Expectations for North American upstream natural gas capital expenditures in 2024 continue to show a year/year decline in the low- to mid-single digits, with subdued rig counts persisting throughout the year. Eventually, those rigs would need to resume work to account for the in-service of more Lower 48 LNG export capacity next year, and possibly to gear up for the rapid growth in data centers – although it is uncertain as to what that opportunity for incremental gas demand may be.
NGI reviewed some of the first quarter of 2024 earnings calls for players in the major North American oil and natural gas production areas in order to gauge future supply and demand trends. NGI’s Patrick Rau, senior vice president for Research & Analysis, also provided a rundown of the top ten themes of 1Q2024 in the latest episode of Hub & Flow.
Baker Hughes Co. (BKR) – Baker Hughes has proclaimed this to be “The Age of Gas.” That’s more of a long-term view, and maybe not quite as apropos a description for 2024, at least not in North America (NA). Both Baker Hughes and SLB Ltd. continue to expect NA activity and spending to be down to the low- to mid-single digits for the rest of this year, primarily because of lower natural gas prices. Thus far in 2024, Lower 48 rigs have fallen to 600 from 622, per Baker Hughes. Even with the recent price rally – which has seen NGI’s daily Henry Hub spot market price index increase from a low of $1.240/MMBtu on March 13 to $2.635 June 3 – rigs are down by six this month.
Nabors Industries Ltd. (NBR) – Expect low rig counts to continue, warned management for Nabors Industries Ltd. In its latest survey of 17 large Lower 48 clients, which covers about 45% of the total rig count, “this group’s year-end 2024 rig count will be modestly lower than the total at the end of the first quarter,” the firm said. Nabors management said this would be mostly the result of merger and acquisition (M&A) activity rather than pure economics. “Essentially, all the projected decline relates to announced merger activity. From our past experience, combined activity usually drops immediately after the merger is completed. Over time, though, we have generally seen a return to prior activity levels for the combined companies. We anticipate the same behavior by our customers following this latest burst of mergers. Aside from the M&A activity, we believe that clients remain cautious about their plans for 2024, particularly in gas-focused basins.”
Diamondback Energy Inc. (FANG) – It’s also taking longer than expected for M&A activity among producers to be approved these days, a notion confirmed by Kaes Van’t Hof, CFO of Diamondback Energy. There have been longer-than-expected delays for approving EQT Corp./Tug Hill Inc., Chevron Corp./Hess Corp., ExxonMobil/Pioneer Natural Resources Co., Chesapeake Energy Corp./Southwestern Energy Co., Occidental Petroleum Corp./CrownRock LP and Diamondback Energy/Endeavor Energy Resources LP, among others. The deals involving EQT and ExxonMobil have at long last closed, but the others likely would not happen until the second half of the year, which is a delay of two-plus quarters. At this pace, any yet-to-be-announced mergers may not clear until sometime in 2025. This increases the risk that drilling activity may continue to lag heading into the impending start-up of the Plaquemines and Corpus Christi Stage 3 liquefied natural gas export projects next year. Continued delays in drilling could lead to a tight supply picture when those facilities ramp, especially if the Lower 48 experiences a colder-than-normal winter.
EQT Corp. (EQT) – Speaking of M&A, will there be more vertical integration by exploration and production (E&P) companies going forward? Flow assurance is always a major consideration for producers. EQT bought Equitrans Midstream Corp., which also lessens the need for EQT to hedge and therefore frees up some working capital. EOG Resources Inc. also is building a 36-inch diameter Verde pipeline to deliver natural gas from its Dorado asset in South Texas to Cheniere Energy Inc.’s Corpus Cristi facility. The midstream master limited partnership industry essentially was born by E&Ps divesting those assets to focus on their upstream core competencies, but permitting issues and severe basis differentials (perhaps in part because of increased volatility) seem to be bringing the vertically integrated model back into vogue.
EQT – U.S. natural gas cash market prices have improved in recent weeks, but Lower 48 production has yet to respond. According to Wood Mackenzie, dry gas production has tried, but failed, to break the 100 Bcf/d level five times since falling below that mark on April 9. That streak would likely end once Mountain Valley Pipeline (MVP) is in-service, which should happen any day, because EQT has been holding about 1 Bcf/d off the market that could fill part of their 1.2 Bcf/d of capacity on that pipe. But that is a special situation. Lower 48 gas production is down 6 Bcf from its peak in mid-February. Some of that is the natural impact of hyperbolic decline rates from existing wells, but it’s estimated that at least 2 Bcf/d of that is from curtailed and deferred production. If all of that displaced production were to hit the market nearly all at once, it could cause another big swing in prices to the downside. All one needs to do is look back at what happened to prices when an explosion at the Freeport LNG sent 2 Bcf/d of supply on the market in June 2022. Instead, these shut-in volumes would likely return more gradually.
