S&P Global Ratings has cut its U.S. Henry Hub, Canadian AECO, and Dutch Title Transfer Facility (TTF) benchmark natural gas price assumptions for 2023 and 2024, primarily in response to lower demand for natural gas. Our 2025 long-term Henry Hub, AECO, and TTF natural gas price assumptions and our West Texas Intermediate (WTI) and Brent oil price assumptions are unchanged from those published Jan. 10, 2023.

We now use a TTF assumption of $22 per million British thermal units (mmBtu) for the rest of 2023--equivalent to almost €80 per megawatt hour (/MWh)--down from $30/mmBtu and of $20/mmBtu for 2024--down from $25/mmBtu. Our TTF price assumption for 2025 remains $20/mmBtu.

The TTF price revisions primarily reflect our view that the ongoing, and above-expectation, underlying drop in Europe's demand for natural gas is, for the most part, sustainable, even if economic growth picks up later in 2023. We estimate the demand decreased about 20% from August 2022 to February 2023. We expect much of the decrease, which was significant even after adjusting for normalized temperatures, is sustainable. Our revised assumptions also incorporate other demand, supply, and storage factors that we lay out in the sections below.

We now use a Henry Hub assumption of $3.5/mmBtu for the rest of 2023, down from $4.0/mmBtu and a Henry Hub assumption of $4.0/mmBtu for 2024, down from $4.5/mmBtu. Our Canadian Alberta Energy Company (AECO) assumptions are 2.25/mmBtu for the rest of 2023 and $2.5/mmBtu for 2024; down from $3.0/mmBtu in both years. The revisions reflect the precipitous decline in the prompt prices and futures curves, primarily due to unseasonable warm weather, in line with "How S&P Global Ratings Formulates, Uses, And Reviews Commodity Price Assumptions," published Sept. 28, 2018. In our financial forecasts for producers and consumers, we consider contracts and prices that are not linked to benchmarks, such as Henry Hub and TTF.

Underlying Decline In European Gas Demand Increasingly Appears Sustainable

The drop in underlying European gas demand has accelerated considerably since August. The EU-level agreement for an initial voluntary 15% (about 45 billion cubic meters [bcm]) cut in gas use for August 2022-March 2023 compared with the five-year average was exceeded by 19.3% up to this past January. Including the U.K., industrial demand was down a staggering 26% (from 121 bcm to 90 bcm) last year, while residential demand dropped a still significant 16%. Lower wholesale prices since October haven't at this stage propelled demand back up, partly because they remain about three times higher than pre-2020 averages.

We estimate 2%-3% of overall European gas demand will not return even if economies grow again and gas prices moderate. Within temperature-adjusted performance, there are distinct factors; including fuel switching, efficiency gains, reduced activity, and outright demand destruction as economies slow. Since November, local consumption--residential, commercial, and public administration—has remained significantly down across most of Europe despite cold snaps. This makes it more likely that the greater part of headline-demand reduction is here to stay. S&P Global Commodity Insights estimates that 8.4 bcm, or a quarter of the 2022 cut in industrial demand is essentially permanent reflecting improved efficiency, factory closures, and relocation of production (especially for newbuilds) to cheaper energy locations.

In addition, we believe other factors support our view of compressed 2023 and 2024 demand:

• Gas-to-power demand should contract significantly in 2023 (notably in the U.K. and Spain), after being surprisingly strong in 2022 despite more expensive gas-fired relative to coal-fired generation. In 2023, we expect Iberia's hydro power generation to recover to a large degree from depressed 2022 levels and France to confirm its nuclear ramp-up (we expect French nuclear generation to increase at least 20 terawatts (TWh) year on year, or 8%). Also, we expect a slight erosion of overall power demand. Overall, gas- and coal-fired power generation could abate by some 200 TWh, reducing the call on fossil fuel supply by about 35 bcm equivalent, or about 5% of total gas demand.
• The usage impact of all price hikes to final consumers did not take effect in 2022. We believe the benefits of most purchase hedges contracted before third-quarter 2021, when European gas prices started increasing significantly, have now elapsed. This means affected users will increasingly feel the weight of market prices. The latter are currently only about half the $37/mmBTU 2022 record average but still about 3x higher than during the two years to mid-2021 and higher than our expectations for U.S. prices (see chart 1).

