The US-China trade war took a turn for the worse this week and could fester for months, potentially denting Chinese economic growth and oil demand well into 2019. That spectre controlled oil market sentiment almost to the exclusion of all other influences this week and had forced Brent to re-test recent support levels around $71/barrel on Friday.
Decisions by Washington and Beijing on August 7 and 8, to proceed with a second round of bilateral tariffs on $16 billion worth of annual imports starting from August 23, squashed any hopes of a return to negotiations. The Trump administration wants to narrow the $375-billion trade gap the US had with China as of 2017 and has threatened to impose duties on all $500 billion worth of its imports from the Asian giant. China is expected to run out of ammunition in its reciprocal retaliation much before that finish line, and yet, it is hard to see it backing off.
Chinese oil consumption is still centered around manufacturing despite the economy’s ongoing pivot to a services-led growth model, and there have been other signs of a demand slowdown, especially after the independent refiners or “teapots”, were hit hard by tightened tax regulations in March that had nothing to do with the tariffs dispute.
Crude imports by China, the largest in the world and a closely monitored proxy for its appetite, slipped two months in a row over May and June. Though there was a slight uptick in July imports to around 8.52 million b/d from a six-month nadir of 8.39 million b/d in June, market confidence in the country’s growth has been shaken.
Consensus expectations on US economic growth remain sanguine but it may be worth paying closer attention to its oil consumption data. Refined products supplied across the US, a proxy for consumption, averaged around 20.93 million b/d in the week to August 3, a slump of 1 million b/d from the corresponding week of 2017, according to the Energy Information Administration. Gasoline use, which accounts for nearly 45% of US oil demand, slid by 540,000 b/d from a week ago to around 9.35 million b/d, in the midst of the country’s peak summer driving demand season. However, four-week average figures, which smooths out volatility that may be more noise than signal, do not indicate any major downtrends.
In a curious last-minute twist in the trade war, China dropped US crude from its list of items that will attract 25% import duty from August 23 and included diesel, jet fuel, naphtha and propane, alongside a host of petrochemical products. The about-turn on crude could be aimed at alleviating pressure on Chinese refiners and holding it as a trump card for later use when Beijing’s leverage in terms of the value of remaining goods to tax withers.
China was the largest overseas buyer of US crude in May, averaging 427,000 b/d of imports, according to the latest monthly data from the EIA. Imports spiked to a record 553,000 b/d in June, according to Reuters. However, Chinese refiners began shunning US crude from July and may not risk resuming imports despite the commodity having been left off the latest tariff list, for fear that it may be reinstated any time. US LNG, which China had left alone but decided to threaten with a 25% import tariff on August 3, is a case in point.
The broader global economic fallout of a bitter fight between the world’s two largest economies defies prediction, but appears to have invited a general sense of gloom as far as oil demand is concerned. That may have been helped by bearishness closing in from the supply side as well. Growing flows from some of the OPEC/non-OPEC producers who have been ramping up in line with the ministerial agreement in Vienna on June 23 to boost collective output by up 1 million b/d have hit progressively the market since June (the Saudis had likely started ramping up that month, even before the Vienna deal).
A moderate-sized contango has entrenched itself at the front end of the Brent forward curve since mid-July, a market state that typically signals supply overshadowing demand. However, WTI, Dubai and Oman time spreads are in backwardation.
What's next for oil? We see no escape from the vortex of bearishness for the next few weeks, though we expect the OPEC/non-OPEC leadership to regroup to shore up prices if Brent breaches the key psychological level of $70/barrel. Looking beyond the next few weeks, the combination of Iran sanctions, moderating US oil production growth, and an exhausted OPEC/non-OPEC spare production capacity could hit the market with a perfect storm in Q4.
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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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