Last Updated: August 6, 2018
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Two big bearish influences have yanked Brent and WTI down by $5-6/barrel from their 42-month peaks, but may be overturned by a supply shock as we approach the fourth quarter of this year. The price slide was triggered by a substantial boost in Saudi production in June and reinforced this week by reports of a rising tide in July not only from the kingdom, but joined by growing flows from Iraq, Kuwait, UAE, Algeria, Russia and Brazil. The countries are pumping at their highest levels since end-2016. 

Within OPEC, the hikes more than offset the declines from Venezuela, Iran and Libya, to produce a net increase of around 340,000 b/d in July compared with June. 

Incremental supply resulting from the OPEC/non-OPEC ministers’ agreement for a 1 million b/d boost in Vienna on June 23, meant to calm Brent down from the $80/barrel mark that had rattled several producer countries, may have come too soon. 

Much would depend on how the second factor weighing on crude prices — mounting trade conflict between the US and China — pans out. Tensions spiked this week after the US said it was considering raising the proposed import tariff rate on $200 billion worth of goods from China from 10% to 25%. 

China said it would have to retaliate “to defend the nation’s dignity”. The country might be running out of ammunition, though, as it buys much less from the US than what it sells to that country — an annual trade deficit of around $370 billion, which is at the heart of Donald Trump’s crusade. 

China might compensate for that lack of leverage by continuing to shun US crude imports and rejecting Washington’s demands to curtail its business with Iran. And it might let the yuan depreciate against the US dollar, which makes Chinese exports more competitive, while discouraging imports, as they become relatively costlier. 

The yuan has slumped by around 8.8% against the dollar since mid-April, accelerating its fall in recent weeks. The first round of tit-for-tat tariffs by the US and China on $34 billion worth of imports went into effect on July 6. 

Data this week showed Chinese manufacturing activity grew at its slowest pace in eight months in July as new export orders contracted for the fourth month in a row, a fallout of the bitter trade dispute with the US. The full impact on China’s economy is not expected to be felt until early 2019. But it has begun to weigh on an oil market predisposed to bearishness due to the additional barrels flowing from the OPEC/non-OPEC producers who had been curtailing output since January 2017. 

Fears of the trade war dampening Chinese oil demand — the second-largest in the world after the US — come on top of two successive monthly contractions in China’s crude imports, which saw June purchase volumes shrinking to the lowest level since December 2017. A marked slowdown in the appetite of the country’s independent refiners or so-called “teapots”, which have slashed operating rates due to shrinking margins after the government plugged some tax loopholes in March, is expected to sustain. These refiners hold 25-30% of China’s 15 million b/d refining capacity. 

Meanwhile, US President Donald Trump this week dangled an ad hoc offer through the press to meet the Iranian leaders without pre-conditions, to which Secretary of State Mike Pompeo promptly added a list of conditions. Tehran, as expected, scoffed at the proposal. While the Iran-backed Houthi rebels in Yemen declared a two-week halt to attacking ships passing through the Bab el-Mandeb strait linked the Red Sea with the Arabian Sea after targeting two Saudi oil tankers in the choke point last week, Iran decided to flex its muscles by launching naval exercises in the Persian Gulf. 

With the first round of US sanctions targeting Iran’s automobiles, gold and currency due to take effect on Monday (August 6), the Iranian rial has gone into a tailspin and there are reports of public protests erupting across the country again. 

The oil market may remain complacent for a few more weeks. But it may be in for a rude shock once US sanctions against Iran’s oil sector begin to bite.

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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.

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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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