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US gas enters an era of increased price volatility

The slump in Henry Hub prices, following steep rises in 2022, is a sign of the need for more gas storage

9 minute read

Even now, two decades after it began, the US shale gas revolution can still astonish. Benchmark Henry Hub month-ahead futures dropped this week to a low of US$1.52 per million British Thermal Units, a level last seen at the height of the Covid-19 pandemic in 2020. Excluding that period, US gas prices have not been this low since the 1990s, when demand was only about half the level it is today.

In real terms, adjusting for consumer price inflation, the Henry Hub price today is only about 20% of what it was in 2000.

Weak prices this winter have underlined the fact that North America holds vast resources of natural gas that can be produced at relatively low cost. That resource base supports Wood Mackenzie’s forecast that equilibrium US gas prices will remain subdued, rising only slowly out to 2050 and beyond.

But while the outlook for average gas prices remains stable, the potential for volatility around those averages has increased. Henry Hub surged briefly above US$10/mmBTU just 18 months ago, despite that vast low-cost resource base. It is likely that price volatility will persist until there is a substantial increase in gas storage capacity in the US.

The immediate cause of the current gas price slump has been the unusually mild winter. Globally, this February may turn out to have been the warmest on record. Gas demand has been lower than usual, and the volumes in storage are well above their five-year average.

Henry Hub prices cannot stay below US$2/mmBTU forever, because supply will be throttled back to rebalance the market. It is already starting to happen. Chesapeake Energy, which will become the largest gas producer in the US when it completes its acquisition of Southwestern Energy, said this week in its fourth-quarter earnings announcement that it would be deferring well completions and the turn-in-lines that start production.

Comstock Resources announced last week it was cutting one frac crew and two rigs from its operations in the Haynesville shale, saying it was “actively managing drilling activity levels to prudently respond to [the] current low gas price environment.”

Over time, the actions taken by these companies and others will tighten the market and drive prices higher. But it will take a while for the effects to work through. Deferring completions will affect production one to three months ahead, and cutting back on drilling typically has an impact six to nine months out.

If at some point gas prices go much higher again, the adjustment back down to average levels will also not be immediate. In time there will be a response in increased supply, but oil and gas companies are still under pressure to strengthen balance sheets and return capital to shareholders, and will not rush to chase higher prices with a surge in activity and production.

On the demand side, one factor that used to act as a limiter on rising prices was a shift to coal for power generation when gas became too expensive. That has been weakened by the loss of coal-fired power plants. At the end of 2013 the US had 300 gigawatts of coal-fired generation capacity. Today it is only about 179 GW, and the number is set to fall further as more plants are retired.

In 2022, two other factors sustained demand for US gas even as its price soared. US coal stockpiles were low, meaning that the coal-fired power plants that were still operational were unable to ramp up generation to replace gas-fired plants. And world gas prices were high in the aftermath of Russia’s invasion of Ukraine, meaning that LNG exporters had no reason to shut off sales.

Eventually there was enough of a supply response to drive prices down. US gas production grew 6% between the first quarter of 2022 and the first quarter of 2023. But it did not come quickly enough to stop Henry Hub staying above US$5/mmBTU for nine months of 2022, reaching US$10/mmBTU in August.

Eugene Kim, Wood Mackenzie’s research director for Americas gas, says the US needs more storage facilities to smooth out these peaks and troughs in prices. “This greater volatility is a result of the US market having expanded significantly without an equivalent expansion in storage capacity,” he says. “We have seen a few companies moving to take advantage of these price movements by investing in storage, but it’s not enough.”

The maximum gas storage recorded in the US is about 4 trillion cubic feet, and that level has not changed much in the past decade, even though gas demand has been rising steadily. Total gas in storage in the US in October 2013 could cover 62 days of demand. By October 2023 it could only cover 39 days.

The intrinsic value of gas storage in North America, which has underpinned its business model for decades, is based on the seasonal spread between summer and winter prices. Gas is injected into storage from April to October, and then withdrawn over the winter. But in the past decade that price spread has been compressed, in part because shale production has been able to flex to some degree to match seasonal changes in demand. The result has been that the incentive to build more storage capacity has been muted.

If you can time the market right to fill storage when Henry Hub is below US$2/mmBTU and sell when it is at US$10/mmBTU, that is good business, of course. But those price movements at a time of increased volatility are inherently difficult to predict.

Other recent gas price spikes have come during extreme weather events, including Winter Storm Uri in 2021 and the cold conditions across the US last month. Storage facilities able to operate in those conditions could have been highly profitable. But the frequency of those events may be too uncertain to support an investment case for more storage.

