US gas producers contend with low prices [Gas in Transition]
Low natural gas prices – already seen in 2023 – fell even further in the US in early 2024. Henry Hub prices have been trading below $2/mn Btu since the first week of February with few prospects for a significant boost in the short term. This translates into challenging market conditions for the US’ gas producers, and with no immediate relief in sight, they have been exploring different options for mitigating against low prices.
One popular strategy when prices drop is scaling back production and spending on new drilling. Several major gas-focused producers including Chesapeake Energy, Comstock Resources, Antero Resources and EQT are all taking steps to cut back some of their production in various ways.
EQT started curtailing around 1bn ft3/day of gross production in late February, with the curtailment expected to last at least until the end of March and the company due to reassess market conditions thereafter. Comstock said in its last earnings call that it would cut its number of operating rigs from seven to five and lowered its capex guidance for the year. Antero said its 2024 drilling and completion capex would be 26% lower than in 2023, while its gas output was expected to decline 3% year on year following the recent dropping of one rig and one completion crew.
Chesapeake, meanwhile, announced a nearly 20% cut in capex, as well as plans to cut two rigs and two completion crews. This is expected to result in around a nearly 15% decrease in production versus its prior guidance. However, Chesapeake’s approach involves deferring turn-in-lines (TILs), leaving a number of wells almost complete and ready to be brought online quickly if market conditions change.
“Chesapeake has talked about the turn-in-line approach, which is where you're drilling and completing a well, but you're not actually doing the final step to turn it on,” Stephen Ellis, an energy and utilities strategist for Morningstar, tells NGW. “You're spending a little more on capex upfront and you take more of a production hit, but you end up having a well that is able to respond to price changes, essentially within days – a week-type thing instead of weeks or months. It’s far more flexible.”
Ellis adds that he would not be surprised if other producers were to adopt such an approach if their wells and market conditions allowed them to do so.
However, while Chesapeake’s approach has been described as “innovative” by analytics firm RBN Energy, it remains broadly in line with US gas producer strategies as a whole.
“Producers are taking steps to choke back wells and defer completions,” natural gas analysts at RBN tell NGW. “We have written before about how producers have a playbook for dealing with temporary low prices, allowing them to make ‘game-time decisions’ to temporarily scale back natural gas production. We saw a lot of these methods used at the start of the COVID crisis, and we are seeing them again in the current low-price environment.”
These efforts are already having an impact on US gas production, illustrating the speed of operator responses.
“Lower 48 dry gas production this March is averaging 4.2bn ft3/d lower than in December, so a lot of production has come off already,” the RBN analysts say. “But these cutbacks are not designed to be permanent, because producers want to produce, and will prepare to produce in the future when they can’t produce in the present.”
Associated gas
The drop-off in output, however, could be offset by broader industry behaviour, which is not linked to gas price movements.
“Unfortunately for producers in major gas-heavy basins, the producers in oil-heavy regions like the Permian consider natural gas to be a byproduct, limiting supply destruction no matter what the gas price,” say the RBN analysts.
Ellis notes that much of the oil production growth in the Permian Basin has come from privately owned companies in the last couple of years, but that with some private producers being taken over by public firms, their output growth could slow. Examples of private-to-public consolidation currently underway include Endeavor Energy Resources being acquired by Diamondback Energy and CrownRock being taken over by Occidental Petroleum – with both transactions due to close this year.
If private operators’ oil output growth slows once they are incorporated into public companies, “that’s also going to mean that associated gas production from those wells is going to come down”, Ellis says.
A challenging year
Even if associated gas production drops, though, US gas prices are not expected to receive a significant boost until more LNG export capacity comes online.
“I think originally, we were hoping that more LNG demand would come online in 2024, but since we've constantly seen delays in new LNG terminals coming online and they keep getting pushed back,” says Ellis.
As a result, Ellis does not see feed gas demand from LNG terminals rising until 2025. RBN agrees, though it notes that it “explicitly disclaims” price forecasts and that this is more of a view on how it expects the market to develop.
“The new LNG export facilities scheduled to come into service in 2025 should put upward price pressure on the market, intensifying as even more facilities come online in 2027,” the RBN analysts say. “However, we also believe that production will continue on an upward trajectory over the next few years, blunting the price impact of the LNG feed gas increase. It will continue to be a long hard road for gas producers even once new LNG capacity develops. That being said, 2024 should prove particularly challenging.”
Vertical integration
Gas producers will therefore have to continue looking for ways to mitigate against challenging market conditions. One more approach has been demonstrated recently by EQT, which announced in mid-March that it had agreed to buy Equitrans Midstream in an all-stock deal worth around $14bn including debt.
Equitrans is building the Mountain Valley gas pipeline in the US Northeast, which is being targeted for start-up this year after various delays. Equitrans was originally spun off from EQT in 2018, when the company agreed to separate its upstream and midstream businesses under pressure from certain shareholders. Now, EQT is reintegrating Equitrans in a bid to boost margins by having more control of transport and processing costs. EQT’s president and CEO, Toby Rice, described the deal as “the most strategic and transformational transactional EQT has ever pursued.”
There are still hurdles to be overcome, including bringing Mountain Valley online. And Ellis notes that E&P firms’ investments in the midstream sector have had mixed results in the past. However, he adds that there is a difference between owning midstream assets in a region with multiple takeaway capacity options, such as the Permian, compared with infrastructure-constrained regions such as Appalachia – as well as differences between oil and gas midstream costs.
“It potentially could lead to a much better outcome for EQT than we would have seen in the past,” Ellis says.
RBN also views the deal as a positive for EQT and suggests that other producers may want to follow suit with similar deals.
“The majority of EQT production flows through the Equitrans gathering system,” say the RBN gas analysts. “The gas-gathering item is a huge factor in profitability for EQT and other gas-weighted E&Ps. So, the vertical integration exemplified by the merger acts as a kind of hedge against sustained low prices by helping producers stay profitable even in a low-price environment. Similar mergers are likely as a way for producers to stay relevant.”