Oil Price Forecast - Oil Surge on Iran Tensions, But WTI (CL=F) and Brent (BZ=F) Remain Trapped in a Supply Glut

Oil Benchmarks in Early 2026: CL=F and BZ=F Trade on Geopolitics Above a Soft Fundamental Floor

Spot prices for the main benchmarks show clearly how geopolitical risk is fighting a structurally heavy supply picture. U.S. West Texas Intermediate WTI (CL=F) is trading around $61.07 per barrel after a 2.9% daily jump of $1.71, while Brent (BZ=F) is near $65.88, up $1.82 or roughly 2.8%, both at their highest levels in more than a week. That bounce came immediately after the United States tightened sanctions on Iranian oil logistics, added nine vessels and eight affiliated companies to its sanctions list, and sent an aircraft-carrier group and guided-missile destroyers toward the Middle East. Oil is pricing a non-trivial probability that the 3.2 million barrels per day of Iranian output, already constrained by sanctions, becomes harder to move or more sporadic in terms of export flows.

At the same time, the physical market is not tight in a structural sense. The Indonesian crude benchmark ICP for December 2025 dropped to $61.10 per barrel from $62.83, a decline of $1.73. The OPEC basket slid from $64.46 to $61.85. Dated Brent eased from $63.65 to $62.70, and ICE Brent futures retreated from $63.66 to $61.64, while WTI on Nymex fell from $59.48 to $57.87 into year-end. The current CL=F recovery back above $61 is therefore a move against the dominant 2025 trend of softening benchmarks driven by oversupply.

Secondary grades show the same structure. Louisiana Light is quoted around $61.73, just above WTI (CL=F), while Mars US trades closer to $69.79, reflecting quality and logistics premia. Bonny Light at $78.62 shows that high-quality Atlantic Basin barrels still command a spread, but the anchor remains a low-60s dollar handle for the main benchmarks, with gasoline at about $1.85 per gallon and U.S. natural gas at $5.275 after a sharp weather-driven spike.

Oversupply vs Risk Premium: How a 3.7–4 Million bpd Surplus Collides with U.S.–Iran Tension

Fundamentally, the oil balance going into 2026 is heavy. OPEC+ crude output in November 2025 reached around 43.1 million barrels per day, higher than a year earlier and inconsistent with a tight-market narrative. Forecasts for production outside OPEC+ have also been revised up: expected 2025 non-OPEC+ supply growth was lifted by 40,000 barrels per day to 0.95 million barrels per day. On the demand side, growth expectations have been edged down; one key forecast for 2025 demand growth was cut by 16,000 barrels per day to 730,000 barrels per day. The International Energy Agency goes further and projects a potential 2026 surplus in the range of 3.7–4.0 million barrels per day, a buffer larger than the excess seen during the COVID-era demand collapse.

Russia is adding to that surplus narrative. Officials there are guiding toward crude production of 10.36 million barrels per day in 2025, rising again to 10.54 million barrels per day in 2026, even as geopolitical risk around Ukraine eases marginally on talk of dropping formal NATO membership aspirations. High U.S. output, a still-elevated Russian contribution, and incremental non-OPEC+ growth all feed into the “super-glut” story that pushed the Indonesian ICP down to $61.10 in December and pulled global benchmarks into the high-50s to low-60s.

The risk premium is coming from a different axis. U.S. sanctions on Iranian oil logistics, explicit warnings from Washington to Tehran, and the visible deployment of naval assets into the region have reignited fears of disrupted flows from the Gulf. Iran’s 3.2 million barrels per day of production, plus its role as a key exporter to big Asian buyers, is a central piece of the BZ=F pricing puzzle. At the same time, Kazakhstan’s massive Tengiz field has been partially offline after a fire at the operating joint venture, with output this month likely averaging only 1.0–1.1 million barrels per day versus the usual 1.8 million, according to projections. Major banks flag the risk that Tengiz remains constrained for the rest of January, which adds another leg to the supply-risk story.

The result is a layered structure: the IEA’s multi-million-barrel surplus and OPEC+ high output cap the upside for WTI (CL=F) and Brent (BZ=F) on any sustained basis, while U.S.–Iran tension, targeted sanctions, and Kazakh disruptions periodically push prices up 2–3% in single sessions. Oil is trading the intersection of surplus arithmetic and tail-risk pricing, not a classic shortage.