The cure for low prices is low prices, and the cure for volatility is volatility. Ultimately, we expect more storage to get built to arbitrage away the extremes. But until then, the potential for more price volatility will remain.

In brief

The US government has continued slowly to replenish the Strategic Petroleum Reserve, buying back a small proportion of the crude volumes that were sold in 2022-23. The low point for the SPR was in July last year, at about 347 million barrels, down from 595 million barrels at the end of 2021. Since last summer, about 12 million barrels have been bought. The administration has previously said it sold the oil in 2022 at an average price of US$95 per barrel. As of Friday morning, West Texas Intermediate was trading at about US$78 per barrel.

China would need a record fall in emissions by next year to meet its carbon intensity target for 2025, an analysis for Carbon Brief has concluded. China’s total energy consumption grew by 5.7% in 2023, preliminary government data show, driving up emissions by about 5.2%, according to the Carbon Brief analysis. The 2025 carbon intensity target is “all but unachievable”, the analysis suggests. However, it adds that China may be able to hit many of its other climate targets, thanks to the rapid growth in its low-carbon energy industries, if it can also moderate the growth of energy demand.

The US Department of Energy has signed a novel fixed-price milestone contract with Kairos Power, providing up to US$303 million to support the company’s development of its innovative reactor design. Hopes of developing the advanced nuclear industry in the US suffered a blow last year when prospective customers pulled out of a planned NuScale Small Modular Reactor development in Idaho.

And finally: the most recent season of the TV crime series ‘True Detective’ has been controversial, but I generally enjoyed it. I did, however, balk at a line in the last episode, when a character says “pollution levels in the region are 11 times higher than those currently acceptable by the Vienna Convention and the UNFCCC.” I think someone should have let the writers know that that is not how either the Vienna Convention or the UNFCCC work.

Other views

Is consolidation changing upstream’s appetite for investment? – Simon Flowers

What does the EU’s new decarbonisation roadmap mean for its carbon economy? – Stephen Vogado

Energy transition outlook: Asia Pacific – Prakash Sharma, Roshna N and Jom Madan

The European Union-Russia energy divorce: state of play – Ben McWilliams and others

GETting Interconnected in PJM

Severe drought erased climate progress in the northwest in 2023 – Michael Thomas

The problem with Europe’s ageing wind farms – Barney Jopson

Why you probably shouldn’t blow up a pipeline – Eric Levitz

A heat pump water heater will save all the electricity you’ll need to power your electric vehicle – Naomi Cole and Joe Wachunas

Biden’s EV dreams are a nightmare for Tesla and the US car industry – Mark Burton and others

Quote of the week

“We now have the most significant clean energy and climate strategy in the nation’s history. Arguably in the world. The strategy for building a clean energy future in the United States rests on four legs. First, making the United States the irresistible nation for investing in clean energy. Second, ensuring that those investments provide economic and clean energy benefits in the communities that have been left behind. Third, strengthening America’s workforce so that our workers have the skills they need to compete in this global clean energy market. And fourth, with cutting-edge R&D, supporting industry so that each future generation of clean energy technology will be more innovative than the last.” – Jennifer Granholm, the US energy secretary, used a speech in Washington to explain the administration’s thinking in supporting low-carbon energy industries.

Chart of the week

This comes from Wood Mackenzie’s latest Horizons report, Over the rainbow: why understanding full value-chain carbon intensity is trumping the colour of hydrogen, by Flor Lucia De la Cruz, our principal analyst for hydrogen and its derivatives. The central argument of the report is that while the rainbow of hydrogen “colours” used to identify production pathways – green for electrolysis of water using renewable energy, blue for reforming natural gas with carbon capture, and so on – might have helped build understanding in the industry’s early days, we now need to move past it. De La Cruz argues that the hydrogen industry “requires ever more accurate project-level certification of carbon intensity” as it evolves.

The chart makes her point perfectly. It is often assumed that green hydrogen will necessarily have lower associated emissions than blue, but that is not always the case. Projects that ostensibly produce green or blue hydrogen can have widely varying emissions, depending on factors including the plant’s location, the precise sources of the power it uses, and the proportion of carbon dioxide emissions that are captured. At some times and in some places, associated emissions for some green hydrogen sources can be higher than for some blue hydrogen sources.

Investors, customers, regulators and policymakers, seeking to decide practical questions such as eligibility for tax credits and progress towards meeting emissions targets, will need significant amounts of additional information to know exactly how different sources of hydrogen should be treated.

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