The fact that US natural gas prices have increased 140% this year to nearly $6/million BTU sounds like a big deal.
That means anything pegged to the cost of gas will cost more, which is good news for those with gas to sell.
But is it anything more than another short-term fluctuation in the price of a volatile, unpredictable commodity?
It is hard to argue no. There has been a barrage of alarming reports about short supplies of heating fuel in Europe and China as winter approaches that pushed up the value of gas for sale to more than $30/million BTU in Asia and Europe, according to Bloomberg and Platts.
The explanation is that buyers are assuming this year’s winter could be a repeat of last year’s unexpectedly cold one. It is an annual worry, but the prices suggest this time the impact could be more extreme.
After years of US gas trading in a tight range of $2–3/Mcf, this marks a break from the trend that will push up the price of things made from gas, ranging from electricity to chemicals.
It is the first time US gas prices have broken $5 since 2014. And it will test how adding a substantial amount of renewable energy to the mix will alter the dynamics of the market.
One thing that has not changed: A warm snap in January could totally change the narrative, causing energy prices to crater.
Winter Worries Return
Those who have been writing about gas for a while remember the winter heating season was a dependably significant annual story line.
During the first decade of the century, every winter held the possibility of a massive gas price spike if the winter was colder than expected and supplies got tight.
For much of that decade, US gas was worth more than $5/Mcf, and on two occasions it surged above $10/Mcf during a period when gas production was declining in the US, with imports rising from Canada and talk about the US becoming a gas-importing country.
That era ended around the end of that decade when the shale revolution began flooding the market with gas. The Marcellus Formation in the northeast added a huge source of the fuel for heating and electric generation near the biggest urban markets, reducing prices and limiting price spikes.
This year, the winter heating season has become a compelling story line again because North America is no longer an isolated gas market. Exports from a handful of large gas liquefication facilities have connected US producers to world markets where they are competing with Australia, Qatar, and Russia.
It has been a slow-building change that dates back to 2016. It has reached critical mass over the past 2 years as the US liquefied natural gas ( LNG) export capacity doubled to about 10 Bcf/D, and growing.
Demand from LNG facilities revived the gas-rich Haynesville play and benefitted other Texas oil plays with a growing supply of associated gas as wells age and tilt from oil to methane.
The US’s position as one of the world’s large gas producers means prices are lower and less volatile for consumers here than in Europe. But it is no longer isolated from those markets.
Propane or Oil?
Which fuel is the more expensive source of a million BTUs, oil or propane?
The answer is propane, and price difference has been steadily rising. The US Energy Information Administration (EIA) reported the cost of a million BTU of propane was a $1.80 higher than oil for the week ended 22 September, up from $0.67 the previous week.
Like LNG, propane is becoming a fast-growing US export, with 60% of it going to international buyers looking for fuel for heating or petrochemical feedstocks. The demand that week also included a large order from a plant needing the gas liquid to make propylene—a sign of rising demand as the economic impact of COVID-19 slowly recedes. It is likely to last until OPEC+ increases gas liquids supply as it increases oil production.
Buyers who can switch fuels are looking for the lowest-cost hydrocarbon. There have been reports in the past week of rising demand for oil as a substitute for natural gas.
“Record-high electricity and natural gas prices have not only knocked out fuel-intensive industry production but are creating fundamental knock-on effects on oil,” wrote Bjornar Tonhaugen, head of oil markets for Rystad.
“We could see an additional oil demand boost of nearly 1 million B/D for December 2021, half of which we deem quite likely to materialize from incremental oil-for-power generation in Asia. The remaining half is more uncertain and hinges on a colder-than-normal start of winter in the Northern Hemisphere, which would drive oil-for-heating,” he said.
While gas supplies are a concern in China, the big worry there is the supply of coal. Many Chinese factories have had to shut down because of a lack of power because electricity generators are running short of coal and are scrambling to line up more in a tight market where their buying power is limited by the price they can charge for electricity.