Regional Demand and ICP: Asia’s Cooling Throughput Anchors the BZ=F Ceiling

Price action in the Indonesian ICP exposes the Asia-side of the equation that matters directly for Brent (BZ=F). The average ICP slid from $62.83 in November 2025 to $61.10 in December. That move coincided with softer refinery runs in China, where crude throughput declined 0.9% month-on-month in November to 14.86 million barrels per day, the lowest level in six months. For refiners in Asia, December’s $61.10 ICP and mid-60s BZ=F translate into relatively comfortable refining margins in the absence of a demand shock; that reduces the urgency to bid barrels aggressively higher.

At the same time, the OPEC basket’s decline from $64.46 to $61.85 shows that Middle Eastern export grades are not escaping this softness. The Asia-Pacific market is absorbing crude at lower prices despite intermittent geopolitical scares. That tells you that forward demand expectations in the region are more cautious, consistent with slightly weaker growth projections and a policy backdrop where large importers such as China and India are diversifying suppliers aggressively.

The Indonesian ICP determination for December 2025, formalized at $61.10 per barrel, is not a noise event. It is backed by an official decree and directly reflects the combination of oversupply, high U.S. production and still-elevated Russian output, alongside modest demand downgrades. For BZ=F, that basket of signals is a cap: sustained trading far above the mid-60s requires either a much larger supply disruption or a positive surprise in Asian demand that is not visible in the current throughput and demand revisions.

North American M&A and the Cost Curve: How $170 Billion of Deals Shape CL=F’s Medium-Term Floor

Upstream corporate behavior in 2025 and the early 2026 deal pipeline show where the marginal cost of barrels is being repositioned. Global upstream oil and gas mergers and acquisitions in 2025 totaled about $170 billion, a 17% year-on-year decline, with the number of transactions falling 12% to 466. North America still dominated, generating over $112 billion in deal value, roughly 66% of the global total. That was driven by consolidation among U.S. shale producers and Canadian names in the Montney and other liquids-rich plays.

The second tier of activity was in Asia and South America, where deal values increased rather than shrank. Asian upstream deal value more than tripled to $18 billion, heavily influenced by a joint platform bringing together assets in Indonesia and Malaysia. South America saw a 71% year-on-year increase to $18.3 billion, anchored by LNG-linked and Vaca Muerta–focused transactions in Argentina.

In contrast, Africa dropped 57% to roughly $6 billion, Europe fell 24% to about $10 billion, the Middle East plunged 65% to nearly $4 billion, Oceania collapsed 96% to around $435 million, and Russia’s deal value shrank 25% to around $750 million. That dispersion mirrors the 2025 price path: Brent starting the year near $79 per barrel, sliding toward $65 by May, rebounding above $70 in June and July, and then rolling over to about $63 by December. WTI (CL=F) tracked that move, starting around $75 and fading into the high-50s.

What matters for price is the structure of the 2026 pipeline. As of January, identified upstream opportunities total nearly $152 billion, with $55 billion in a nearer-term investment pipeline, including a potential $23.5 billion exit by Santos and roughly $17 billion in international upstream assets associated with a major Russian company. An early-year $7.5 billion acquisition of Aethon Energy by a Japanese buyer, plus reported merger discussions between Coterra Energy and Devon Energy, signal that capital is still willing to scale into long-lived gas- and liquids-weighted positions at current price levels.

Large national oil companies – ADNOC, Saudi Aramco, Petronas, Petrobras, Pertamina, Ecopetrol – are acting as strategic buyers while several international oil companies recycle capital via divestments and joint ventures. This dynamic pushes the global cost curve down over time: low-debt, state-backed or scale-driven acquirers can run assets profitably at lower realized prices. For WTI (CL=F), that reinforces the idea that the mid-50s to low-60s region can function as a viable operating environment rather than a crisis zone. It also means that any price spike much above current levels is likely to unlock more opportunistic hedging and future supply, containing the upside.

