as a hedge.

However, it is likely that the push for this came from Tokyo Gas. As one of the world’s largest LNG buyers, Tokyo Gas has been at the forefront of redefining the strict traditions of LNG contracts. Reading between the lines, this deal most likely does not include any destination restriction clauses, a change that Tokyo Gas has been particularly pushing for. With the trajectory for Brent crude prices uncertain – owing to a difficult-to-predict balance between OPEC+ and US shale – creating a third link in the pricing formula might be a good move. Particularly since in Japan, LNG faces off directly with coal in power generation. With the general retreat from nuclear power in the country, the coal-LNG battle will intensify.

What does this mean for the rest of the industry? Could coal-linked contracts become the norm? The industry has been discussing new innovations in LNG contracts at the recent LNG2019 conference in Shanghai, while the influx of new American LNG players hungry to seal deals has unleashed a new sense of flexibility. But will there be takers?

I am not a pricing expert but the answer is maybe. While Tokyo Gas predominantly uses natural gas as its power generation fuel (hence the name), it is competing with other players using cheaper coal-based generation. So in Japan, LNG and coal are direct competitors. This is also true in South Korea and much of Southeast Asia. In the two rising Asian LNG powerhouses, however, the situation is different. In China – on track to become the world’s largest LNG buyer in the next two decades – LNG is rarely used in power generation, consumed instead by residential heating. In India – where LNG imports are also rising sharply – LNG is primarily aimed at petrochemicals and fertiliser. LNG based power generation in China and India could see a surge, of course, but that will take plenty of infrastructure, and time, to build. It is far more likely that their contracts will be based off existing LNG or natural gas benchmarks, several of which are being developed in Asia alone.

If it takes off  the coal-link LNG formula is likely to remain a Asian-based development. But with the huge volumes demanded by countries in this region, that’s still a very big niche. Enough perhaps for the innovation to slowly gain traction elsewhere, next stop -  Europe?

The Shell-Tokyo Gas Deal:

Contract – April 2020-March 2030 (10 Years)

Volume – 500,000 metric tons per year

Source – Shell global portfolio

Pricing – Formula based on coal and oil & gas-linked indexes

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April, 15 2019