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S&P Global Ratings' Oil And Gas Price Assumptions Are Unchanged

S&P Global Ratings has reviewed its hydrocarbon price decks and left unchanged its Brent and West Texas Intermediate (WTI) oil price assumptions and Henry Hub, Canadian AECO, and Dutch Title Transfer Facility (TTF) benchmark natural gas price assumptions for the remainder of 2023 and subsequent years. Our last revisions were in mid-2023, ("S&P Global Ratings Lowers Hydrocarbon Price Assumptions On Moderate Demand", published on June 22, 2023).

Table 1

S&P Global Ratings' oil and natural gas price assumptions
--Unchanged prices--
WTI ($/bbl) Brent ($/bbl) Henry Hub ($/mmBtu) AECO ($/mmBtu) TTF ($/mmBtu)
Remainder of 2023 80 85 2.5 1.75 14
2024 80 85 3 2.25 14
2025 80 85 3.5 2.75 12
2026 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 Btu. Note: Prices are rounded to the nearest $5/bbl and 25 cents/mmBtu. Source: S&P Global Ratings.

To calibrate the potential use of cash flow volatility adjustments and resilience of corporate ratings and financial risk profiles, we maintain a ratings midcycle price reference point for our analysis of oil and gas producers. These prices are also unchanged: $50/$55 per barrel (bbl) of oil equivalent for both WTI and Brent and $2.75/$2.25/$8 per million Btu (mmBtu) for natural gas prices as determined by Henry Hub, Alberta Energy Co. (AECO), and TTF.

We typically publish our price decks at least every quarter. We may also publish when there are significant changes to S&P Commodity Insights' (SPCI) forecasts or when the hydrocarbon futures curves persistently deviate more than 20% from our published decks. S&P Global Ratings' corporate analysts continue to use the first three years in their financial modelling, analysis, and determining ratings on exploration and production companies. For further information, see the revised version of "Credit FAQ: How S&P Global Ratings Formulates, Uses, And Reviews Commodity Price Assumptions".

Supply Cuts Influence Oil Prices

Current and expected annual demand growth is likely to remain positive, albeit moderating in 2024 and 2025, after the recovery from COVID-19 restrictions. SPCI and the International Energy Agency have world oil demand growth forecasts of 2.2 million bbl per day (b/d) in 2023. This compares with an annual average of 1.6 million b/d between 2010 and 2019. Economic growth in major oil-consuming countries looks sufficient to support this demand despite efficiency and decarbonization measures across transportation modes. In particular, concerns about the strength of the Chinese economy have not materially affected oil demand growth there as freight and travel rebounded in contrast to property and some industrial activity.

The Saudi Arabian and Russian supply cuts in July 2023 have significantly influenced oil prices. With Saudi Arabia now producing 9 million b/d and Russian seaborne exports down 800,000 b/d in the summer compared with the spring, oil fundamentals have improved. We assume the Saudi restraint broadly continues into 2024. SPCI notes the cuts are economically rational as higher oil revenues are generated from 9 million b/d at $90/bbl than 10 million b/d at $70/bbl. Nonetheless, overall global oil production is likely to increase about 1.5 million b/d in 2023 due to increased flow from the U.S., Brazil, and Iran in particular. Indeed, non-OPEC+ supply is running at record highs. The spare OPEC+ production capacity of about 4 million b/d is not weighing on prices.

Reported inventory is being drawn down, likely continuing for the remainder of 2023 given the anticipated supply-demand balance. Stocks of both crude and products remain modest despite operational refineries running at or near capacity. This dynamic supports prices, although it may reverse in early 2024 on seasonal demand declines.

