S&P Global Ratings has reviewed its hydrocarbon price deck and has lowered its Henry Hub, Canadian Alberta Energy Co. (AECO), and Dutch Title Transfer Facility (TTF) natural gas price assumptions for the remainder of 2024 and 2025 (see table). We maintain our Brent and West Texas Intermediate (WTI) oil price assumptions for the remainder of 2024 and subsequent years. Additionally, we have added 2027 annual assumptions for these hydrocarbons.
Table 1
| S&P Global Ratings' oil and natural gas price assumptions | ||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| New prices | Old prices | |||||||||||||||||||||
| WTI ($/bbl) | Brent ($/bbl) | Henry Hub ($/mmBtu) | AECO ($/mmBtu) | TTF ($/mmBtu) | WTI ($/bbl) | Brent ($/bbl) | Henry Hub ($/mmBtu) | AECO ($/mmBtu) | TTF ($/mmBtu) | |||||||||||||
| Remainder of 2024 | 80 | 85 | 2.5 | 1.75 | 10 | 80 | 85 | 3.25 | 2.25 | 14 | ||||||||||||
| 2025 | 80 | 85 | 3.5 | 2.5 | 10 | 80 | 85 | 4 | 2.75 | 12 | ||||||||||||
| 2026 | 80 | 85 | 4.25 | 3.25 | 10 | 80 | 85 | 4.25 | 3.25 | 10 | ||||||||||||
| 2027 and beyond | 80 | 85 | 4.25 | 3.25 | 10 | |||||||||||||||||
| bbl--Barrel. WTI--West Texas Intermediate. HH--Henry Hub. TTF--Title Transfer Facility. AECO--Alberta Energy Co. mmBtu--Million British thermal units. Note: Prices are rounded to the nearest $5/bbl and 25 cents/mmBtu. Source: S&P Global Ratings. | ||||||||||||||||||||||
The decline in our gas price deck in 2024 is somewhat meaningful, though we anticipate limited rating impact. We note that many of the producers have focused on reducing debt over the past several years and some producers benefit from hedges.
To calibrate the potential use of cash flow volatility adjustments and the resilience of the financial risk profile and ratings, we maintain a ratings midcycle price reference point to be used in our analysis of oil and gas producers. These midcycle prices are unchanged at $50/$55 per barrel of oil equivalent for both WTI and Brent and $2.75/$2.25/$8 per metric million British thermal units (mmBtu) for natural gas prices as determined by Henry Hub, AECO, and the TTF.
We typically publish our price decks at least every quarter. We may also publish when there are significant changes to S&P Global Ratings Commodity Insights' forecasts or when the hydrocarbon futures curves persistently deviate by more than 20% from our published decks. Our corporate analysts continue to use the first three years in their modelling, analysis, and determining of ratings for exploration and production companies. For further information, see, "Credit FAQ: How S&P Global Ratings Formulates, Uses, And Reviews Commodity Price Assumptions," published April 20, 2023.
Natural Gas Prices Reflect Exceptionally High Inventory Levels
Chart 1
Henry Hub
The price of Henry Hub has plummeted, attributed to a warm winter because of the El Niño and record U.S. natural gas production in 2023. As of Feb. 9, 2024, working gas storage in the U.S. was at 2,535 billion cubic feet (Bcf), the highest it has been for this time of the year since 2016. Storage levels are 16% higher than the five-year average and 11% higher than the same period in 2023.
Chart 2
According to the U.S. Energy Information Administration thus far in the withdrawal season (November through March) the average rate of withdrawals from storage is 12% lower than the five-year average. If the rate of withdrawals from storage matched the five-year average of 10.9 Bcf per day for the remainder of the withdrawal season, the total inventory on March 31, 2024 would still be approximately 20% higher than the five-year average for the end of the withdrawal season.
We consider it likely that producers will accordingly lower natural gas-directed rigs. However, the corresponding decline in production will take about four to six months which, coupled with inventory levels that will likely remain high exiting the heating season, will subdue any meaningful movement in natural gas prices. Much of the U.S. gas production is from associated gas from oil production, particularly from the Permian Basin. With WTI rising over the last few weeks, increased oil production could boost gas supplies. Producers are demonstrating efficiency and productivity gains, and some may utilize drilled but uncompleted wells to garner higher netbacks--which could quickly increase production and further pressure natural gas prices.
AECO
Like Henry Hub, warmer-than-expected weather conditions have created significant volatility in AECO prices. Canadian natural gas production reached an all-time high in 2023, resulting in record storage levels in western Canada to start the heating season. One of the warmest Canadian winters in the last century significantly reduced space heating demand and kept storage levels extraordinarily elevated. Canadian gas-directed rigs have simultaneously remained stubbornly high, because producers are holding production flat in anticipation of the startup of Canadian liquefied natural gas (LNG) export facilities in early 2025. The combination of these factors has weighed on AECO prices, with prices dropping steeply over the recent weeks, currently trading at about US$1.30 per mmBtu.
Chart 3
We forecast that storage inventories will remain above the five-year average into 2025 even if weather patterns and temperatures return to normal levels later in 2024. This is because Canada's working gas storage levels are at or near all-time highs for this time of year and production is expected to remain flat.
Chart 4
The start of LNG Canada Phase 1 in early 2025 (with an export capacity of about 2 Bcf per day) will be positive for domestic demand. It is likely that project sponsors will ramp up production to meet most of this new demand, using either their own acreage or partners. As a result, we anticipate high-single-digit yearly growth in Canadian natural gas production in 2025. We expect the startup of domestic LNG exports to provide less upward price support to the AECO benchmark in 2025 than previously anticipated. This is because of the possibility of elevated storage levels persisting into 2025, coupled with a higher Canadian gas production forecast.
TTF
We have lowered our TTF assumptions for 2024 and 2025. This reflects subdued European demand based on a warm winter and a weak economic recovery. It also considers soft global LNG prices, because supply remains abundant and is set to grow from next winter, and Asia-Pacific's demand recovery is well priced in. We anticipate demand moderation, at a quarter below 2019 levels, as households and industries barely increase consumption and gas-to-power use reduces sharply. Subdued power consumption, gas and coal-fired generation being displaced by growth of about 10% in renewables, and recovering hydro and French nuclear generation support this view.
The EU's underground natural gas inventory levels are high for this time of the year, at 65% of capacity as of Feb. 17, 2024. With only about six weeks of significant potential withdrawals left, we forecast a very healthy winter exit level of about or above 50%.
Physical constraints on delivering LNG to continental Europe, and specifically to Central and Eastern Europe, are no longer material. Half a dozen new floating regasification units send gas to the grid, part of a 75 billion cubic meters per year regasification capacity increase over 2022-2024, which focuses on the regions previously most dependent on Russia (such as Italy and Central and Eastern Europe).
This report does not constitute a rating action.
| Primary Credit Analyst: | Emmanuel Dubois-Pelerin, Paris + 33 14 420 6673; emmanuel.dubois-pelerin@spglobal.com |
| Secondary Contacts: | Thomas A Watters, New York + 1 (212) 438 7818; thomas.watters@spglobal.com |
| Simon Redmond, London + 44 20 7176 3683; simon.redmond@spglobal.com | |
| Laura Collins, Toronto +1 4165072575; laura.collins1@spglobal.com |
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