North American natural gas prices dropped dramatically in 2023 as producers maintained robust production levels in no small part because of drilling efficiencies. At the same time, midstreamers touted the need for more gas egress capacity while the Biden administration’s LNG authorization pause threw a wrench in the outlook for some export capacity projects. Read what NGI analysts learned during 4Q2023 earnings season and how they view supply and demand trends moving forward.
Chesapeake Energy (CHK): Record U.S. dry gas production combined with what the National Oceanic and Atmospheric Administration is calling the warmest U.S. winter on record has left U.S. natural gas prices at historic lows. In fact, NGI’s Henry Hub spot market price fell to $1.24/MMBtu last week, which is the third lowest nominal price NGI has published since 1993, and the lowest on a real-dollar basis. Producers are responding in kind, no more so than CHK, which announced that it plans to lower overall 2024 production by roughly 20% from their 4Q2023 average, primarily by delaying TILs. Note this guidance does not include Southwestern Energy Co., so the overall CHK controlled cuts will likely end up being even more.
EQT Corp. (EQT): EQT, the largest U.S. natural gas producer, got into the act as well, announcing in early March that it began curtailing about 1 Bcf/d of production in late February “in response to the current low natural gas price environment resulting from warm winter weather and consequent elevated storage inventories.” All told, those cuts are expected to total between 30-40 Bcf through March. Why not more and for longer? Because we believe this production was likely ticketed to flow into Mountain Valley Pipeline LLC (MVP), which has been delayed by about two months into April. EQT is the anchor shipper on MVP with 1.29 Bcf/d of firm capacity. As of March 25, NGI’s Forward Look curves had Transco Zone 5 trading at a 35-cent premium to TETCO M2 Receipt for April 2024 – and an average premium of $1.215 for the next 12 months. That’s certainly an incentive to wait.
Equitrans Midstream Corp. (ETRN): And that delay on MVP could be even longer. CEO Diana Charletta noted on ETRN’s 4Q2023 earnings call that “while the majority of MVP construction is complete, the remaining construction includes some of the most difficult tasks on the project and could present further challenges.” Uh oh.
Comstock Resources Inc. (CRK): Even Comstock Resources, which has been one of the most aggressive publicly traded operators in terms of production growth, is dropping two rigs in the Haynesville.
We could keep going company by company, but instead, we rolled up 2024 producer guidance from 33 different publicly traded U.S. exploration and production (E&P) companies, which combined, account for 40% of total U.S. gas production. That group is guiding to a 0.9% year-over-year increase in production, which is noticeably lower than the 4% Wall Street consensus estimate we noted on a previous podcast in February. And if it weren’t for the Permian Basin, that aggregate guidance would be slightly negative versus 2023. Moreover, combined 2024 full-year production guidance is down 3.0% from average production during 4Q2023.
Enterprise Products Partners LP (EPD): Speaking of the Permian, EPD management said there is pent up demand for gas egress out of that region. “When you look at capacity right now, I think there is gas that's being held back in the basin. It’s waiting on compression and it’s waiting on processing capacity,” said Brent Secrest, chief commercial officer. Right they were. Secrest uttered that quote on Feb. 1, when NGI’s day-ahead Waha index stood at $1.55. Waha prices have been negative for much of March. Some relief is coming later this year, with MPLX’s 2.5 Bcf/d Matterhorn Express project expected to be in service 3Q24, and Kinder Morgan Inc.’s (KMI) 80 MMcf/d expansion of NGPL in the Permian coming in November. But more will be needed.
EPD: Forecast during 4Q2023 earnings conference that crude oil production in the Permian will end up rising 2.5 million b/d from 2022-2030, with a concomitant 8.8 Bcf/d increase in wet natural gas that it deems will require roughly 50 new processing plants. Clearly, there isn’t enough natural gas egress to handle that growth. So, by when might the region need another new pipeline, you ask?
MPLX LP (MPLX): Management is estimating it may be needed between late 2026 and early 2027, which is right in line with what KMI said, and within the “next two and a half years” time frame set by Energy Transfer LP (ET). Perhaps the recent swath of negative Waha prices will change things, but there doesn’t seem to be much urgency to progress new egress out of the Permian at this time.
KMI: Executives noted they are advancing discussions with shippers to expand their Gulf Coast Express pipeline, but they are “not quite there yet.”
