S&P Global Ratings has reviewed its hydrocarbon price decks and lowered its West Texas Intermediate (WTI) and Brent oil price assumptions by $5 per barrel (bbl) for 2025-2028. In addition, we raised our Henry Hub and Dutch Title Transfer(TTF) natural gas price assumptions for 2025 and 2026. We also lowered our Alberta Energy Co.(AECO) natural gas price assumptions by $.50/million btu for 2025-2028 (see table). We do not anticipate any direct rating actions as a result of the changes to our price deck. Upstream balance sheets remain in a healthy position given the focus on paying down debt and generating cash over the past few years.

To calibrate the potential use of cash flow volatility adjustments and the 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 of oil equivalent for both WTI and Brent and $2.75/$2.25/$8 per million Btu (Btu) for natural gas prices as determined by Henry Hub, AECO, and TTF respectively.

We typically publish our price decks at least every quarter. We may also publish when there are significant changes to S&P Global 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," published April 20, 2023.

Revisions To Oil Price Assumptions

The revision of the oil price deck reflects weaker underlying fundamentals and the decision by OPEC+ to increase oil supply. Following the Biden Administration's sanctions against Russian oil back on Jan. 10, Brent peaked at $82/bbl. The Biden Administration enacted a broad range of sanctions against Russian oil and gas production that included producers, tankers, insurance companies, traders, and ports. In addition, on Feb. 24, the EU and U.K. announced sanctions on three major Russian oil ports and numerous "dark" tankers, while the U.S. imposed new sanctions on the Iranian Oil Terminals Co. (not rated), 13 tankers, and several entities.

SPCI assumes these sanctions on Russian production are broadly neutral for crude oil prices, largely because market participants have adapted to the Jan. 10 U.S. sanctions, finding ways to deliver sanctioned barrels through the increase use of nonsanctioned vessels, offsetting the reduced volumes from sanctioned vessels. According to SPCI at Sea Data, Russian crude exports via nonsanctioned vessels increased by over 500,000 barrels per day (bbl/d) over the month of January.

After trading more than $80/bbl, Brent has been unable to maintain those levels as market fundamentals and concerns about global demand and tariffs, reasserted themselves. Moreover, in a somewhat surprising move, OPEC+ announced on March 3 that starting in April, it would begin to reintroduce the 2.2 million bbl/d of production through September of 2026 beginning with a 138,000/bbl per month increase in April. OPEC+ announced it will monitor market fundamentals and adjust as warranted. In our previous assumptions, we incorporated the tariffs, global demand risk, and lack of evident Russian supply disruptions, and believed OPEC+ might, yet again, delay reintroducing barrels to the market.

Chart 1

Since last June, OPEC+ has delayed reintroducing 2.2 million bbl/d of production three times, with the last announcement in December when it said it would delay bringing back production until April.

Potential sanctions by the Trump Administration on Iranian oil production and the ongoing conflict between Russia and Ukraine remain a wildcard and could impact OPEC's decision to add more or lessen production from their current 5.5 million barrels of surplus capacity.

Before sanctions were enacted and OPEC's decision to return barrels to the market, oil markets were under pressure. After two years of demand growth outstripping supply, we expected oil markets to shift into oversupply conditions for the next two years. Growth from non-OPEC production, particularly from North America, Brazil, and Guyana was likely to outstrip slowing demand particularly from China as it rapidly moves toward an electric vehicle (EV) society and converts its diesel truck fleet engines to compressed natural gas. And although its uncertain how long the recent implementation of tariffs will remain in effect, a prolonged period of tariffs could further lower global demand for oil. Global oil inventories remain at, or near, the bottom of the five-year average; however, they will likely increase over the next two years.

Graphic 1 

Revisions To Natural Gas Price Assumptions

The Henry Hub has entered a period of tighter fundamentals brought on by a cold winter and producers laying down rigs and lowering production. Indeed, buoyed by exceptionally strong demand of 144 billion cubic feet per day (cf/d; 17.6 billion cf/d higher than the five-year average) in January due to the cold weather, the storage surplus that has existed over the past two years and kept a lid on prices has now been eliminated.

Graphic 2 

In January, inventories finally flipped to a deficit compared to the five-year average and despite elevated supply levels, they are on track to finish the season at approximately 1.7 trillion cf, over 150 billion cf below the five-year average. Needless to say, Henry Hub prices have responded accordingly (see chart 2).

Chart 2

It would appear the U.S. lower 48 gas inventories may be entering a prolonged period of tightness as SPCI is projecting liquefied natural gas (LNG) feedgas demand will increase by more than 6 billion cf/d from October of last year through March 2026, which will keep the storage levels below the five-year averages and keep gas prices elevated. We assume production will continue to lag demand given the six-month cycle lag between drilling and production and as producers focus on generating cash flow and returning value to shareholders.

We remain sanguine on the long-term lower 48 prospects for natural gas prices as SPCI forecasts a 95% increase or a 12.5 billion cf/d increase in gas demand related to LNG feedgas demand in 2029 to 25.7 billion cf/d.