However, we will continue to watch how European governments' affordability-protection measures stimulate demand, which will particularly depend on the pace that sharply lower wholesale prices since fall 2022 are channeled to end consumers.

TTF And Henry Hub Price and S&P Global Ratings' Price Assumption

Supply Concerns Have Diminished; New Flows Are Likely Insignificant For Next Winter

On the supply side, over October 2022–February 2023, Europe has significantly enhanced its supply infrastructure, notably relating to Central and Eastern Europe (CEE), and we have seen little negative news since the Nord Stream 1 pipeline's idling in late August. It is quite possible the slight reduction in Russian and Algerian pipe inflows is due to them becoming less competitive as wholesale prices have collapsed.

Russia's continuing lower supply volume meets under one-10th of average European demand, down from more than one-third in 2021. A Russian decision to fully cut remaining piped gas exports to Europe, or challenges with the maintenance of the Yamal liquefied natural gas (LNG) facility, are not part of our base case. Taken together, we see other supply sources to Europe as sufficiently reliable. These are primarily LNG and piped gas from Norway, Algeria, and Azerbaijan, while we expect the Dutch Groningen field to close within a year (possibly in October). The second-largest U.S. liquefaction facility, Freeport, which until June 8, 2022, supplied significant volumes (about 1 bcm monthly) to Europe, has partly resumed operations. We note that the risk of recovering Asian demand increasingly competing with Europe for LNG has still not materialized, amid moderate temperatures in North-East Asia. However, according to S&P Global Commodity Insights, China's gas demand growth could reach 6%, after negative 1.4% in 2022, which might be only partly met by increasing, cheap pipe supplies from Russia and Central Asia and gradually increasing domestic production. As such additional Chinese LNG demand will eat into the limited increase in global liquefaction in 2023 (just over 20 bcm per annum (bcmpa) and 2024 (about 10 bcmpa), we expect LNG supplies to Europe to only slightly grow in 2023, after the remarkable 60% (60bcm) growth in 2022 to 163 bcm, of which we understand at least one-quarter was spot or short term. Global, primarily U.S., liquefaction capacities will not start increasing again significantly until the 2025-2026 winter: for 2024 and 2025 we expect increases of just 14 bcm and 5 bcm, respectively; (see "Europe's LNG Focus Can Bring Pain As Well As Gain For Utilities," published Nov. 9, 2022 and "From Lots To Lack: Liquefied Natural Gas' Wild Ride," published Jan. 23, 2023).

Elsewhere, supply bottlenecks affecting traditionally Russia-supplied CEE should meaningfully ease in 2023. First, this quarter five floating and storage regasification units are scheduled to start commercial operations, all strategically placed in Germany (three, of which the last one, Brunsbuettel, received its first cargo Feb. 15), Finland, and Greece and with significant capacity that we estimate at 23.5 bcmpa, of which a substantial part is likely to be used already in 2023. We also understand that nearly 30 bcm of LNG remains afloat – several bcm above recent years - and a substantial portion could feed spot demand. Second, the 10 bcmpa Baltic pipe Norway-Poland is now fully used, optimizing Eastern Europe's access to Norwegian gas. We believe these improved supply connections soothe TTF dynamics significantly, contributing to our lower 2023 price assumption.

European Gas Stocks Will Start The Spring Filling Season At Very Healthy Levels

Overall European storage remained 63% full as of Feb. 21, 2023, which is about 20 percentage points more than the mean of recent years, equivalent to some 21 bcm. This is despite France reducing storage fullness significantly year to date to 49% (down 35 points compared with 13-18 for Germany, Italy, the Netherlands, and 20 for Europe as a whole). These stock levels reflect lower underlying demand; particularly mild weather this winter and aggressive and costly, national-government-supported replenishment during 2022. This increases certainty that Europe will start the 2023 refilling season with stocks of at least 50%, partly de-risking plans to reach the EU's 90% target by Oct. 1, 2023, ahead of winter.