Patterson-UTI Energy Inc. (PTEN) – Rig counts continue to fall, but Patterson-UTI expressed more optimism on the completions side. “We think Q2 is likely the low point for our company this year in terms of” hydraulic fracturing (frack) activity, said CEO Andy Hendricks during PTEN’s 1Q24 earnings call. “We’ve had some customer-specific gaps that opened up on our calendar during Q2, and those customers should resume normal activity by Q3.” Overall, Primary Vision frack spread has increased from 240 exiting 2023 to 263 as of May 17, according to Bloomberg. Normally, frack counts tend to lag operating rigs by roughly one quarter, but right now, it’s the frack count that is leading the way.
Natural Gas Intelligence (NGI) – Those completed wells would not necessarily turn into production immediately, since completed wells still need to be hooked up to the pipeline network before they can be turned in-line (TILs). Deferred TILs (DTILs) are essentially a deferred form of storage, and lately have become a popular tool among the larger E&Ps to take advantage of the steep contango in the current gas curve. Henry Hub gas for winter 2024/25 is trading at a $1.074 premium to the current spot market as of June 11, according to NGI’s Forward Look. There may be quite the incentive to wait, as holding out until prices rebound could also significantly improve the internal rates of return of unconventional wells, especially considering year one typically represents their highest annual rate of production. It takes roughly one month to turn DTILs into production, so these wells could be brought on much later this summer, and still arrive in time for winter.
Chesapeake Energy Corp. (CHK) – Still, TILs require more maintenance than drilled but uncompleted (DUC) wells. Josh Viets, COO of Chesapeake Energy Corp., explained that with DTILs, “we do have to be a little bit more thoughtful about how we manage those in terms of our wellbore preparation and preservation, primarily from a corrosion standpoint. But probably most importantly, we do have to stay on top of them, and specifically, it’s around just monitoring the pressure.” He also mentioned the need to guard against offset wells, especially by other operators. “That’s not something we’ve dealt with yet, but we do recognize it’s a threat, and we actively manage that to ensure we’re not impacting the investments that we’ve made on those particular wells.” It’s certainly possible this extra maintenance requirement could cause some operators to turn these DTIL wells to sales a bit faster.
NGI – The hottest topic this quarter was easily the seemingly sudden emergence of data centers and what that may mean for U.S. natural demand going forward. Nobody doubts this is a growth opportunity, but getting a consensus as to what that opportunity could be is like watching a congressional hearing on C-SPAN: opinions are all over the place. Early estimates range between 1 Bcf/d and 20 Bcf/d of incremental gas demand by 2030, the median of which is 6.5 Bcf/d. NGI’s Carolyn Davis, managing editor for News, discussed the opportunities and challenges with Enverus senior energy transition analyst Carson Kearl on NGI’s Hub & Flow.
Williams (WMB) – Storage rates continued to climb, and have reached the point where brownfield storage expansions are now in the money, according to Williams.
Enbridge Inc. (ENB) – Management noted it has seen storage re-contracting prices go up by 100-150%. Michele Harradence, President of Gas Distribution & Storage, noted “just a couple of years ago customers were only wanting two-year storage deals are now going out four to five.” Williams noted their customers are more willing to sign longer-term storage deals as well.
Kinder Morgan Inc. (KMI) – Kinder Morgan regularly ran a snippet in their Investor Relations (IR) presentations that read “Rates [are] still below [the] cost to develop greenfield storage,” but that hasn’t appeared in any of their slide decks thus far in 2024. Storage rates may have been heading to these levels anyway, given forthcoming increased LNG demand in the face of a lack of new Lower 48 capacity growth over the last decade, but the surge in demand for electricity to power 24/7 data centers only enhances the need.
EOG Resources Inc. (EOG) – In the Utica Shale activity continues to advance. In fact, of the major U.S. producing regions, it is the only one not to see a year/year decline in rigs. The Utica is a premium play for EOG Resources, and MPLX LP noted it is seeing growth in the wet gas window with more producers moving in. Capital utilization for MPLX’s Utica processing assets climbed to an average of 59% in 1Q2024, up from 49% in 4Q2023 and 37% a year ago.
DT Midstream Inc. (DTM) – Furthermore, DT Midstream also expects production volume in the Utica to ramp over the next 18-24 months. In its 1Q24 IR presentation, DT Midstream shared a forecast from third parties calling for an increase in Appalachian Basin production from 34 Bcf/d in 2023 to 40 Bcf/d in 2033. MVP can take up to 2.0 Bcf/d of that in a few weeks, and another 0.5 Bcf/d once EQT adds compression to expand the line. Given the lack of new pipeline takeaway capacity from the Marcellus Shale, however, in-basin consumption may be the key to achieving that forecast. Shell plc’s Monaca cracker is now fully operational so that helps a bit. But could more data centers spring up in Ohio, Pennsylvania or West Virginia?
