NGI’s 3Q2023 North American Natural Gas Supply and Demand Analyst Takeaways

North American natural gas prices dropped dramatically in 2023 as producers maintained robust production levels, inventories grew and international markets found more balance after Russia invaded Ukraine. Read what NGI analysts learned during 3Q2023 earnings season and how they view supply and demand trends moving forward.

• EQT Corp. (EQT): The marginal molecule of U.S. natural gas supply is coming from the Haynesville Shale, requiring a natural gas price of $3.50/MMBtu “to even begin generating cash flow in maintenance mode.” That’s certainly in line with what BTU Analytics LLC is thinking, as they currently peg the natural gas breakeven price in the Haynesville at $3.456/MMbtu. Shorter term, however, the breakeven may be quite a bit less than that. Why? Because the backlog of drilled but uncompleted wells in the Haynesville continues to grow, and in our estimation, is the only major shale basin in the United States where that has been the case since the year 2020. 
• EQT: You can’t have the No. 1 natural gas producer in the United States not offer its macro view on prices, right? CEO Toby Rice said the natural gas outlook should improve. EQT expects a lower overhang in U.S. storage thanks to robust gas-fired power generation, “resilient” export demand, and “lower-than-expected production this summer.” EQT also expects L48 production exit volumes at year-end 2023 will be flat or slightly down quarter-over-quarter. Moreover, EQT sees more weakness in 1H2024 as the impact from a 25%-plus drop in gas rigs since March begins to set in, especially in the high-decline Haynesville play where the rig count remains well below maintenance levels. Management said the progress demonstrated commissioning the Golden Pass and Plaquemines LNG facilities has been encouraging and will create structural tailwinds even before the facilities are fully operational. EQT also expects that U.S. coal production will drop by more than 20% year-over-year in 2024 as the impact of recent coal plant retirements hits the market. 
• EQT: Longer-term, EQT believes that the commencement of service on the Mountain Valley Pipeline, and retirement of more coal-fired plants in the PJM Interconnection market represents an upside of over 4 Bcf/d of demand for Appalachian gas over the next five years. Furthermore, EQT is modeling a 5 Bcf/d increase in LNG export demand by year-end 2025, along with another 1 Bcf/d from a combination of exports to Mexico and industrial demand.
• EQT: The company reported their third quarter pumping hours per crew averaged more than 400 hours, which is an all-time high pace for EQT. That included two crews each achieving more than 500 pumping hours in a month. “To put this into context, the theoretical maximum pumping hours in a month for a single frac crew is roughly 600 hours after accounting for minimum maintenance time, so our teams are knocking on the doorstep of perfection,” management said. Of course, coming close to perfection means lower incremental gains going forward.
• Kinder Morgan Inc. (KMI): Demand for U.S. storage continues to rise and rates are moving higher, especially for multi-cycle salt facilities versus single-cycle reservoir storage, but still may not be quite high enough to spark much new build activity. In fact, KMI noted in their December 2023 investor relations presentation that rates are still below the cost to develop greenfield storage. 
• SLB Corp. (SLB): The company thinks activity in North America is bottoming going into 2024. It expects to see increased activity from here, although they cautioned they don’t have the budget numbers from their customers just yet.
• Liberty Energy Inc. (LBRT): Management said the fourth quarter could see seasonal softness from winter weather and holiday disruptions, but recent strength in commodity prices will help drive activity soon thereafter. Improved cycle times and budget exhaustion should also contribute to reduced activity. We believe the data are bearing this out. According to Baker Hughes Co., the U.S. rig count stood at 626 on Dec. 8, basically flat from levels entering the quarter. 
• LBRT: Management noted that hydraulic fracturing (fracking) activity has largely stabilized, reaching a baseload level of activity needed to sustain flat production. They think the U.S. rig count is bottoming now and should see it grow over the next 6-12 months. “But in our new boring shale industry, it’s probably going to grow more slowly and modestly,” said CEO Chris Wright. 
• LBRT: Wright said the United States will see an increase in gas focused activity, but producers are waiting for the right gas signals. Increased LNG operations will help. As such, Wright believes fracking activity for gas starts 2Q2024 or even sooner. If we have a warm winter, then 3Q2024. Through Dec. 9, total U.S. heating days are down 12% this season, so perhaps it’s looking more like 3Q2024. 
• Nabors Industries Ltd. (NBR): NGI believes changes in the frac count tend to lag changes in the number of rigs by roughly one calendar quarter. Thus, if reverse logic holds, and using Chris Wright’s assertion in the previous note, this would imply the U.S. rig count should start to improve sometime in the first half of 2024. Nabors Industries offers further supporting evidence. “Once again, we surveyed the largest Lower 48 clients at the end of the third quarter. Our survey covers 17 operators, which account for approximately 45% of the working rigs at the end of the quarter. The survey indicates this group will add about 6% to its rig count through early 2024. This increase is spread across nearly 50% of the surveyed operators. We are encouraged by the distribution of this planned increase. With the expected international additions, we would increase our international rig count by 50% by the end of next year,” said CEO Anthony Petrello.