U.S. Natural Gas Prices Reflect Oversupply And High Inventory

Following a steady retreat since last August, when the price of Henry Hub natural gas was well over $9/mmBtu, prices have rebounded after establishing a floor. Concerns about the economy, the 2 billion cubic feet per day outage at the Freeport liquefied natural gas (LNG) facility due to a fire, unseasonable weather patterns, and record U.S. production contributed to the decline. The stubbornly high natural gas rig count has begun to respond with gas rigs declining by 45 from last year to approximately 121 rigs. Also, prices have rebounded from lows largely because of record electricity demand during the summer months, the pull from Freeport coming back online, increasing LNG demand, and record exports into Mexico. We believe the combined demand pull and lower rig count established a pricing floor. Still, prices remain relatively weak, reflecting associated gas production from the Permian Basin representing 22% of overall U.S. production last year. This associated gas production does not depend on the Henry Hub price; rather, oil prices will dictate what associated gas is produced. We expect oil prices to remain favorable for Permian drilling programs.

It's difficult to be sanguine about the near-term prospects for natural gas. There is no near-term catalyst that will alter the supply-demand balance to favor higher prices. Also, inventory remains 8% higher than the five-year average and 17% higher than a year ago, which doesn't bode well for prices as we approach the end of the winter restocking season.

Chart 1


Without a near-term catalyst, natural gas prices will likely exhibit their typical seasonal pattern, but we expect the average price of Henry Hub to be range bound. The market is waiting for the significant buildout of the U.S. and Mexican LNG liquefaction capacity at the end of 2025 through 2027 to begin to assert itself on the demand side.

Canadian AECO Also Oversupplied

The Canadian gas market was well oversupplied at the end of the last heating season in March. It was similar to the U.S., with rising production and an unseasonably warm winter leading to significant oversupply conditions.

Gas market balances in Canada would have been worse if not for wildfires in Alberta and British Columbia. Their meaningful impact on Western Canada production in May and June helped alleviate what would have been a severe oversupply. It looks like the market found a floor largely from the supply side of the equation. Nevertheless, Canadian gas directed rig counts have remained relatively consistent and inventory at five-year highs, which will weigh meaningfully on prices for the winter.

Chart 2


Much like the market for U.S. Henry Hub, there is no near-term catalyst. However, LNG facilities are being built in Canada that could structurally increase demand and help moderate the oversupply. In particular, we now expect the LNG Canada Phase 1 to start in July 2025, and a smaller Woodfibre LNG facility is scheduled to start in August 2027. We expect total Canadian feed-gas demand to increase to 2.2 billion cubic feet per day in 2028.

TTF Up In Recent Months, But Unlikely To Regain 2022 Highs

Our TTF assumptions are elevated through 2025 because the European gas supply balance remains somewhat fragile and dependent on factors beyond Europe's control. Behind this is the assumption that the remaining Russian piped gas of 2 billion cubic meters per month, covering approximately 5% of Europe's needs, will continue and that Russian LNG continues apace even if Arctic-LNG's 9 billion cubic meters a year train 1 wasn't commissioned successfully and on time. Nevertheless, we estimate average TTF prices should remain significantly lower than they were up to February 2023.

The European Union's natural gas inventory is 95% of capacity, eight weeks ahead of initial expectations and with a broad distribution (only Latvia remains below 90%). This is contrary to 2022, when Central and Eastern Europe were underfilled. Moreover, Europe's demand for natural gas seems set to stabilize for now at one-fifth below its 2021 level. A rebound is unlikely before early next year given our view of European GDP growth. Yet, for ongoing supply, the EU will still compete with Asian LNG demand.

Beyond this winter, Europe's demand hinges notably on further heat pump deployment (after 2022's record) to reduce residential gas heating demand and continued sustained investments in renewable power generation to replace gas- and coal-fired sources. The effect up to August was muted by weather conditions, but the EU reduced gas burn 19% year on year. Lastly, we could see lower prices if increases in global LNG liquefaction capacity outstrip demand, notably from China and emerging Asia. Such excess supply might push prices into the low-single digits.

Related Research

This report does not constitute a rating action.

Primary Credit Analysts:Simon Redmond, London + 44 20 7176 3683;
Thomas A Watters, New York + 1 (212) 438 7818;
Secondary Contact:Emmanuel Dubois-Pelerin, Paris + 33 14 420 6673;

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