LNG, Gas and the Cross-Commodity Signal: Why Oil Cannot Ignore a Record LNG Year

The gas and LNG markets are sending mixed signals that feed back into BZ=F and CL=F. Gas prices have been extremely volatile, with U.S. natural gas surging more than 20% in a matter of days during an Arctic cold spell and headline moves of 23–45% over very short windows as storage dynamics and weather collide. In Europe, gas storage has been draining at the fastest pace in five years, yet forward curves still price a heavy wave of new LNG supply.

On the infrastructure side, over $8.6 billion of LNG infrastructure assets are already formally up for sale, with another $2.5 billion in upstream assets feeding LNG plants also on the block. Additional optionality comes from potential changes in ownership of an 80% stake in a U.S. pre-FID LNG export project and partner-search processes for large Argentine LNG developments. A record LNG year in Europe is likely as markets rebalance and more export capacity ramps, while China moves to price some LNG flows in yuan.

For oil, the implication is straightforward. High LNG and gas availability puts a ceiling on oil’s role in marginal power generation and industry, especially in Asia and Europe. As gas and LNG supply expand, substitution risk for oil in power and some industrial uses increases. At the same time, periods of gas price spikes – driven by weather or infrastructure outages – will periodically direct incremental demand back into middle distillates. The current configuration, with gas volatile but fundamentally well supplied, leans toward capping CL=F and BZ=F more than sustainably supporting them.

Grid and Transformer Bottlenecks: Structural Drag on the Energy Transition, Long-Run Support for Liquids

The transformer and grid crisis developing in the United States and Europe is not just an electricity-sector story; it matters for long-run oil demand. Since 2019, U.S. demand for power transformers has jumped roughly 116%, while demand for distribution transformers has climbed about 41%. Domestic manufacturing has not kept pace. Roughly 80% of U.S. power transformer supply and 50% of distribution transformer needs in 2025 were met by imports, with lead times for large units stretching far beyond historical norms.

Underinvestment in transformer manufacturing, a post-pandemic construction boom and electrification push, and price volatility in grain-oriented electrical steel and copper are all constraining how fast new renewable and electrified loads can connect to the grid. Some analysts argue the shortage is overstated and that poor procurement practices are to blame, but the outcome is the same: delays in bringing new generation – including wind, solar and storage – online.

Major manufacturers are cautious. One leading supplier has committed about $1 billion to new U.S. transformer capacity but only when orders are pre-backed by buyers. The CEO is explicit that this is “probably not enough” to close the gap and that buyers who cling to transactional, short-term behavior may simply fail to secure supply.

For oil, that bottleneck slows the pace at which renewables can displace hydrocarbons in power generation and, indirectly, in some transport segments via EV charging infrastructure. The clean energy transition is economically compelling – renewables are “too cheap to fail” – but grid constraints keep the door open for liquids and gas longer than climate targets assume. This is a subtle but important source of medium- to long-term support for BZ=F and CL=F in a world that otherwise looks structurally oversupplied in the medium term.

Saudi Aramco (TADAWUL:2222): Equity Market Read on the Oil Story

Saudi Aramco’s share price is a useful check on how equity markets read the combination of oil fundamentals and policy risk. The stock closed the latest session at 25.32 riyals, up 0.08 riyal, a move of roughly 0.3%, trading in a 25.26–25.68 range. The broader Saudi benchmark gained about 1.2%, supported by optimism over fourth-quarter results and a structural shift: from February 1, the market opens to all foreign investors, which can materially increase liquidity and index participation.

For TADAWUL:2222, the backdrop is oil’s recent bounce, Middle East geopolitical tension, and a dividend-centric equity narrative. When Brent (BZ=F) trades closer to the mid-60s and WTI (CL=F) holds above $60, investors extrapolate stable free cash flow and high dividends. If BZ=F were to roll back toward the high-50s and CL=F retest the mid-50s, the conversation immediately pivots to how much capital expenditure can be cut without damaging long-term capacity and how flexible the dividend really is.