In Europe, supplies were also tight because of a long list of reasons. A Bloomberg story summarized Europe’s power shortage: “Lower volumes of gas piped in from Russia, less gas exported from Norway, Trinidad, and Nigeria. Less gas stored because the previous winter was colder than average. Higher demand for gas globally as economies emerge from pandemic lockdowns. Very low wind speeds.”
As a result, Tonhaugen said Asian LNG, European gas, and global coal markets are hitting all-time highs, while fuel oil and other distilled product prices are rising to meet the expected demand for backup generation capacity.
Richer BOEs
For producers in oil-rich shale plays, gas income had become a significant source of revenue because of steadily rising prices this year, even before the fall surge.
By year’s end, gas prices are expected to range from $4 to $6/Mcf, according to more than 70% of the oil and gas executives surveyed by the Federal Reserve Bank of Dallas in late September.
Demand is up, but US gas supply remains limited because of the continued slowdown in US drilling, which is benefiting from growing export demand from pipelines to Mexico and LNG to the world.
For many companies, though, the bottom line benefit is far less than the price rise would suggest. They reduced their exposure in the event the gas price plunged by using hedging strategies that also limit their upside.
Still, if higher prices become the norm, gas income will become a more significant part of their business, particularly during a time when operators are constantly looking for incremental ways to improve their profit margins.
Earnings reports acknowledge that operators produce a mix of oil and gas by reporting production based on BOE—that is, barrels of oil and its energy equivalent in gas, which is the standard production measure in unconventional plays where good oil wells also produce a lot of gas, which moves the liquids out of the ultratight rock.
Because gas sells for a lot less than oil, a BOE is worth less than a barrel of oil, but that gap is narrowing. For example, a BOE that is half oil and half gas—which is line with the Permian average—would have been worth $35 in September 2018; based on today’s prices, it is worth $55.
Anyone lucky enough to have a cargo of gas to sell in Europe could sell an all-gas BOE for $120 or more. Bloomberg reported that the price on 1 October at a key Dutch trading hub would be the equivalent of $190/bbl of oil.
(The formula used was the price per barrel of oil divided by 2 and the price of an Mcf of gas multiplied by 3, to equal half of the 6,000 BTU in an oil barrel).
That increase helps explain how shale producers have finally become profitable—dividend-paying cash machines.
One oil executive in the Dallas Fed survey even said, “We have pivoted to producing more natural gas and less crude oil. The decrease in our oil production compared to last year is the result of a sale of oil properties. We are bullish on natural gas for the next few years.
There are gas-only companies, but they are in the minority. Among 54 independent producers analyzed for an EIA report, gas represented 10% of their revenues, down from 14% in the first quarter when oil prices were lower.
Slowed-down development plus a focus on maximizing the value of what comes out of wells may also explain a decline in flaring. According to the Texas Railroad Commission, the amount flared in July totaled 4.7 Bcf/D, compared with 19.8 Bcf/D for the same month in 2019.
The fact that gas pipeline capacity caught up with production over the past 2 years, allowing producers to sell for nearly the benchmark price, also is a big reason for the decline.
However, a statement about the flaring drop from Wayne Christian, the chairman of the Texas Railroad Commission, explained that the “drop in the flaring rate here in Texas follows a cooperative effort between the Railroad Commission and oil and gas companies to find innovative technological solutions that would result in less gas being flared.”
He did not offer any particulars about the innovations. He might have been referring to using field gas to generate electricity for fracturing or even using it to power computers mining for bitcoin.
It will be interesting to see if higher oil prices will push the amount of gas flared.
In the past, when oil prices were high, production growth in the Permian and Bakken was accompanied by rising flaring as producers rushed to sell the oil that was far more valuable than the gas.
Those booms were triggered by far lower oil prices, but this time around they are making good money by not growing fast and the gas is worth a lot more than it used to be, so maybe there’s a new way of doing business in shale.
