U.S. exports of liquefied natural gas (LNG) have been growing steadily and reached a new peak of 4.7 billion cubic feet per day (Bcf/d) in May 2019, according to the latest data published by the U.S. Department of Energy’s Office of Fossil Energy. This year, the United States became the world’s third-largest LNG exporter, averaging 4.2 Bcf/d in the first five months of the year, exceeding Malaysia’s LNG exports of 3.6 Bcf/d during the same period. The United States is expected to remain the third-largest LNG exporter in the world, behind Australia and Qatar, in 2019–20.
U.S. LNG exports have increased as four new liquefaction units (trains) with a combined capacity of 2.4 Bcf/d—Sabine Pass Train 5, Corpus Christi Trains 1 and 2, and Cameron Train 1—came online since November 2018. Although Asian countries have continued to account for a large share of U.S. LNG exports, shipments to Europe have increased significantly since October 2018 and accounted for almost 40% of U.S. LNG exports in the first five months of 2019. LNG exports to Europe surpassed exports to Asia for the first time in January 2019.
A warm winter in Asia and declining price differentials between European and Asian spot natural gas prices led to increased volumes of U.S. LNG exports delivered to Europe. Europe’s total LNG imports in the winter of 2018–19 averaged 10.2 Bcf/d, 60% higher than in the previous two winters and the highest winter average since at least 2013, according to CEDIGAZ LNG data. LNG imports to Europe have been relatively low in recent years, but they are expected to grow as new LNG supply comes online and European countries continue to increase natural gas consumption as part of their decarbonization initiatives.
Total LNG imports in the three largest global LNG markets—Japan, China, and South Korea—started to decrease in February 2019 amid a milder-than-normal winter and, in Japan, the restart of nuclear power plants. China, which became the world’s second-largest LNG importer in 2017 (surpassing South Korea) and the world’s largest importer of total natural gas in 2018 (surpassing Japan and Germany), continued to increase LNG imports. Its LNG imports were 20% (1.3 Bcf/d) higher in the first five months of 2019 compared with the same period last year as the country continued to expand LNG import capacity and implement coal-to-gas switching policies.
LNG from the United States accounted for 7% of China’s total LNG imports in the first six months of 2018. In September 2018, China imposed a 10% tariff on LNG imports from the United States, and in the months since then (October 2018 through May 2019), U.S. LNG has accounted for 1% of China’s LNG imports. Because no long-term contracts between suppliers of U.S. LNG and Chinese buyers exist, LNG from the United States is supplied to China on a spot basis. Spot LNG shipments are dispatched based on the prevailing global spot LNG and natural gas prices, and the tariff made LNG imports from the United States to China less competitive.
Recent declines in price differentials between European pricing benchmarks (including National Balancing Point (NBP) in the United Kingdom and Title Transfer Facility (TTF) in the Netherlands) and Asian spot LNG prices (including Japan LNG spot prices) have affected the flow of flexible (i.e., without a fixed destination specified in an offtake LNG contract) U.S. LNG exports.
Because the round-trip transportation costs from the U.S. Gulf Coast to Europe are about $1.50 per million British thermal units (MMBtu) lower than those to Asian markets, a sufficiently narrow price spread between European and Asian spot natural gas/LNG prices will make Europe the preferred destination for exporters of U.S. LNG. The spread between Japan spot LNG and NBP/TTF prices was about $1.00/MMBtu in December 2018 and January 2019, and it reached a low of $0.60/MMBtu in April, which supported continued high U.S. LNG exports to Europe.
The U.S. Energy Information Administration (EIA) expects U.S. LNG exports will continue to increase in 2019 as the first trains at the two new liquefaction facilities (Freeport LNG in Texas and Elba Island LNG in Georgia) come online in the next few months. In its latest Short-Term Energy Outlook, EIA forecasts U.S. LNG exports will average 4.8 Bcf/d in 2019 and 6.9 Bcf/d in 2020 as new liquefaction trains at Cameron, Freeport, and Elba Island are commissioned in the next 18 months.
By 2021, six U.S. liquefaction projects are expected to be fully operational. Another two new U.S. liquefaction projects (Golden Pass in Texas and Calcasieu Pass in Louisiana) that started construction this year are expected to come online by 2025. By that time, EIA projects that the United States will have the world’s largest LNG export capacity, surpassing both Qatar and Australia.
Source: U.S. Energy Information Administration, Bloomberg L.P., and Japan METI
Note: Japan LNG spot price is the average price of spot LNG imported into Japan in the months shown. Singapore LNG is a Singapore-based spot LNG price index. National Balancing Point is the U.K.-based spot natural gas price index.
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Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.