Oil prices were on a tear this week, riding a wave of strong supply-demand fundamentals and lingering geopolitical fears. All that the handful of OPEC and non-OPEC ministers gathering in the Saudi coastal city of Jeddah had to do was get out of the way, which they did
Front-month ICE Brent futures scaled a new 40-month peak to settle at $73.78 Thursday, while WTI had notched a high of $68.47 the previous day. Even the sour benchmark, Dubai, which trades at a discount to sweet crude, finished the week above the $70 psychological level, for the first time since 2014.
Shortly after oil bulls took cheer from the absence of any dovish signals from the six-member OPEC/non-OPEC Joint Ministerial Monitoring Committee meeting in Jeddah Friday, US President Donald Trump threw a wet blanket on them. “With record amounts of oil all over the place”, OPEC was keeping prices “artificially high”, he tweeted, adding that it “will not be accepted.”
Brent, which had briefly vaulted over $74/barrel after the JMMC, was back in the red compared with its Thursday’s settle. But it is hard to see what Trump could do to “not accept” the high prices (assuming he doesn’t agree with the free ride the US shale producers are getting due to the OPEC/non-OPEC cuts and hasn’t changed his mind about walking away from the Iran nuclear deal). US imposting tariffs on crude imports won’t serve the purpose and sanctions against 21 countries (Russia, Venezuela and Iran are already in that list) would probably have the opposite of the desired effect.
Irrespective of whether crude settles higher or lower on the day Friday, the Trump dampener is likely to be transitory, with fundamentals soon returning to the driver’s seat in oil. This week was relatively quiet on the geopolitical front, but all it needed was an across-the-board draw in US commercial oil stocks being reported for the previous week, for crude to resume its ascent.
Saudi Energy Minister Khalid al-Falih told the media in Jeddah that he believed OPEC and its allies should persist with their production cuts because OECD oil inventories are significantly above levels before 2014, when the world was hit by a wave of oversupply. Importantly, Russian Energy Minister Alexander Novak, also in Jeddah for the JMMC meeting, concurred with AlFalih’s assessment.
Any revision to the OPEC/non-OPEC producers’ current goal of draining the inventories to their five-year average is to be discussed at the June 22 ministerial meeting. Some ministers have suggested in recent months that the target be tightened to a seven-year average, which would mean continued production restraints to mop up more more barrels from storage.
The long-term Saudi-Russian collaboration, discussed between the respective ministers in Jeddah, is work in progress.
OPEC and its Saudi leadership have turned distinctly hawkish of late and the outcome of the Jeddah meeting should lay any doubts on that count to rest.
We now expect OPEC to move its inventory goalpost at the June meeting and telegraph that to the market in the intervening weeks. That sets the stage for rolling over the cuts beyond December. The only spanner in the works could be the May 12 US decision on Iran sanctions. If it produces a crude spike to $80 or beyond and appears set to crimp Iran supplies, OPEC will have to go back to the drawing board.
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In its latest Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that natural gas-fired electricity generation in the United States will increase by 6% in 2019 and by 2% in 2020. EIA also forecasts that generation from wind power will increase by 6% in 2019 and by 14% in 2020. These trends vary widely among the regions of the country; growth in natural gas generation is highest in the mid-Atlantic region and growth in wind generation is highest in Texas. EIA expects coal-fired electricity generation to decline nationwide, falling by 15% in 2019 and by 9% in 2020.
The trends in projected generation reflect changes in the mix of generating capacity. In the mid-Atlantic region, which is mostly in the PJM Interconnection transmission area, the electricity industry has added more than 12 gigawatts (GW) of new natural gas-fired generating capacity since the beginning of 2018, an increase of 17%.
This new natural gas capacity in PJM has replaced some coal-fired generating capacity—6 GW of coal-fired generation capacity has been retired in that region since the beginning of 2018. The Oyster Creek nuclear power plant in New Jersey was also retired in 2018, and the Three Mile Island plant in Pennsylvania plans to shut down its last remaining reactor this month.
