Provided Content: Content provided by Baystreet. The Globe and Mail was not involved, and material was not reviewed prior to publication.
Natural Gas Producers Are Slashing Spending As Prices Stumble
All of this has met with an El Niño led reduced demand for winter heating needs. The El Niño effect, combined with extended timelines for the arrival of new LNG demand for pipeline gas, has simply destroyed pricing for the commodity over the last several months. Tying these points to my opening line, we see that a huge storage overhang will greet injection season, with storage volumes that are likely to be substantially above 2023 levels. You can see the slope of the blue line in the EIA gas storage graph below is much flatter than at the same point in late March of 2023, where inventories bottomed at 1.830 TCF. In all likelihood, we will reach late March of 2024 with at least an extra couple of hundred BCF in the tank.
The best time times in gas supplies mean that it’s the worst of times in terms of the prices producers receive for their products. RBN Energy noted in their daily blog a few days ago that gas prices had recently reached historic lows on an adjusted basis-
“Natural gas prices have declined severely over the past two or three weeks, and a few days ago (February 20) the March contract settled at $1.576/MMBtu. In nominal dollars, that was the lowest front-month price since the summer of 2020, but in real, inflation-adjusted terms, it was the lowest price of the 21st century.”
And finally, gas-oriented E&P’s are starting to take note and do the one thing in their power that will eventually reverse the trend.
Late last month, in their quarterly earnings call, Marcellus and Haynesville basins gas driller Chesapeake Energy (NYSE:CHK) joined other gas drillers and announced a strategic 20% reduction in new gas capex. By withholding funds for new production, the gas giant will essentially divert as much as 1.5 BCF/D to a future time when-hopefully prices will be more supportive. Nick Dell’Osso, President and CEO of Chesapeake, commented in the call-
“Given current market dynamics, the company plans to defer placing wells on production while reducing rig and completion activity. The company will drop a rig in the Haynesville and Marcellus in March and around mid-year, respectively, and a frac crew in each basin in March. These activity levels will be maintained through year end. Deferring new well production and completion activity will build a short-cycle, a capital-efficient productive capacity that can be activated when consumer demand requires it. The company expects to drill 95 to 115 wells and place 30 to 40 wells on production in 2024.”
By deferring placing wells online, the company is essentially pushing completion capex into the future and building its Drilled but UnCompleted-DUC inventory to enable a quick turnaround once higher gas prices are seen. Completion capex-sand, water, pumping, and flow back, is often well over half the total cost of turning a well in-line-TIL to sales and deferring it means the wells will be quickly turned to sales-an industry best practice once economic conditions warrant.
Over the last several years, the DUC inventory for operators has been cut by about 50%, as noted in the EIA-DPR from June-2019, to just 4,386 in the current report.
Chesapeake is not alone in tightening its belt to await better days. Other shale operators, and not just gas producers have moved to reduce spending. Notably, fellow Marcellus driller Antero Resources (NYSE:AR) has put in place a 26% capex reduction that includes dropping one rig and one completion crew, with a plan to build DUCs, similar to Chesapeake’s. Another Marcellus driller, Range Resources (NYSE:RRC) has adopted a similar strategy of building DUC inventory, while maintaining operational efficiencies from experienced drill crews.
Distressed Haynesville driller Comstock Resources (NYSE:CRK), has taken even more severe capex curtailment steps, suspending its dividend, dropping 2 of the 7 rigs it operates in the Haynesville, along with a frac crew. The Haynesville basin-producing reservoirs, the Bossier and the Haynesville are deeper and hotter than those in many shale plays, leading to more expensive drilling. When gas prices are sufficient, these costs are quickly offset by surging production from the intensive stimulations the company deploys.
Some gas drillers have maintained output plans to which they have committed, but EQT Corporation, (NYSE:EQT) have commented these plans are “flexible” to take low price realizations into account. Toby Rice, CEO of EQT noted in their quarterly call, that they could decide to “defer some planned TILs to 2025, depending on pricing.”
Summing up
It remains to be seen how long it will take for these capex curtailments to become effective, or if it will happen at all. Liquids production has been growing still in the Permian and to a lesser extent in the Bakken, although, as the DPR points out, these gains are flattening, and with this light ~50°gravity oil comes the associated gas we have discussed. It could be a while, but some help is on the way.
There is a delicate balance for the operators as about 12 BCF/D of new demand will appear on the horizon in the 2025-2028 era, driven by the arrival of newly constructed LNG plants in the Gulf of Mexico and on Mexico’s West Coast, beginning to need pipeline gas. When you add the advent of increased industrial and power-generated demand that will also arrive in this time period, the current gas surplus could quickly turn into a deficit that could also quickly ramp prices.
That is the eventuality that operators are planning and hoping for. Their challenge is to stay alive until then.
By David Messler for Oilprice.com
