Diesel (heating) oil price on Apr 17, 2026 at 5pm EDT?

The IEA forecasts indicate a significant reduction in OPEC+ spare production capacity. The International Energy Agency (IEA) anticipates a significant reduction in OPEC+'s effective spare production capacity throughout 2025. Initial forecasts from the May 2025 Oil Market Report (OMR) projected capacity at approximately 2.8 Mb/d, highlighting market vulnerability ^[4]. Subsequent revisions in the September 2025 OMR saw this figure drop to an average of 2.6 Mb/d by year-end, falling below the 3 Mb/d critical buffer ^[3]. The December 2025 OMR further refined this outlook, forecasting OPEC+ effective spare capacity to average around 2.5 Mb/d for the entirety of 2025, underscoring a narrowing cushion against potential supply disruptions ^[1].

Both agencies project spare capacity will fall below the critical 3 Mb/d buffer. The U.S. Energy Information Administration (EIA) largely concurs with the IEA's outlook on tightening spare capacity, projecting global spare crude oil production capacity, predominantly held by OPEC+, to consistently remain below historically comfortable levels throughout 2025 ^[2]. The EIA's October 2025 Short-Term Energy Outlook (STEO) estimates an average of 2.7 Mb/d for the year, frequently dipping below the 3 Mb/d threshold ^[2]. This sustained decline in effective spare capacity below the critical 3 Mb/d buffer indicates a structural shift, leading to heightened supply insecurity, increased price volatility, and greater risk of shortfalls for refiners in the event of unexpected outages or geopolitical events, potentially impacting refined product costs and availability ^[3].

Global complex refining capacity will increase, shifting towards the Middle East and Asia. By Q1 2026, the global complex refinery landscape is expected to undergo a significant transformation, characterized by a net increase in overall capacity, despite regional closures, with a pronounced geographical shift ^[1]. Major capacity additions are forecasted in the Middle East and Asia, notably from projects such as Kuwait's Al-Zour refinery and Nigeria's Dangote refinery, which are substantial contributors to this global growth ^[1]. Conversely, North America has experienced and anticipates further significant reductions in operable crude distillation capacity. Since 2019, approximately 1.5 million barrels per day (b/d) of U.S. capacity has been retired or converted, with additional reductions expected by 2026, exemplified by Phillips 66's Rodeo refinery (converting to renewable diesel) and Valero's Benicia refinery ^[2]. These regional closures are partially offset by global additions, leading to a redistributed, rather than diminished, global refining footprint ^[1].

North American closures will reduce U.S. distillate supply, increasing import reliance. The announced closures in North America, particularly in the U.S., will directly impact domestic fuel supply, especially for distillates ^[2]. The U.S. Energy Information Administration (EIA) forecasts that refinery closures combined with rising consumption will contribute to reduced U.S. petroleum inventories in 2026 ^[3]. The U.S. East Coast (PADD 1) is already a structurally deficit market for distillates, relying heavily on imports to meet demand. The reduction in domestic refining capacity, particularly from complex facilities capable of producing higher yields of distillates, will exacerbate this reliance on external supply ^[2].

Increased import dependency will reshape distillate arbitrage to the U.S. East Coast. With diminished domestic supply, the U.S. East Coast will increasingly depend on imports from other refining hubs, including Europe, the Middle East, and Asia ^[4]. This heightened import dependency is expected to increase the price sensitivity of the U.S. East Coast distillate market to global supply disruptions, shipping costs, and international product balances. The necessity to attract barrels from further afield will likely widen the arbitrage window, potentially requiring higher premiums for imported distillates to cover freight and encourage trans-Atlantic or even longer-haul shipments, thereby influencing heating oil futures and overall distillate pricing on the East Coast ^[4].

U.S. renewable diesel capacity will significantly expand by 2025. Total U.S. renewable diesel production capacity is projected to reach approximately 4.6 billion gallons per year (BGY) by the end of 2025 ^[1], an increase from about 3.8 BGY operating capacity in 2023 ^[2]. This substantial growth is primarily driven by federal incentives, such as the Inflation Reduction Act (IRA), and state-level Low Carbon Fuel Standard (LCFS) programs, which collectively aim to reduce the carbon intensity of transportation fuels ^[1].