The key challenge for 2023 remains to replenish stocks without the benefit of supplies provided by Gazprom over January-August 2022, which exceeded the current pace, and that we estimate at about 39 bcm. In our view, high storage levels in early 2023 bridge at least half of this gap. (Effectively, storage is about 33 bcm higher year on year. Even if gas use didn't decline year on year, Europe wouldn't need to purchase more gas than last spring and summer.) The other half is likely to be covered by the about 6%-7% additional underlying demand reduction, and notably the lesser gas-to-power demand. Therefore, we maintain our base case that--beyond price-driven demand destruction--Europe should not see significant administrative demand curtailments this winter or next, with that scenario now becoming remote rather than plausible.

Lower North American Demand and Prices Also Reflect Warmer Weather

Overall, S&P Global Ratings believes demand softness is the primary factor contributing to the natural gas price at the U.S. benchmark Henry Hub declining by 41%, or $2.26 per (mmBtu, in January 2023 compared with December 2022).

Warmer-than-average seasonal temperatures across the U.S. in January contributed to lower natural gas consumption for space heating. January 2023 was the warmest since 2006 and had 16% fewer heating degree days than the 10-year (2013–2022) average. Moreover, the U.S. Energy Information Administration (EIA) estimates that in January, consumption of natural gas in the residential and commercial sectors, combined, averaged 40.1 billion cubic feet (bcf) per day, which is 15% lower than the five-year (2018–2022) average for January. In addition, the outage at the Freeport LNG liquefied natural gas export facility has resulted in about 2.0 bcf per day less gas demand since mid-June 2022. Furthermore, increased domestic gas production in the U.S. lower 48 states contributed to incremental price softness, as supply outpaced demand. S&P Global Ratings believes these combined factors are contributing to current natural gas price weakness.

The EIA estimates that dry natural gas production in January 2023 averaged 11% more than the five-year average (at 100.2 bcf/d) and 5% more than January 2022. Relatively high production combined with less consumption has resulted in high storage levels, with net withdrawals from storage totaling 100 bcf for the week ending Feb. 10, compared with the five-year (2018–2022) average net withdrawals of 166 bcf and this past year's net withdrawals of 195 bcf during the same week. Working natural gas stocks totaled 2,266 bcf, which is 183 bcf (9%) more than the five-year average and 328 bcf (17%) more than last year at this time.

Given the sizeable natural gas exports leaving Canada for the U.S. lower 48, market factors affecting U.S. gas demand and prices will have a corresponding effect on the Canadian benchmark gas price, particularly for volumes unable to access markets linked to the Henry Hub price.

The lower 2023 and 2024 AECO price assumptions reflects S&P Global Ratings expectation of softening U.S. lower 48 demand for Canadian natural gas exports, which we believe will persist throughout 2023, but alleviate in 2024 in tandem with strengthening fundamentals for the Henry Hub benchmark price. Our long-term AECO price assumption maintains a US$0.50 per mmBtu basis differential relative to our Henry Hub long-term price assumption.

S&P Global Ratings believes the near-term factors adversely affecting North American natural gas prices will remain in effect through 2023, but abate in 2024, at which time market prices could respond to a more supportive outlook for demand fundamentals for natural gas.

Related Research

Global LNG research series:

• From Lots To Lack: Liquefied Natural Gas' Wild Ride, Jan. 23, 2023
• Japan's LNG Supply: On Solid Ground?, Jan. 5, 2023
• Contracting And Counterparties: Navigating North American LNG’s Choppy Cs, Feb. 1, 2023
• China Gas Sector Easing Into Lower Demand, Nov. 21, 2022
• Europe's LNG Focus Can Bring Pain As Well As Gain For Utilities, Nov. 9, 2022

Energy Transition research series:

• Energy Transition: Developing Markets Are Still Fueling Demand For Oil, July 20, 2022
• Energy Transition: Gas' Role Varies By Sector And Region Amid Security Of Supply Concerns, July 20, 2022
• Energy Transition: Renewables Remain The Cornerstone Of Future Power Generation, July 20, 2022

Other research:

• S&P Global Ratings Lowers 2023 European And U.S. Gas Price Assumptions On More Balanced Supply And Demand, Jan. 10, 2023
• SLIDES: Eastern European Utilities Handbook, Jan. 5, 2023
• SLIDES: Utilities Handbook 2022: Western Europe Regulated Gas, Nov. 4, 2022

Related Criteria:

• How S&P Global Ratings Formulates, Uses, And Reviews Commodity Price Assumptions, Sept. 28, 2018