TC Energy Corp. (TRP) – Columbia Gas Transmission serves the data center mecca of Northern Virginia, but could Columbia Gas and other local pipelines serve more load in Pennsylvania? EQT CEO Toby Rice seems to think so: “Our analysis suggests the combination of data center build-outs and additional coal retirements could generate up to 6 Bcf a day of incremental natural gas power demand in our own backyard by 2030.” For that matter, could Pennsylvania just approve an intrastate pipeline that would ship natural gas to a potential export facility along the Atlantic seaboard of the state, à la what natural gas liquids shippers are doing at Marcus Hook?
DTM – The gassy Haynesville Shale is expected to see production rise by 12 Bcf/d in 2033, according to statistics in DT Midstream’s latest IR presentation. Nearly 10 Bcf/d in proposed pipeline projects could accommodate that growth over time. This all paints a rosy picture, but not one without a few short-term growing pains. Producers have dropped 18 rigs in the Haynesville over the last year, according to Baker Hughes data. This has helped dry gas production fall to the current 10 Bcf/d from a high of 12.5 Bc/d in February, according to Bloomberg. The dispute between Energy Transfer LP and Williams over right-of-way access is pushing some of that planned capacity back to the second half of 2025, which could further restrain short-term production. Some of that should come back this winter when Chesapeake Energy, Comstock Resources Inc. and others restore some curtailed production. In addition, the Haynesville is the only major production region to see a year/year increase in its drilled but uncompleted well count, so this would help restore production to its previous heights once the economics improve and short-term infrastructure snags are resolved.
NGI – Waha prices continue in the negative. Prices have been below zero for most of May, including reaching a low of negative $6.00 on May 6. The economics in the Permian Basin are driven by oil prices, and spot West Texas Intermediate prices have averaged a robust $80/bbl so far in 2024. The impact of efficiency gains from longer laterals and better completion techniques on gas production in the region should not be underestimated, which continue to enable publicly traded producers in the Permian to beat short-term guidance, even in the face of lower rig counts. Expectations are that the Permian would need another pipe in late 2026/early 2027 – no change there from a quarter ago. Matterhorn Express Pipeline would add 2.5 Bcf/d later this fall but that’s essentially it for a while, as no major new capacity is scheduled to come online thereafter. Assuming it takes two years to build a new pipeline out of the Permian, a new system would be needed in the second half of 2024 to meet those expectations.
Coterra Energy (CTRA) – Simultaneous fracturing, aka simulfracs, and trimulfracs are spearheading the efficiency gains in the Permian on the completion side and are leading to per well savings of $100,000-$300,000. Coterra Energy, Diamondback Energy, Matador Resources Co., Ovintiv Inc. and Chord Energy Corp. all sang the praises of this multi-well completion method on their various earnings calls. If simulfracs (and trimulfracs) are so amazing, then why not complete all wells that way? “That’s a great question,” said Blake Sirgo, senior vice president of Operations for Coterra. “And I think it’s something that gets missed sometimes in simulfrac is you really have to have an optimal pad with a lot of well heads on one pad to optimize the cost savings. There’s some times where you might simulfrac and save no money because a simulfrac crew is just basically two frack crews smashed together…The goal is not to simulfrac everything. The goal is to make the most economic wells, and so we’re only chasing it where it makes sense.”
ConocoPhillips (COP) – Several oil-focused producers touted their refrac opportunities in older and more mature basins such as the Eagle Ford and the Bakken shales, including ConocoPhillips, Devon Energy Corp., Marathon Oil Corp. and Silverbow Resources Inc. Refracs tend to increase production initially, but come back down to previous production levels quickly. EOG management said the refrac technology still has a “long way to go,” and the company favors drilling a new well or an infill well. Perhaps the step change in efficiency gains the industry has achieved over the last year could translate into more success from the latest round of refracs.
Pacific Gas & Electric Corp. (PG&E) – Canada is gearing up to fill two pipelines – the recent Trans Mountain (TMX) Pipeline expansion for crude oil, and Coastal GasLink to flow to the LNG Canada facility that is expected to begin commissioning later this year. Gas- and oil-focused rigs in Canada both stand at 57, up 11 and 18 from a year ago, respectively. With more gas staying at home in Canada, what might this mean for Northern California? Roughly 40% of gas on average enters California through Malin, according to NGI estimates. If PG&E takes less gas from Western Canada, it would need to pull more from the Rockies and Permian. Our guess is PG&E would look to source more gas from the Rockies, given the favorable spreads to PG&E Citygate from Opal vs. the SoCal Border. Perhaps this would help breathe some new life into Ruby Pipeline LLC, which Tallgrass bought out of bankruptcy in January 2023.