Renewable diesel expansion will greatly displace conventional distillates in PADD 5. This surge in production capacity is expected to have a significant impact on the demand for petroleum-based distillates, particularly within the West Coast's PADD 5 region ^[4]. PADD 5 alone consumed roughly 75% of total U.S. renewable diesel in the first three quarters of 2023 ^[4]. Specifically in California, renewable diesel consumption is projected to reach around 2.5 billion gallons by 2025, potentially fulfilling over 80% of the state's current conventional diesel demand ^[3]. While renewable diesel consumption is also growing in PADD 1 (East Coast), its impact on displacing petroleum-based distillates in that region is anticipated to be more modest compared to the substantial displacement seen on the West Coast ^[5].

The Jones Act tanker fleet's net change remains unclear, but it is perceived as constrained. The precise net change in the number and capacity of the Jones Act-compliant tanker fleet available for transporting refined products from the Gulf Coast (PADD 3) to the East Coast (PADD 1) is not explicitly detailed. While the return of a specific Citgo Jones Act tanker from abroad was noted, potentially re-entering the domestic fleet, this individual event does not quantify the overall net change in the fleet ^[2]. The fleet is generally perceived as constrained and stable, with ongoing discussions around Jones Act waivers highlighting persistent logistical challenges.

Jones Act waivers consistently show limited impact, highlighting persistent fleet capacity issues. Despite the use of temporary Jones Act waivers to address domestic fuel relief, these waivers have consistently been observed to have "little impact on US domestic oil supply" ^[3] and a "limited impact on demand" ^[4]. This suggests that the underlying capacity of the Jones Act fleet remains a persistent factor in domestic energy logistics. Experts indicate that foreign-flag waivers do not pose a risk to the Jones Act fleet itself, reinforcing the view of its continued, albeit potentially limited, operational presence ^[5].

Insufficient domestic fleet capacity leads to increased shipping costs and price spikes. The consistent need for waivers and their limited effectiveness, coupled with observations of "stalled domestic fuel relief" ^[6], point towards an insufficient or highly utilized existing domestic fleet for refined products. Market conditions, including events like the "Arcosa Exit" in the Gulf Coast barge market slated for Q1 2026 ^[7], further underscore tightness and potential disruptions in domestic energy logistics. These constraints create an environment ripe for increased shipping costs and potential regional price spikes, particularly for heating oil in PADD 1, as domestic supply remains challenging despite soaring fuel exports ^[3].

Major energy analysts forecast persistently tight US distillate inventories through 2026. Both Goldman Sachs and the U.S. Energy Information Administration (EIA) anticipate continued tightness. Goldman Sachs has issued warnings about a "significant shortfall in global diesel inventories," forecasting critically low levels that could lead to oil price shocks and refined product crises ^[2]. The EIA projects U.S. total distillate fuel oil inventories to remain at "multiyear lows" throughout 2026, with a forecast of 117 million barrels (MMbbl) by the end of 2026. This level would represent the lowest year-end inventory observed since 1951 ^[1].

Forecasted Q1 2026 levels are significantly below the five-year average. The EIA’s outlook indicates that US distillate inventories will consistently fall below the previous five-year (2019–2023) average through 2024-2026, implying notably low levels at the close of Q1 2026 ^[1]. The calculated 5-year seasonal average for distillate inventories at the end of March (the Q1 withdrawal season) is approximately 129.1 MMbbl [Derived from 5]. Moreover, the projected 2026 inventory levels are expected to be near or below the critically low levels seen in 2022, when US distillate inventories ended March at 113.8 MMbbl [Derived from 5]. The EIA's year-end 2026 forecast of 117 MMbbl suggests that levels at the end of Q1 2026 will be within a similar critical range, mirroring or exceeding the tightness experienced in 2022 ^[1].