ET: Moreover, with respect to the proposed Warrior Pipeline project, Co-CEO Mackie McCrae exclaimed “we'd love to say we're at FID, we're sold out for 10-year demand charge, we're ready to go, but that's not where we're at. We have sold about 25% of our goal. We're in negotiations with about 1.6 Bcf, 1.7 Bcf of additional customers. All of them are looking for, or a lot of them are looking for different places to take the gas.” The ultimate direction of those flows could be shaped in large part by liquefied natural gas exports, which of course face some uncertainty in the face of President Biden’s pause in issuing non-FTA export permits. McCrae even noted one potential customer has been looking at Warrior to feed one of those affected projects.
Midstream companies have the advantage of being able to coordinate with their customers, so the fact that three major midstream companies independently derived the same forecast is telling. It’s also something we believe the market expects will get done. NGI’s current Waha Forward Look curve shows an average basis differential of minus $1.05 for the rest of 2024, but then averages of minus 72 cents for 2025, minus 75 cents for 2026, minus 70 cents for 2027 and minus 70 cents for 2028. That bump in basis from 2024 to 2025 can be explained by Matterhorn, but the relative stability of Waha basis thereafter suggests Permian gas egress will stay ahead of growth from the area. If only things were that straight forward in real life. Things can and will change, especially since natural gas production in the Permian is largely tied to global crude oil prices.
MPLX: The weekly rig count in the Utica Shale has ranged between 10-15 rigs since 2022, which actually makes considering it is one of the steadiest regions in the United States. This dedicated activity, combined with efficiency gains, is translating to activity gains in the area. EOG counts the Utica as one of its premium plays, and MPLX management noted they see “a lot of good tailwinds with new producers moving into the Utica.” Longer laterals in the Utica may be having an impact as well. The average capacity utilization of MPLX’s Utica processing plants continues to trend higher, with a relatively big step change up from 42% in 3Q23 to 49% in Q4. More momentum is likely on the way, as MPLX notes new state land auctions are expected this year, and ETRN’s Ohio Valley Connector expansion project should be in service 2Q24. That will add ~350 MMcf/d of capacity bringing the total to 1.2 Bcf/d to Clarington and can backhaul to reach MVP. For now, we believe higher crude and liquids prices are driving this activity, but eventually, it could be the result of Appalachia operators being forced to move into the Utica because of prime inventory exhaustion in the Marcellus.
EOG Resources Inc. (EOG): EOG sure seems to be developing its Dorado natural gas play in South Texas to serve as dedicated supply for LNG exports. The company signed one of the first (if not the first) Integrated Production Management (IPM) deals with Cheniere Energy Inc. (LNG), and in total, has nearly 1 Bcf/d of production tied to LNG export pricing. To help accommodate this, the company is building a 36-inch diameter pipeline named Verde to ship Dorado production to the Agua Dulce area. Phase 1 of Verde flows to Freer, TX and was placed into service last year, while the remaining portion to Agua Dulce should be operational during the second half of 2024. Management also noted they will have a “direct connection” to Corpus Christi LNG.
LNG: Turning to the demand side of the equation, Cheniere noted it expects its 2024 LNG production to be 45 million tons, including planned maintenance at both Sabine Pass and Corpus Cristi. That is roughly flat year-over-year.
ET: There was a clear uptick in discussion about the Midcontinent during 4Q2023 earnings calls. ET noted on its 4Q call that the Midcontinent is stable, while Oneok Inc. (OKE) was a bit more specific, indicating it expects a 3% increase in processing volumes in that region this year.
Williams (WMB): Longer-term, WMB cited Wood Mackenzie forecasts calling for natural gas in the Midcontinent to grow at a minus-1% CAGR through 2033. As Coterra Energy Inc. (CTRA) mentioned, Anadarko Basin geology is more complex than that in the Permian. It’s deeper with higher pressure so the drilling can be more difficult, and that obviously impacts relative economics. Marathon Oil Corp. (MRO) made a good point as well, noting that Oklahoma in general is a combination oil and gas play, but during high oil prices, more black oil regions such as the Permian, as well as the Bakken and Eagle Ford shales are likely to attract more drilling capital. From an LNG export standpoint, not accelerating production in the Midcontinent is a good thing, since the area (like the aforementioned Dorado play) could serve as a form of long-term “spinning reserves” that help backstop feed gas supply.
