Oil Prices Forecast: WTI Around $56 and Brent Near $60 as Oversupply Crushes the War Premium

Oil Price (CL=F, BZ=F): From Scarcity Premium To Glut Discount

WTI CL=F Around $56–57 And Brent BZ=F Near $60–61: Deepest Drop Since 2020

West Texas Intermediate CL=F trades around $56–57 a barrel after a daily loss of about $1.61 (-2.76%), while Brent BZ=F sits near $60–61 with a similar $1.60 (-2.57%) decline. Intraday, Brent slipped to roughly $61.21 and WTI to $57.30, keeping both benchmarks just above multi-year lows instead of reclaiming $70. Year to date, Brent is down roughly 18–19%, WTI about 20–21%, setting up 2025 as the steepest annual decline since 2020. North Sea Dated crude averaged about $63.63 in November, the fifth monthly drop in a row and the longest losing streak in more than a decade, putting prices near a four-year low. The curve and the tape show the same message: this is a controlled repricing lower, not a spike crash, as the market systematically removes the war premium and prices in structural oversupply.

Structural Oversupply: Supply Expands 3–4x Faster Than Demand

Global oil demand in 2025 is expected to rise by roughly 830,000 barrels per day (bpd), followed by 860,000 bpd in 2026. Against that, global supply is projected to grow by about 3.0 million bpd in 2025 and another 2.4 million bpd in 2026, led by non-OPEC+ output from the U.S., Brazil, Guyana, Canada and other producers. This imbalance is already visible in inventories: observed global stocks hit around 8.03 billion barrels in October, a four-year high, with builds averaging about 1.2 million bpd over the first ten months of 2025. The implied surplus for Q4 2025 through 2026 sits near 3.7–3.84 million bpd, close to 4% of global demand. Those are glut metrics, not “slightly loose” conditions, and they explain why rallies in CL=F and BZ=F toward the mid-$60s are consistently sold and why the market now treats that zone as resistance, not fair value.

“Oil On Water” And Inventory Overhang: The Glut Shows Up In Logistics

The surplus barrels are not just a statistical construct; they are sitting visibly in the system. A large slice of the excess appears as “oil on water”: crude in transit or parked on tankers as sanctioned flows struggle to find end buyers and long-haul shipments from the Americas to Asia increase. More cargoes spend more days on the water, effectively converting parts of the tanker fleet into floating storage. Meanwhile, refinery and product data confirm loosening balances. Weekly reports show crude draws that are modest at best alongside sizeable builds in gasoline and distillates, signaling that refiners are well supplied and that end-user demand, especially for diesel, is patchy. This happens even as natural gas trades near $4.366 per MMBtu, up about 2.92% on the day. The result is a stacked overhang: high crude stocks on land, ample refined product inventories, and an expanding cushion of barrels stuck in transit between the two.

National Oil Companies: NOCs Are Quietly Setting The Long-Term Floor For CL=F And BZ=F

Beneath the day-to-day swings in CL=F and BZ=F, national oil companies are defining the long-term supply structure. Investment trends show NOCs outspending listed majors in upstream, particularly in low-cost, long-life projects. Political backing, structurally lower lifting costs and the absence of quarterly dividend pressure allow these state producers to commit capital well into the 2030s while many listed companies keep capex tight and favor short-cycle projects. In Asia, PetroChina has been redirecting capital toward downstream and gas, upgrading refineries for higher-margin products and locking in LNG supply with long-term contracts stretching into the 2030s. Sinopec pushes harder into petrochemicals, hydrogen and CCUS while doubling down on LNG to feed industrial boilers and heavy manufacturing. CNOOC remains upstream- and LNG-focused, ramping offshore output in the South China Sea and buying into LNG projects earlier in the chain to control more gas for power and industrial clients. Petronas expands LNG positions with supply from Atlantic and Indian basin projects and spends at home on gas, CCS, hydrogen and midstream to stabilise Malaysia’s power system. India’s ONGC increases overseas investments and coordinates long-term LNG procurement through state buyers.

