The US natural gas market wakes up

The Kraken, the monstrous giant squid of Alfred Lord Tennyson’s poem, lies for a long time at the bottom of the ocean in an “ancient, dreamless, uninvaded sleep”, until it suddenly awakens and roars to the surface. The US natural gas market has been a bit like that. Since 2009, the Henry Hub benchmark gas has averaged around $3.30 per million British thermal units, rarely breaking above $5. But this week, the first-month futures price topped $8/mmBTU, for the first time since 2008.

Although gasoline prices pulled back quickly (futures were back below $7/mmBTU on Thursday night), the rise in prices has highlighted the new dynamic in the market. Changes on both the supply side and the demand side of US gas are combining to reduce flexibility and increase price volatility. There are good reasons to think that the current (relatively) high prices will not last in the long term. But at least for a while, more spikes are definitely possible.

On the demand side, market inflexibility is due in part to the loss of coal-fired power generation capacity. There has been a wave of closures of coal-fired plants that have reached the end of their economic life, often hastened by environmental regulations and corporate emissions targets. The United States lost an average of 11 gigawatts of coal-fired generation capacity each year between 2015 and 2020.

That means coal is less able to act to cap gas prices. Traditionally, if gas prices rose enough, generators would switch to burning more coal, balancing the market. Loss of carbon capacity means the damper has eroded. Low thermal coal reserves have further weakened it.

At the same time, the North American gas market is increasingly connected to the rest of the world. Once largely isolated in splendid isolation, it has been linked to global trends by the growth of LNG imports since Cheniere Energy shipped its first cargo from Sabine Pass Louisiana in 2016. When the global gas market is oversupplied, as it was in the summer of 2020, US LNG exports fall, driving prices down in North America.

When global markets are tight, as they are today, US LNG exporters operate at full capacity. That has stoked concerns about whether gas stored in the US will be adequate for next winter, contributing to upward pressure on prices, says Eugene Kim, director of research for Wood’s Americas gas team. Mackenzie.

Meanwhile, on the supply side, producer responses to high prices are in many cases limited by company commitments to maintain capital discipline, pay down debt and return cash to investors. There was a good example of this last week from Comstock Resources, which produces gas in the Haynesville Shale. It is generating free cash at current gas prices, even though it has hedged about 50% of its production. It is planning a sharp reduction in its debt, from 3.8 times adjusted earnings in 2020 to 1.5 times this year, and announced last week that it would use some of its cash flow to redeem $245 million of senior 7-year notes. .5%, due in 2025. Once its target leverage ratio has been reached, the company says, it will seek to return capital to shareholders. Meanwhile, it is planning average overall production growth of about 2-7% this year.

That capital discipline among E&P companies means US gas production this month is rising only about 3% higher than in April 2021.

The reason to think that current market conditions will be time limited is that the US still has very large gas reserves that can be produced relatively cheaply. “What fundamentally determines the long-term price of US gas is the marginal gas molecule that needs to be brought to market to meet demand,” says Eugene Kim. “Blessed with abundant low-cost gas resources, Henry Hub’s fundamental price is closer to $3/mmBTU, rather than current market prices that have reached $8/mmBTU.”

Still, now that the gas market has woken up, it may be a while before it goes back to sleep. The availability of coal as an alternative to gas is only going to decrease. The US today has about 200 gigawatts of coal-fired generation capacity. Wood Mackenzie forecasts that by 2030, that will be down to just about 90 GW. During the same period, wind and solar power are expected to grow rapidly, creating a threat of further imbalances in the gas market caused by variations in its production. Investments to help manage gas price volatility, including underground storage, may look increasingly attractive.

The lockdown in Shanghai has entered its fifth week, with new enforcement measures announced, as authorities struggle to control the Covid-19 outbreak in the city. Shanghai is normally the world’s busiest container port, and difficulties in moving cargo to and from the docks have contributed to the widespread disruption of international trade. Shipping congestion off Shanghai is adding to the strain on global supply chains and upward pressure on global inflation. Foreign companies are scrambling to get staff back to work in Shanghai, despite the Chinese government’s call for work to resume at 666 major companies.

Germany has been one of the EU’s strongest opponents of a ban on energy imports from Russia. But this week, Foreign Minister Annalena Baerbock pledged to end Russian oil imports by the end of the year. However, the German government has made no such commitment for gas. Employers and unions this week issued a joint statement warning that “a quick gas embargo would lead to lost production, closures, further deindustrialization and long-term loss of jobs in Germany.” Martin Brudermüller, chief executive of BASF, said that the closure of Russian gas imports to Germany would cause the “worst crisis since the Second World War”. Finance Minister Christian Lindner told the BBC: “We are ready to stop all energy imports from Russia, it is only a matter of time.”

Halliburton, the oilfield services group, reported a 24% rise in revenue and a 44% rise in adjusted profit for the first quarter, and gave an optimistic view of its outlook for the rest of the year. Chief Executive Officer Jeff Miller said: “We see significant strain across the entire oil and gas value chain in North America. Commodity prices and strengthening customer demand in the face of a nearly depleted equipment market are expected to drive expansion in Completions & Production division margins.”

Oil producers in the Federal Reserve district that includes Oklahoma, Colorado and Wyoming say they need an average crude price of $62 a barrel for drilling to be profitable, but $86 a barrel for a substantial increase in activity. , according to the latest energy survey from the Kansas City Federal Reserve.
Source: Wood Mackenzie

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