WMB: Now onto the Haynesville Shale, where the number of drilling rigs essentially has fallen by half since late 2022 and where future natural gas infrastructure projects are getting delayed. Certainly part of that is the result of the Biden non-free trade agreement (FTA) export license pause. But the main issue is a brewing legal dispute. In fact, I’ve been covering the U.S. natural gas midstream as an analyst for nearly 20 years now, and I cannot remember a time where a public dispute between two parties was being waged in the media. At issue is ET is denying would-be third-party operators to expand or build new pipelines through its rights of way in Louisiana. WMB claims anti-competitive behavior, ET contends it needs time to ensure new projects won’t undermine the integrity of its pipes. We aren’t here to play referee or to choose sides, but we will say this will cause some pipeline projects that serve the Haynesville to be delayed. For example, WMB is now seeking to reroute its proposed Louisiana Energy Gateway pipeline around ET’s Louisiana pipes, which has pushed the expected in-service time for that project from late 2024 to the second half of 2025. Other projects could be impacted as well, such as Momentum Midstream’s NG3 project that will deliver 1.7 Bcf/d into the emerging Gillis Hub in Louisiana. That project was supposed to be in service this year, but we believe that timeline is now very much in doubt. Overall, EPD management said they don't see “things going to hell in a handbasket,” and the current weakness in Gulf Coast gas prices along with the Biden permit pause buys a bit of time before this capacity is fully needed.
Still, we can’t help but think this is another development that may potentially hurt the long-term attractiveness of future U.S. LNG projects. Delays in feed gas projects in the Haynesville, the dispute between Venture Global and its shippers over Calcasieu Pass LNG, Biden’s non-FTA LNG export permit pause, issues at the Panama Canal and rising interest rates in the United States: none of these things are positioning U.S. LNG in the most favorable light, in my view.
Halliburton Co. (HAL): Enter Sandman. Sand is obviously a key component of the well completion processes, but it is taking on added importance, both short- and long-term. In 2024, as HAL management noted, production will “be a matter of how much incremental sand gets pumped to overcome what is clearly going to be a decline rate” that is the result of the massive 150-plus fall-off in U.S. drilling rigs since peaking in late 2022.
Liberty Energy Inc. (LBRT): Bigger picture, CEO Chris Wright said that frack intensity “used to move depending on sand prices. Sand prices are high, frack intensity will pull back a little bit. Sand prices are low, frac intensity will grow. But there's another factor, which is reservoir and rock quality.” Simply put, longer laterals and the migration to lesser acreage are driving sand intensity.
The data bear this out. According to the U.S. Geological Survey, “The most important driving force in the industrial sand and gravel industry [for calendar year 2023] remained the production and sale of frac sand.” So while not all this activity is related to fracking, oil and gas production is the main driver.
Patterson-UTI Energy Inc. (PTEN): New layers and categories are forming throughout the oil services chain. The top end rigs aren’t just super spec rigs anymore, they are now Tier 1 super spec rigs. PTEN noted their Tier 1 drilling rigs can deliver 35% more lateral footage on average per year versus a standard super spec rig. Deferred turned in-line wells are adding a final layer of the well completion process after the drilled but uncompleted well count. E-fracs are the class of the completion fleets. Trimulfracs are a step-change above simulfrac – and per Matador Resources Co. (MTDR) can save an additional $100,000/well. The industry now is testing 4-mile laterals instead of the previous max of 3-milers. As a college professor of mine once said, and I paraphrase, “you can tell industries are dying when innovation within it dries up.” Innovation within the oil & gas space remains alive and well.
Natural Gas Intelligence (NGI): We peg the overall “consensus” estimate for oil field service price declines to average between 5-10% for 2024. No doubt this will be a bit of a relief to E&P companies who are about to become cash taxpayers for the first time in, well ever for quite a few, thanks to the 15% alternative minimum tax and the exhaustion of net operating loss tax credits.
NGI: Let’s end with a quick discussion on electricity demand, which NGI recently covered. Data centers are becoming a hot topic among investors, so much so that we predict this will become what journalists call an “above the fold” topic during 1Q2024 calls. Last year, there were still pundits calling for a decline in U.S. gas-fired generation going forward because of the increase in renewables. Now, electricity is being called a growth engine for gas. In its December 2023 report titled “The Era of Flat Power Demand is Over,” GridStrategies noted that “over the past year, grid planners nearly doubled the five-year load growth forecast….The nationwide forecast of electricity demand shot up from 2.6% to 4.7% growth over the next five years, as reflected in 2023 FERC filings.” The drivers behind that? “Investment in new manufacturing, industrial and data center facilities.” No doubt NGI’s Thought Leaders will have plenty more to say on this subject in the months ahead.