Gulf NOCs: Outspend, Integrate, Get Closer To The Customer

In the Gulf, state producers are executing the most aggressive strategy. Middle Eastern NOCs are taking a larger share of global upstream spending even as global totals stay roughly flat, pushing capital into long-life capacity and integrated complexes rather than short-cycle volumes. ADNOC’s XRG unit targets 20–25 million tonnes a year of gas and LNG capacity by 2035, moving existing U.S. assets under one platform positioned to lead further gas and LNG acquisitions, especially in North America. QatarEnergy expands LNG output through the North Field program and secures demand with long-dated contracts in Europe and Asia, betting on tighter LNG balances later in the decade. Saudi Aramco continues to tie upstream, refining, gas and “new energies” into a single integrated model, placing capital directly in consuming markets via refineries, petrochemical complexes and technology and services agreements. The regional strategy is clear: outspend competitors, integrate across the value chain and sit as close as possible to end demand, locking in long-life, low-cost barrels that remain profitable even if BZ=F spends years in the mid-$50s to low-$60s.

Latin America: Petrobras, Ecopetrol, Pemex, PDVSA And YPF Manage Constraints, Not Expansion

In Latin America, national producers are focused on holding output steady while navigating tight budgets and political noise. Petrobras retains the most flexibility: its 2026–2030 plan outlines about $109 billion in investment, with roughly $91 billion already committed, keeping most capital in pre-salt projects that are already moving while avoiding expensive frontier exploration. Gas, chemicals and lower-carbon investments are added only once core fields are fully funded. Ecopetrol shifts towards a broader earnings base, leaning more on transmission, solar and wind through its ISA unit to smooth volatility as upstream growth slows. By contrast, Pemex, PDVSA and YPF are constrained by debt, declining fields and political pressure. Pemex remains the most indebted energy company in the world, with declining production still a central concern. PDVSA’s exports and operations remain heavily shaped by U.S. sanctions, payment risks and the structure of swap deals with foreign partners. YPF faces higher costs, rising debt and adverse court rulings, with recent quarterly losses underscoring the pressure. For these three, the goal is defensive: keep output from collapsing and preserve enough progress in power and low-carbon projects to maintain financing and political support.

Africa: NOCs Push For Control But Face Execution Risk

Across Africa, the resource base is substantial, but getting projects funded and built on schedule remains the critical challenge. A series of investigations show large discoveries translating into less local benefit than promised, prompting governments to push their NOCs to take more control. Nigeria’s NNPC is the most aggressive volume-pusher: its exploration and production arm has reached about 355,000 bpd, the highest level in more than 30 years, and the company now operates under a mandate to lift output and finally get domestic refining running. Mozambique, Senegal, Ghana and Uganda are betting heavily on LNG and integrated gas projects as their only near-term path to meaningful export income. The payoff depends on keeping construction on time and preserving meaningful national equity instead of sliding back to structures where external operators capture most of the value. Governments want their NOCs to shift from passive royalty collectors to active operators, but the combination of financing, technical complexity and governance risk makes execution the main uncertainty.

North America: De-Risking Hub For Foreign NOCs And Critical-Minerals Base

North America is not building its own national oil company, but it is building something that matters for oil: a federal-backed critical-minerals base and a stable hydrocarbon platform that foreign NOCs can use to de-risk their portfolios. U.S. policy has pushed equity positions in rare earths and battery metals to secure domestic production, while the hydrocarbon side has become the natural hedge for Gulf and Asian NOCs. ADNOC’s XRG platform illustrates the strategy: take equity in U.S. gas, LNG trains, chemical complexes and midstream, anchoring long-life cash flows in one of the most legally and financially predictable markets. PetroChina and other Asian players are also extending into transition materials and industrial supply chains beyond crude and refined products. Upstream M&A outlooks highlight several state-owned producers as likely active buyers, with U.S. gas and LNG assets seen as core holdings thanks to deep capital markets and clear operating rules. For global barrels, North America is the hedge: the region where NOCs park capital to stabilise returns in a world where CL=F and BZ=F no longer trade with a persistent scarcity premium.