Unlike a typical listed E&P, insider activity in TADAWUL:2222 is de facto state policy: the controlling shareholder is the Saudi government. That means “insider transactions” are not classic director purchases or sales but decisions about secondary offerings, buybacks, and state-driven stake sales. From an oil-price perspective, the stock’s modest positive reaction to the latest CL=F and BZ=F bounce tells you that equity investors are not yet pricing in a new super-cycle; they are treating the move as a tradable risk-premium spike layered on top of a still-fragile fundamental base.

Technical Structure in WTI (CL=F): Channel, Value Areas and a Possible 17% Air Pocket

The CL=F daily chart remains decisively governed by a downward-sloping channel that has framed price action since mid-2025. The upper boundary is anchored at the June 23, 2025 high near $78.40 and validated by a more recent touch in mid-January 2026. Each time price has pushed into the top of that band, follow-through has failed. The latest attempt saw CL=F rejected and driven back toward the 20-day EMA, which sits near $59.11.

Short-term, the key battleground is the $59–$60 zone. The round $60 level is acting more as a ceiling than a floor. Value measures reinforce that story: a developing VWAP around $59.77 and a recent value-area high near $59.84–$59.85 define a tight resistance band. While CL=F was hovering around $59.75 at the time of one detailed technical review, the conclusion was clear: as long as futures trade below $59.85, bounces look like mean-reversion within a bearish structure, not durable reversals.

A concrete trade example illustrates the skew. Short entries were placed at $59.69 and $59.82, with an initial stop at $60.03, later tightened to $60.14, and tiered targets at $59.39, $59.17, and a swing objective around $56.60. The average entry of $59.755 against a $60.03 stop defined risk of $0.275 per barrel. Hitting the first target delivered roughly 1.33R, the second 2.13R, and the third – if reached – about 11.47R, with an average reward close to 5R if all targets printed.

That trade has since been stopped out as CL=F pushed through the value-area high, and the latest value area has migrated toward $60.02, effectively making that level the new “line in the sand” between bulls and bears. The important point is not the specific loss or gain; it is the map. As long as WTI (CL=F) remains inside the broader descending channel and fails to establish acceptance above $60–$61, the technical bias stays fragile. A move back toward the lower channel boundary near $56.80–$57.00 remains structurally valid.

For very patient traders, a deeper extension to around $49.50, approximately 17% below recent $59.75–$61.07 levels, is technically possible if global oversupply collides with a volatility shock in financial markets. That is not a base-case call but a clear air pocket on the chart that becomes relevant if the IEA’s surplus scenario converges with a risk-off macro backdrop.

Geopolitical Shock Layer: Iran, Sanctions and Kazakhstan as Short-Term Drivers for BZ=F and CL=F

The latest 2.8–2.9% jump in BZ=F and CL=F is a textbook geopolitical spike. Fresh U.S. sanctions on Iranian shipping capacity, including nine tankers and eight associated entities, raise the friction cost of moving Iran’s 3.2 million barrels per day. Naval deployments – aircraft carrier plus destroyers – signal readiness to escalate, and presidential warnings to Tehran not to crack down violently on protests or escalate the nuclear program revive the risk of direct strikes on infrastructure.

Layered on top of that is Kazakhstan’s struggle to bring the Tengiz field fully back after a fire, with production running 700,000–800,000 barrels per day below normal and credible risk that capacity remains constrained through the end of January. Major banks are explicit that this outage, if prolonged, adds a non-trivial tightening impulse to an otherwise loose market.

The same tape shows how quickly sentiment can flip. Earlier in the week, oil slipped about 2% when the U.S. administration backed away from a tariff fight with Europe and ruled out military action connected to another geopolitical flashpoint, reminding traders that headline risk cuts both ways. For BZ=F and CL=F, this means the next $2–$3 moves are likely to be event-driven and sharp, while the broader $55–$70 corridor remains anchored by fundamentals.

How Policy, Storage and Trade Flows Feed Back into the 2026 Oil Range

Beyond the Middle East, policy and trade data reinforce a capped-but-supported range for CL=F and BZ=F. India’s refiners are relying more on Middle Eastern and Atlantic barrels to compensate for volatility in Russian supplies, evidenced by new multihundred-million-dollar supply deals with Latin-American and Middle Eastern producers. U.S. refiners are snapping up discounted Venezuelan heavy barrels after sanctions flexibility re-opened that channel, while Washington simultaneously channels Venezuela’s oil revenues through a controlled fund structure, limiting Caracas’ ability to deploy capital.