Graphic 3 

We believe that demand increases will be met by increased production in the Permian in the form of associated gas and from the Haynesville given its close proximity to the boom in LNG buildout along the Gulf Coast. Haynesville production increases will be supported by 3.5 billion cf/d of capacity added this year from Williams' Louisiana Energy Gateway (September 2025, 1.8 billion cf/d) and Momentum Midstream's New Generation Gas Gathering (December 2025, 1.7 billion cf/d). We believe additional pipeline capacity will be needed in the Haynesville but should not face regulatory hurdles. Permian associated gas production increases will be supported by the 4.8 billion cf/d (final investment decision [FID] pending) pipeline capacity expected to be operating by the first half of 2027.

Revisions To Canadian AECO – March 2025

Regional supply and demand fundamentals continue to pressure Canadian AECO natural gas pricing. AECO averaged less than US$1.50/million Btu through the first two months of 2025 while the Henry Hub averaged more than US$4/million Btu over the same period.

Canada's natural gas production has continued growing despite AECO prices that averaged just over US$1/million Btu in 2024, roughly half the average price for full-year 2023. Strong supply and relatively flat demand caused Canadian natural gas storage levels to test new highs entering winter 2024-2025 (see chart 3). While particularly cold weather has resulted in robust withdrawals this winter, we believe storage will remain well above the five-year average into 2026 tempering the AECO price. This is due to tepid domestic demand pulls--especially with startup of LNG Canada likely further delayed until the second quarter of 2025--and persistently increasing Canadian supply.

Chart 3

Given the high liquids component in regions like the Montney, Canadian producers can break even at exceptionally low (in some cases even negative) gas prices given the offsetting condensate component of the production prices roughly in line with WTI. Condensate is used as a blending agent for bitumen production, so its demand fundamentals remain strong as Canada only produces roughly two thirds of its domestic condensate demand. The relatively low breakeven gas prices in the Montney, strong condensate demand, and anticipated improving North American gas prices with LNG buildout, are supporting SPCI forecasts for increasing Canadian gas production. Specifically, SPCI expects Canadian production to increase by about 0.9 billion cf/d this year and 1.5 billion cf/day in 2026 despite the persistent storage glut and correspondingly weak AECO prices. Canada's 2024 production averaged about 18.5 billion cf/d, 0.6 billion cf/d higher than 2023 levels. We expect the Montney will remain the key area of natural gas production growth in Canada over the next three to five years, while other dry gas plays continue to decline.

As the overall North American market tightens due to increasing LNG export capacity in both the U.S. and to a lesser extent Canada(increasing to just under 3 billion cf/d by 2029) over the next few years, we believe the AECO price trajectory is positive but we are relatively more bearish on the knock-on effect from U.S. LNG for AECO versus the anticipated increase we assume for Henry Hub. We assume regional supply and demand fundamentals will exert more of an impact and keep AECO price improvement limited. Canadian producers can and will continue increasing production even at gas prices as low as US$1/million Btu. Furthermore, Canada is egress-constrained in its ability to significantly increase gas exports to the U.S. to capitalize on what we expect will be a tighter U.S. natural gas market for 2026-2028. President Donald Trump's recently enacted 10% tariff on Canadian oil and gas imports will also reduce Canadian producers' realized pricing for these exported volumes.

Revisions To Dutch Title Transfer

Our upward revision of our TTF price assumption for the rest of 2025 factors in both price-supportive factors--primarily geopolitical and supply--and price-dampening factors.

Europe's storage position is weak, in stark contrast with last winter's.

Europe's storage was only 38% as of March 1, 2025, way down year on year from 63% (273 terawatt hours) just as the Ukraine needs imports from the E.U. instead of providing a buffer. Europe is thus likely to exit winter with storage around 30%, which is low compared to the past two years (see chart 4). Pressure to refill to Europe's stated 90% gas storage target in the spring and summer 2025 before the heating season, will prompt a needed increase of LNG imports from the previous year of approximately of 36 billion cubic meters (absorbing approximately 6% of global supply).

The risk of failing the EU's Nov. 1, 2025, target of 90% fullness have prompted discussions to loosen it, which would merely shift the supply tensions from the spring and summer to next winter. This "kick the can" strategy appears risky. Regional stocks are particularly low in France and the Netherlands and paradoxically sustained in some markets (e.g., Italy, Austria, and Slovakia), which had direct Russian piped-gas supplies cut on Jan. 1.

Chart 4

Recent temporary price spikes to nearly $18/million Btu, in our view, relate more to geopolitical risks, primarily in the Middle East and Ukraine. The Middle East has limited impact on European and global LNG supply as long as shipping through the Hormuz strait remains fluid. Additional U.S. and European sanctions could affect Russian LNG supplies, which reached a record 18 billion cubic meters in 2024 (about 5% of Europe's demand). While both factors appear to be modest in terms of relevance to physical gas market fundamentals, they do prompt significant geopolitical premiums on exchange-traded markets. Beyond geopolitics, short-term tensions on demand (weather-related demand in Asia Pacific) or supply (commissioning delays at North America's LNG export projects and occasional maintenance issues in Norway) may prompt temporary price spikes.

The few near-term price-dampening factors include historically low LNG shipping rates. For the next three to five years, we continue to see backwardation down to $10/ million Btu beginning in 2027 given continued global LNG supply growth, from 2026 potentially lower LNG imports needs from Europe based on renewable growth weak economic growth (see chart 5).

Chart 5