Goldman: «Холодный январь» и «рекордный спрос на СПГ» повышают риск роста цен

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Zdjęcie: goldman:-„cold-january”-&-„record-lng-demand”-drive-upside-risk-in-natty-prices

Goldman: „Cold January” & „Record LNG Demand” Drive Upside Risk In Natty Prices

Ben Noll, a meteorologist at New Zealand’s National Institute of Water & Atmospheric Research, posted on X that the Lower 48 is bracing for another „major Arctic blast” in ten days.

A major Arctic blast could cover most of the United States with frigid conditions around Jan. 20

Watch: pic.twitter.com/8NcSVx3fqJ

— Ben Noll (@BenNollWeather) January 10, 2025

„Sub-zero temperatures are forecast in more than 35 states over the next two weeks,” Noll said.

Data compiled by Bloomberg shows that the Lower 48 average temperatures by January 20 could be around 20F, well below the 30-10-5 year averages, which trend in the high 30Fs.

Heating degree days, a measurement of how cold the temperature is and how much energy is needed to heat a building, for the Lower 48, is expected to soar in the latter parts of the month. This is an indication energy demand will jump even higher.

The continued cold blast and another round of frigid temperatures will likely drive up heating demand and support higher NatGas prices as supplies tighten in the intermediate timeframe, according to Goldman Sachs co-head of Global Commodities Research Samantha Dart.

Dart noted how an exceptionally cold January and record-high LNG exports tightened supplies, forcing her to revise her Henry Hub summer 2025 $2.90/mmBtu forecast to $3.30/mmBtu. The prospect of rising LNG exports leaves the analyst’s 2026 target of $4/mmBtu „skewed to the upside.”

She provided more color into the NatGas supply-demand dynamics and the 2025 and 2026 price targets:

Exceptional cold poses significant upside risk to US gas demand this month. January is currently forecast to be 1.3 standard deviations colder than average in the US, with a potential to lift US gas demand this month by 6.1 Bcf/d above what we would have expected under average weather. Together with production freeze-offs (1.2 Bcf/d month to date[1]) and strong LNG feedgas demand, and net of softening surprises from Canadian imports and exports to Mexico, US January gas balances might be 6.4 Bcf/d tighter than we expected should current cold forecasts realize, posing upside risk to our $2.90/mmBtu Summer 2025 Henry Hub forecast to $3.30/mmBtu.
Record-high US gas demand for LNG exports also tightening the balance. We note that US feedgas into LNG export facilities has reached a record high 14.5 Bcf/d weekly average (vs GSe of 14 Bcf/d for January), with Plaquemines having now loaded its first commissioning cargoes. With Cheniere’s Corpus Christi Stage 3 expansion starting this year, we expect US total feedgas into LNG export facilities to average nearly 15 Bcf/d this year (+2.3 Bcf/d yoy), reaching 16.7 Bcf/d by year end.
Net impact on storage reduces 2025 congestion risks… While this tighter-than-expected January, if confirmed, would represent a near-200 Bcf impact on storage, the net impact on our end-Oct25 storage expectation is significantly moderated by the hit from the recent sharp rally in US gas prices to power demand for gas. On net, should the current extended cold forecast for January realize, this would take our end-Oct25 storage expectation to 51 Bcf below our Nov24 estimate, at 4.05 Tcf.
…implying lower C2G likely required this year vs our previous expectations. While such levels are still relatively high, they suggest the market would require less coal-to-gas (C2G) substitution than we currently embed in our balances to keep storage away from congestion levels. This means Sum25 Henry Hub could potentially balance the market closer to $3.30/mmBtu (vs our current $2.90/mmBtu summer price view), which we estimate would be sufficiently below current market prices to incentivize incremental C2G switching to take end-Oct25 storage under 4 Tcf.
Tightening risks partly moderated by upside risk to associated gas production… These tighter risks to our balances are at least partly moderated by softening risks to our US associated gas production assumptions. At our Energy, Clean Tech and Utilities Conference held in Miami this week, Permian producers and midstream companies indicated expectations of regional oil and associated gas volume growth similar to what we saw in 2024. This would imply up to 0.4 Bcf/d of upside risk to the 22.2 Bcf/d of Permian associated gas production we expect to see on average in 2025, which is ~2 Bcf/d up from 2024.
…while we’ve gained increased confidence in our flat Haynesville volumes expectation. At the conference, Haynesville producers confirmed our view that regional gas production is unlikely to grow this year with Cal25 Henry Hub prices near $3.50/mmBtu. Producers indicated that the turning-in-line of new wells and completion of drilled but uncompleted (DUC) wells would likely offset natural basin declines keeping overall production levels largely flat sequentially.
Upside risk to our bullish $4/mmBtu 2026 Henry Hub forecast. Importantly, given elevated gas price volatility and balance risks, producers indicated the need of a sustained gas price buffer on top of estimated marginal costs of production for the basin to shift into growth mode. Specifically, they’ve indicated that $4-$5/mmBtu prices will likely be required to incentivize growth, above our estimated $3.50 (core)/$3.75-$4.00 (non-core) Haynesville marginal costs. Given our view that significant increases in US LNG exports will require renewed production growth in the Haynesville in 2026, we believe this leaves risks to our $4/mmBtu 2026 Henry Hub price forecast skewed to the upside.

NatGas prices are set to test the $4/mmBtu level after clearing the $3/mmBtu level in late November. Prices have been stuck in a multi-year lateral after plunging from nearly $10/mmBtu in mid-2022.