European demand remains constrained by weak industrial activity, but gas storage is draining faster than in the prior five years, keeping some optionality for distillate usage in power and heating backup. LNG imports into Europe are on track for a record year as new projects ramp, and there are signs of increasing trading of LNG in non-dollar currencies, including yuan, which adds FX complexity but does not change the physical balance.

On the supply-management side, large producers publicly reject the narrative of a looming glut, arguing that the oversupply story is “seriously exaggerated.” However, the IEA’s 3.7–4.0 million barrels per day surplus figure, OPEC+ output of 43.1 million barrels per day, and rising non-OPEC+ contribution are hard data points. The tug-of-war between official messaging and analytical balances is precisely why the market keeps snapping back when CL=F tests the high-50s and BZ=F the low-60s: physical traders see barrels available, while macro funds see geopolitical optionality.

Oil Outlook for 2026: Key Bands for CL=F and BZ=F

Pulling together the macro, micro, and technical layers, the actionable picture for WTI (CL=F) and Brent (BZ=F) in 2026 is a defined range with asymmetric event-driven tails.

On the downside, the $56.80–$57.00 area in CL=F aligns with the lower boundary of the current channel and with the December 2025 lows around $57.87. Below that, the $49.50 region is the next major structural level, roughly 17% below current prices. Reaching that zone likely requires the IEA surplus to materialize at the high end of 3.7–4.0 million barrels per day, a soft global economy, and a de-escalation of Middle East risk.

For Brent (BZ=F), the mid-60s – around $65–$66 – is now the pivot. It reflects both the recent spike to $65.88 and the December $61.64–$63.21 basket levels. Sustained trade above $70 would probably need a prolonged outage at Tengiz or another large field, plus a meaningful reduction in Iranian exports or shipping capacity. Sustained trade below $60 would imply that oversupply and demand downgrades are overwhelming risk premia, with Asia unable or unwilling to absorb barrels even at discounted levels.

Technically, CL=F must hold above $59–$60 and then clear $61–$62 with conviction to neutralize the current bearish channel. Until there are multiple closes above the value band near $60.02–$60.10 and obvious acceptance at higher value areas, rallies remain suspect. For BZ=F, repeated failures in the high-60s would confirm that the current recovery is geopolitical froth rather than cycle renewal.

Final Stance on Oil: Hold the Benchmarks, Sell Strength Rather Than Chase Spikes

From a position-taking perspective on the benchmarks WTI (CL=F) and Brent (BZ=F), the data argue against calling this either a clear long or an outright structural short at current levels around $61–$66.

The oversupply side is real: 43.1 million barrels per day from OPEC+, non-OPEC+ growth of 0.95 million barrels per day, demand growth trimmed to 730,000 barrels per day, a projected 3.7–4.0 million barrels per day surplus in 2026, Russian output rising to 10.54 million barrels per day, Indonesian ICP at $61.10, and Chinese refinery runs at a six-month low of 14.86 million barrels per day. That package does not support a high and rising price deck.

The support side is also real: U.S.–Iran confrontation risk, explicit sanctions on Iranian shipping, a 700,000–800,000 barrels per day shortfall from Tengiz, faster-than-normal European gas storage draw, a still-slow grid build-out that prolongs hydrocarbon demand, and a massive LNG reshuffle that occasionally tightens regional balances. Those are sufficient to defend the mid-50s to low-60s for CL=F and the low-60s to mid-60s for BZ=F unless external demand collapses.

Given that mix, the clean call is:

For the benchmarks WTI (CL=F) and Brent (BZ=F), the stance is Hold, with a tactical bias to sell strength into the high-60s for BZ=F and low-60s to mid-60s for CL=F rather than chase geopolitical spikes. Directional longs only become attractive again if prices retest the mid-50s with the same surplus narrative still firmly in place and without a synchronized global recession.

That is the rational position when the tape is being pulled higher by tension and lower by surplus math: hold core exposure, avoid panic buying on news-driven jumps, and use the range – not headlines – as the primary decision anchor.

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