• Halliburton Co. (HAL): Management noted that drilling activity among private exploration and production (E&P) companies was “super busy” the first part of 2023, but they stepped down their activity going into late summer, a time that is typically more active. That will weigh on production going into 2024, Halliburton management said. We estimate privates make up for roughly one-third of total U.S. gas production, so that’s no small chunk of change. 
• Range Resources Corp. (RRC): According to Range CEO Dennis Degner, increased gas-fired power demand along with “industrial demand growth, exports to Mexico and continued LNG commissioning, sets the tone for the domestic natural gas market to gradually rebalance, particularly when considering the meaningful rig activity reductions we've seen in the Haynesville.”
• RRC: With respect to operational efficiencies, they averaged more than nine frac stages per day in the quarter, up 70% year-over-year. They also completed two of the longest laterals in company history in the third quarter, both more than 21,000 feet. Overall, Range reported achieving a 40% improvement in drilling efficiencies in the first half of 2023, compared to 2022, and a 20-25% increase in completion efficiencies over the same time period.
• National Fuel Gas Co. (NFG): Much of the industry is facing industry absorption and is moving to develop lower tier acreage. In other words, core inventory exhaustion, a topic that has been discussed prominently during producer earnings conference calls the last few quarters. And for good reason, since moving to higher cost production areas requires higher natural gas prices, everything else being equal. But therein lies the rub, we said everything else being equal. Oilfield service companies continually invest in research and development (R&D) to advance technologies. For example, SLB and Halliburton tend to spend either side of 2% of their revenue on R&D, good for a combined $1 billion or so in annual R&D spend. Furthermore, operators also continue to tweak their drilling and completion formulas as well. These result in efficiency gains that lower the overall production cost curve over time. Those gains are not linear and tend to be lumpy, but we believe 3Q2023 saw a step change higher in terms of efficiency improvements, particularly for drilling cycle times in Appalachia. 
• Antero Resources Corp. (AR): Antero reached a company record 129 day cycle time (spud to sales) in June 2023. Furthermore, CEO Paul Rady noted that “Since 2019, our cycle times have decreased by an impressive 65% and averaged just 160 days through the first three quarters of 2023.”
• Chesapeake Energy Corp. (CHK): Drilled four of the fastest 10 Marcellus wells in their history during the third quarter.
• Ovintiv Inc. (OVV): Turning to the Permian Basin, Ovintiv introduced us to the term “trimulfrac,” which is the process of stockpiling wet sand onsite from local mines and completing three wells with a single frac spread at the same time. Management noted roughly 25% of their Permian wells in 2023 will be completed with this technology, and expect to use it on “more than half of our program next year.”  Management went into detail on how this works and potential savings, so for those interested, we’d refer you to their 3Q23 conference call transcript. But needless to say, such technology really isn’t proprietary or exclusive in our view. Others surely will be able to replicate it. 
• Southwestern Energy Co. (SWN): Back in the 1950s, it was a race to break the four-minute mile, a feat first accomplished by Roger Bannister. Today, in the oil and gas industry, the new milestone seems to be drilling wells more than four miles in length, something that is happening more frequently. Southwestern drilled a record 24,000-foot-plus well in Brooke County, WV, in the third quarter, and now has 25 wells in Appalachia with lateral lengths greater than 20,000 feet. And it’s not just limited to the gassier Appalachia. ExxonMobil has plans to drill more four-mile laterals in the Permian. Longer laterals help lower unit costs, which is important in every industry, but especially when producers are price takers. So will four-mile wells become the new standard? Probably not, in our view. Not every region is conducive to such long laterals, of course, and as ConocoPhillips noted, drilling longer laterals increases operational risk not only from drilling the well but also future workovers. Precision Drilling added these longer laterals also require more “hook load, HP, pumps and better top drives,” so there is more of an upfront cost. Still, we imagine this will be quite the popular topic among sell-side analysts during 4Q2023 calls.
• ExxonMobil (XOM): Perhaps the biggest bombshell from 3Q2023 occurred in early October, just before the earnings season began, when XOM announced their acquisition of Pioneer Natural Resources Co. XOM’s management believes they can extract 20% more oil from Pioneer’s Midland sub-basin acreage in the Permian by applying their version of cube technology. The thing is no one outside of XOM (and maybe now Pioneer) seems to know what this improved technology is just yet. Greater recovery factors are another lever to reduce unit costs. Is this improved technology easy to implement? Can it be applied to other basins? These are the questions that will be top of mind going forward and a topic of great interest here at NGI.
• Natural Gas Intelligence (NGI): Last thought: The consensus estimate for oilfield service cost deflation is somewhere in the mid-single digit percentage range, thus allowing operators to get a bit more bang for their buck next year.