• S&P Global Ratings raised its 2023 and 2024 West Texas Intermediate (WTI) and Brent oil price assumptions. We also set our long-term price assumptions for 2025 (see table).
• At the same time, we lowered our Henry Hub natural gas price assumption for the remainder of 2002 and 2023 and set our long-term price assumption for 2025. We also lowered our Alberta Energy Co. (AECO) 2023 price assumption and set our long-term AECO price assumption.
• We lowered our Title Transfer Facility (TTF) price assumption for the remainder of the year and affirmed our 2023 and 2024 price assumptions. We also set our long-term TTF 2025 price assumption.
• Macro conditions and supply/demand fundamentals remain supportive for credit quality.

We use this price deck as an input to our ratings analyses to assess credit quality for hydrocarbon-related corporate, sovereign, local and regional governments, and project finance issuers, in accordance with the approach described in "How S&P Global Ratings Formulates, Uses, And Reviews Commodity Price Assumptions," published Sept. 28, 2018. In particular, the increase in the oil price assumptions for 2024 reflects our shift to a figure based on our expectations for 2024 as a year, rather than as an indicator of long-run sustainable prices and break-even costs. Our long-term assumption is now in 2025 in place of 2024.

Supply Fundamentals And Political Unrest Remain Supportive For Oil Prices

Global oil prices have recently declined largely due to demand-related concerns about recessions and the persistent lockdowns in China due to COVID-19. Nevertheless, oil prices remain supported by many factors, largely on the supply side of the equation. We also believe price volatility will continue, as markets focus on opposing factors and especially as the EU embargoes on Russian seaborne crude oil (Dec. 5, 2022) and products (Feb. 5, 2023) become effective. Our base case view reflects:

• Globally, we expect supply and demand to be broadly balanced in 2023 and into 2024, with Organization for Economic Cooperation and Development commercial crude inventory levels remaining at or near the low end of the five-year averages (see chart 1). Demand and refinery utilization rates are getting close to pre-COVID-19 levels.

• OPEC has remained supportive of prices and recently announced that it will reduce oil production by 2 million barrels per day (b/d). While on the surface the amount seems meaningful, it's unlikely that all 2 million barrels will come off the market because some OPEC producers are having trouble reaching their current production quotas and as has been demonstrated in previous production cut announcements by OPEC, some countries do not adhere to their stipulated quotas. S&P Commodity Insights(SPCI) believes that actual production cuts will amount to approximately 800,000 b/d.
• We expect producers in North America to remain disciplined in terms of production. Estimates by the U.S. Energy Information Administration (EIA) and our affiliate SPCI place U.S. production increasing by 490,000 b/d and 1 million b/d, respectively, in 2023. SPCI expects Canada will increase production by a modest 200,000 b/d. Driven by investors' priorities, public producers in North America are still focused on keeping production growth limited and using cash flow to pay down debt and augment returns to investors. Given the track record in 2022, we do not expect this philosophy to change in 2023.
• There is a significant geopolitical risk premium embedded in global oil prices due to the Russia-Ukraine war, which shows no sign of abating.
• According to SPCI, surplus capacity remains near historical lows at just over 1 million b/d. The OPEC production cuts will add barrels and increase spare capacity to somewhere near 2 million b/d, but we still consider that level to be tight.
• EU sanctions on seaborne Russian crude oil are set to become effective on Dec. 5. SPCI estimates that approximately 1.5 million b/d will be affected by February 2023. Netting out Russian barrels sent to Asia, we estimate approximately 500,000-700,000 b/d will be removed from market. So far, Russian production has been resilient, with China and India buying discounted Russian crude at the expense of other nations, particularly the U.S.
• It's unlikely that an agreement will be reached on the Iran nuclear deal, so we do not expect additional Iranian barrels.

Natural Gas Prices Have Fallen As Supply Has Increased

Henry Hub

U.S. natural gas prices have sharply declined recently largely due to approximately 3 billion cubic feet (bcf) per day of offline liquefied natural gas (LNG) capacity from the Freeport LNG facility, as well as Cove Point LNG, which has been offline longer than expected for maintenance. Also, weaker demand for the shoulder season and higher-than-expected gas production led to a meaningful increase in natural gas storage injections for September to October, which reduced the deficit in storage back to the five-year average (see chart 2).

In the near term, with cold weather returning and Cove Point and Freeport LNG production coming back on line, we do not expect inventory levels to rise from here. Also, Calcasieu Pass becoming commercially active next year should lend further support over the medium term. Longer term, U.S. LNG export capacity remains flat until late 2024, when additional liquefaction capacity begins to come online, particularly from Venture Global's Plaquemines facility and LNG Canada sometime in 2025.

Longer term, the U.S. market growth in demand and prices will be tied to Europe's LNG build-out capacity as it looks to source natural gas away from Russian supply. Natural gas prices appear to be "globalized" with the situation in Europe a key factor for the direction of longer-term prices.

AECO

Our AECO price revision largely reflects the expectation of softening U.S. lower 48 demand for Canadian natural gas exports, which we believe will persist into 2024. Our long-term AECO price assumption maintains a 50-cent per mmBtu basis differential relative to our Henry Hub long-term price assumption.

U.S. domestic natural gas production is forecast to increase beyond 2022, with S&P Commodity Insights projecting U.S. domestic gas production to increase over 11 bcf per day between 2022 and 2025. In addition, Canada's 2023 natural gas production is also projected to remain relatively stable year over year, with projected 2022 expected daily average production of about 17.4 bcf per day, which increased about 1.3 bcf per day from 2021's daily average production. At this time, U.S. LNG exports are not expected to grow to fully absorb the projected increased U.S. gas production, thereby weakening demand for Canadian gas exports into the U.S. lower 48. Furthermore, with Canadian gas in storage, at about 625 bcf on Nov. 11, 2022, only marginally below the five-year average of about 702 bcf, these normal storage levels will likely constrain potential near-term AECO price upside.

TTF

TTF prices have declined considerably from late August because high prices led to industrial and consumer demand destruction while LNG shipments to Europe have remained consistently high. Indeed, European gas demand is set to decrease well over 10% year on year in 2022--a strong reduction only partly due to warmer spring and fall weather. Where possible, some companies are switching to other fuels and feedstocks while gas-fired generation (off a commodity now priced at an equivalent to oil at nearly $200 a barrel) even now remains more expensive than coal-fired generation.

Barring abnormally cold weather, it appears Europe will have sufficient gas to meet its needs for this current winter. With overall inventory levels in the mid-90 percent area, Europe surpassed its 85% target (see chart 3).

Chart 3

The concern is next April, when Europe will look to build its coffers for the 2023 heating season and will likely be doing it without Russian gas from NordStream 1. In response, Europe approved a gas rationing plan to reduce consumption by 15% (45 billion cubic meterby March, which is roughly the amount of Russian gas loss from NordStream 1. At current levels, Russian supply meets only about 8% of average European demand, down from more than one-third in 2021. Russian pipeline supply continues through Turkey and Ukraine, totaling about 65 billion cubic meter a day in October. However, an interruption of Ukrainian transit remains a salient near-term risk. We estimate these lower Russian volumes cannot be fully compensated by other sources, so continued lower consumption is necessary unless the winter proves unusually mild.