These changes in capacity contribute to EIA’s forecast that natural gas will fuel 39% of electricity generation in the PJM region in 2020, up from a share of 31% in 2018. In contrast, coal is expected to generate 20% of PJM electricity next year, down from 28% in 2018. In 2010, coal fueled 54% of the region’s electricity generation, and natural gas generated 11%.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Wind power has been the fastest-growing source of electricity in recent years in the Electric Reliability Council of Texas (ERCOT) region that serves most of Texas. Since the beginning of 2018, the industry has added 3 GW of wind generating capacity and plans to add another 7 GW before the end of 2020. These additions would result in an increase of nearly 50% from the 2017 wind capacity level in ERCOT. EIA expects wind to supply 20% of ERCOT total generation in 2019 and 24% in 2020. If realized, wind would match coal’s share of ERCOT's electricity generation this year and exceed it in 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Natural gas-fired generation in ERCOT has fluctuated in recent years in response to changes in the cost of the fuel. EIA forecasts the Henry Hub natural gas price will fall by 21% in 2019, which contributes to EIA’s expectation that ERCOT’s natural gas generation share will rise from 45% in 2018 to 47% this year. Although EIA forecasts next year’s natural gas prices to remain relatively flat in 2020, the large increase in renewable generating capacity is expected to reduce the region’s 2020 natural gas generation share to 41%.
Headline crude prices for the week beginning 9 September 2019 – Brent: US$61/b; WTI: US$56/b
Headlines of the week
Detailed market research and continuous tracking of market developments—as well as deep, on-the-ground expertise across the globe—informs our outlook on global gas and liquefied natural gas (LNG). We forecast gas demand and then use our infrastructure and contract models to forecast supply-and-demand balances, corresponding gas flows, and pricing implications to 2035.Executive summary
The past year saw the natural-gas market grow at its fastest rate in almost a decade, supported by booming domestic markets in China and the United States and an expanding global gas trade to serve Asian markets. While the pace of growth is set to slow, gas remains the fastest-growing fossil fuel and the only fossil fuel expected to grow beyond 2035.Global gas: Demand expected to grow 0.9 percent per annum to 2035
While we expect coal demand to peak before 2025 and oil demand to peak around 2033, gas demand will continue to grow until 2035, albeit at a slower rate than seen previously. The power-generation and industrial sectors in Asia and North America and the residential and commercial sectors in Southeast Asia, including China, will drive the expected gas-demand growth. Strong growth from these regions will more than offset the demand declines from the mature gas markets of Europe and Northeast Asia.
Gas supply to meet this demand will come mainly from Africa, China, Russia, and the shale-gas-rich United States. China will double its conventional gas production from 2018 to 2035. Gas production in Europe will decline rapidly.LNG: Demand expected to grow 3.6 percent per annum to 2035, with market rebalancing expected in 2027–28
We expect LNG demand to outpace overall gas demand as Asian markets rely on more distant supplies, Europe increases its gas-import dependence, and US producers seek overseas markets for their gas (both pipe and LNG). China will be a major driver of LNG-demand growth, as its domestic supply and pipeline flows will be insufficient to meet rising demand. Similarly, Bangladesh, Pakistan, and South Asia will rely on LNG to meet the growing demand to replace declining domestic supplies. We also expect Europe to increase LNG imports to help offset declining domestic supply.
Demand growth by the middle of next decade should balance the excess LNG capacity in the current market and planned capacity additions. We expect that further capacity growth of around 250 billion cubic meters will be necessary to meet demand to 2035.
With growing shale-gas production in the United States, the country is in a position to join Australia and Qatar as a top global LNG exporter. A number of competing US projects represent the long-run marginal LNG-supply capacity.Key themes uncovered
Over the course of our analysis, we uncovered five key themes to watch for in the global gas market: