S&P Global Ratings has reviewed its hydrocarbon price decks and lowered its natural gas price assumptions for Henry Hub (HH) and Canadian Alberta Energy Co. (AECO) but raised its near-term price assumptions for Dutch Title Transfer (TTF). Also, despite recent weakness in oil prices, we have maintained our oil price decks. In particular, we lowered our HH price assumptions for 2025 and 2026 by 25 cents per million Btu (/mmBtu) and lowered our AECO price assumptions by 25 cents/mmBtu for 2024-2026. We have raised our TTF prices for the remainder of 2024 and 2025 by $2/mmBtu (see table).

Given the modest changes to our price deck, we do not anticipate any direct rating actions. Upstream balance sheets remain in a healthy position given the focus on paying down debt and generating cash over the past couple of years.

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 (/bbl) of oil for West Texas Intermediate (WTI) and Brent and $2.75/$2.25/$8 per mmBtu for natural gas prices as determined by HH, 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.

Oil

Following recent news of no increases in Chinese or North American import demand, the sentiment that the oil markets would be tight clearly has shifted. Oil prices have retreated over the past few weeks, recently touching a 14-month low, with the price of WTI falling below $70/bbl (see chart 1). Concerns about global economic slowdowns, particularly from China, the world's biggest importer; recent weak economic data; and the potential for 700,000 barrels per day (bbls/d) of Libyan production re-entering the market, have pressured oil prices. Libyan production has been offline since last month when a standoff began when the head of the Presidency Council in Tripoli in the west moved to oust a veteran central bank governor, Sadiq al-Kabir, and replace him with a rival board, prompting the House of Representatives in East Libya to halt oil production and demand the reversal of the decision to dismiss Kabir. Recent news that the two parties agreed to jointly appoint a central bank governor and that Kabir would be reinstated resulted in oil prices dropping 5%.

In order to provide some support, OPEC last week reversed its decision to introduce 180,000 bbls/d in October and November as part of its June decision to unwind 2.2 million bbls/d of production cuts. Moreover, while geopolitical tensions remain elevated, the political risk premium is eroding because it appears the market has grown ambivalent to conflicts actually resulting in sustained supply disruptions. However, U.S. and Organization for Economic Cooperation and Development crude oil inventories remain close to their five-year lows, providing limited cushion in the event of any potential supply shortfall.

Chart 1

OPEC+ clearly will remain the "balancer" of last resort, but it is in a difficult position because certain members, particularly Saudi Arabia, want to target an $80/bbl Brent oil price for budgetary reasons while balancing other constituents' concerns and frustration about the loss of market share to rising production from non-OPEC countries, particularly the U.S. and Canada, Brazil, and Guyana. OPEC+ currently has about 5.86 million bbls/d of production offline. At its June 2024 meeting, OPEC+ agreed to extend its two production cuts: the 3.66 million bbls/d of production cuts was extended by a year to the end of 2025, and the 2.2 million bbls/d of cuts was extended three months until the end of September of this year, at which time it was to gradually reintroduce those barrels over the course of the next 12 months. Last week, OPEC stated it would delay bringing back online 180,000 of the 2.2 million of cuts until the end of November while it continues to monitor market developments. We believe at its Dec. 1 meeting, OPEC will reassess the feasibility of maintaining production cuts in support of the oil markets. Any reintroduction of supply, given the recent weak economic data, will make it highly unlikely OPEC+ will be able to maintain an oil price of $80/bbl.

Natural Gas

North American gas prices just can't seem to catch a break. But we remain sanguine on the medium- to longer-term prospects because we believe the demand side of the equation will offer the solution to what ails natural gas (see chart 2).

Chart 2

Henry Hub

The near-term prospects for the improvement of Henry Hub natural gas prices remain limited. Henry Hub prices reached record lows back in March due to another warm winter, record production, the Freeport LNG export terminal being off-line, and undisciplined production growth from the Permian (where gas production is a by-product of oil drilling and thus is agnostic to price). Record power burn during the summer and a 38% decline in the natural gas rig count since April of last year have supported prices somewhat, with the Hub rising above $2/mmBtu in mid-August after spending 17 days below $2/mmBtu, but prices still remain very weak.

The resulting build-up in natural gas storage inventory levels, which are near five-year highs at 3.3 billion cubic feet (Bcf), continue to act as a lid on prices (see chart 3).

Chart 3

It's likely inventory levels get worse before they get better. S&P Commodity Insights (SPCI) is forecasting lower 48 inventory to approach four trillion cubic feet (Tcf) at the end of the injection season in October, which is near the 4.3 Tcf of storage capacity the Energy Information Administration (EIA) estimates is the maximum amount of capacity that can be stored at any given time.

However, we continue to believe the liquefied natural gas (LNG) terminal buildout over the coming years will be the remedy for low natural gas prices. With a normal winter, we expect the inventory surplus to begin eroding late this year and approach the five-year average as Plaquemines LNG begins to increase shipping and when Corpus Christi Stage III ramps up at year end. The market could meaningfully tighten in the second half of 2025 as LNG exports continue growing and when Golden Pass LNG plans to place in service the first two trains of its new three-train facility. At the same time, we should begin to see the production impact from the drop in rig count and completion activity over the past year. We expect the price of Henry Hub to begin a meaningful price rally starting in 2025 as the market tightens.

Canadian Alberta Energy Co.

Despite flat demand and record storage levels, Canadian natural gas production is anticipated to grow by 0.4 Bcf/d this year relative to 2023 to average about 18.3 Bcf/d. Canadian gas producers have been hesitant to scale back production given the anticipated start up of LNG Canada phase 1 later this year, instead focusing drilling efforts on more profitable liquids-rich areas rather than cutting rigs or total production. As a result, the gas-directed rig count has remained on par with 2023 levels despite AECO pricing well below US$1/mmBtu for most of this summer (see chart 4).

Chart 4

Similar to the U.S., Canadian natural gas storage levels may test capacity this fall, with SPCI currently predicting storage inventories to reach 811 Bcf at the end of October relative to estimated Canadian gas storage capacity of 824 Bcf (see chart 5). We anticipate storage will remain at or above the five-year high at least through the first six months of 2025, assuming normal weather patterns, which we expect will keep AECO prices compressed into 2025.

Chart 5

LNG Canada Phase 1 is expected to export its first cargo as early as November 2024, with first feedgas weeks earlier. Full commercial operations are anticipated in July 2025. While we expect positive pricing momentum for AECO next year associated with the start of Canadian LNG exports, as well as increasing U.S. LNG export supply, high storage levels and growing production are likely to temper some of this upward momentum. Meaningfully increased U.S. LNG export capacity in 2026 and beyond should similarly further strengthen North American gas prices, including AECO, but due to egress issues, not to the same quantity as we anticipate for Henry Hub.

Dutch Title Transfer

We revised upward our TTF price assumptions for the remainder of 2024 and 2025 to $12/mmBtu from $10/mmBtu, primarily reflecting geopolitical risk. Our prices for 2027 and 2028 are unchanged at $10/mmBtu. Geopolitical risks persist, primarily due to the Middle East and the Russia-Ukraine war. We anticipate limited physical impacts on European and global LNG supply, as long as shipping through the Hormuz strait remains fluid. However, the market seems to have waited until early August to price in a cut from January of piped shipments of Russian gas through Ukraine, as a five-year ship-or-pay contract with Gazprom expires at the end of 2024. These shipments of 2 billion cubic meters/month contribute about 5% to Europe's total gas supply. While both factors appear to be modest in terms of relevance to physical gas markets, they have prompted a significant geopolitical premium on exchange-traded markets.

Other supportive gas supply factors include recent maintenance in Norway (some 30% of European supply overall) and slight commissioning delays at two North American LNG export projects. For future years, the U.S. export-approval pause on LNG export projects doesn't yet seem a material factor. On the demand side, confirmation of Asia's rebound in LNG imports is supportive. Over January to August 2024, they increased 10% year on year, a pace likely to decelerate over the next few months but sufficiently sustained to keep global prices tight, but below levels of $12-$14/mmBtu where emerging market/Asia-Pacific demand starts being destroyed.

With respect to Europe's gas storage position, storage levels have consistently reached near-fullness as early as August (93% currently) for two years in a row. Storage levels are generally high across the EU membership, including the more vulnerable regions of Germany and Eastern Europe (see chart 6).

Chart 6

Heretofore, European LNG imports have sunk to three-year lows, dampening global demand, with Europe's imports year to date down a quarter year on year. The soft industrial recovery, a concerted effort to lower residential demand, and less gas-to-power burn as renewables continue substituting fossil fuels, have played a part in lower LNG imports (see chart 7).

Chart 7