IEA, OPEC And Wall Street: Three Conflicting Maps For 2026 Oil Prices

The forward path for CL=F and BZ=F sits on top of three different narratives. The IEA projects a clear glut, with its December outlook putting 2026 supply about 3.84 million bpd above demand, close to 4% of global consumption, even after trimming the surplus for the first time since May. That implies continued inventory builds and structural downward pressure on prices unless producers cut volumes. OPEC+ disputes this. The alliance pumped around 43.06 million bpd in November and expects demand for its crude in 2026 at roughly 43.0 million bpd, implying a surplus of just 60,000 bpd if output holds near current levels – effectively balanced. The group has signaled it will pause further production increases in Q1 2026, choosing to observe rather than pre-emptively tightening. Wall Street banks sit between those poles but lean bearish: consensus has Brent averaging roughly $62–63 per barrel in 2026 and WTI around $59, with some houses marking Brent closer to $56 and WTI to $52 and warning about temporary excursions into the $40s if supply remains resilient or macro data soften. The cluster is clear: high-$50s to low-$60s Brent, cheaper WTI, and very few forecasts with a sustained average above $70.

Geopolitics: Peace Premium For Consumers, Not War Premium For Oil Futures

Geopolitics still generate intraday volatility, but the direction of impact on BZ=F and CL=F has flipped compared with earlier in the decade. The main focus now is the Russia–Ukraine peace track. A 20-point peace framework and security guarantees are being negotiated, and public signals from Kyiv suggest that “a lot can be decided before the New Year.” Contacts between Moscow and Washington have been acknowledged. For oil, a credible peace deal would eventually enable sanctions relief on Russian exports, adding barrels to an already oversupplied market and reinforcing the bearish narrative. As a result, headlines about progress in talks trade as negative for prices, while reports of strikes on infrastructure deliver only short-lived support. In parallel, the U.S. has ordered a “quarantine” of Venezuelan oil for at least two months, intercepting sanctioned tankers. That tightens some heavy-sour supply into the U.S. Gulf and parts of Asia, but volumes are too small to offset a multi-million bpd surplus, and routing adjustments dilute the impact. Other security events, including actions in Nigeria and seizures of sanctioned ships, are being treated the same way: they move the tape for hours or days but do not break the underlying oversupply story.

From Brent BZ=F To The Pump: Regional Fuel Prices Adjust To $60 Oil

The downstream translation of BZ=F around $60–61 is already visible in retail fuel prices, especially in Europe and the Balkans. Bosnia and Herzegovina and North Macedonia show the lowest pump prices in the region. Bosnia’s BMB 95 gasoline averages about €1.20 per liter, diesel around €1.17, and BMB 98 approximately €1.31, with autogas near €0.64 and heating oil around €1.08 per liter. North Macedonia’s diesel sits near €1.11, Eurosuper 95 roughly €1.22, Eurosuper 98 about €1.25, autogas around €0.91 and heating oil also close to €1.08. At the high end, Serbia posts average prices around €1.51 per liter for BMB 95 and €1.65 for Euro diesel, the highest diesel price in the region. Slovenia sees BMB 95 near €1.63, diesel around €1.45, and NMB 100 roughly €1.67 per liter, with autogas close to €0.83 and heating oil about €1.05. Montenegro sits in the middle with diesel around €1.31, BMB 95 near €1.41, BMB 98 around €1.44 and heating oil about €1.24. Croatia shows broader bands: diesel €1.30–1.52, Eurosuper 95 €1.34–1.46, Eurosuper 100 €1.77–1.79, autogas €0.83–0.86, and heating oil close to €0.81, one of the lowest heating oil prices in the region. Tax, excise and regulatory regimes explain most of the spread, but the backdrop of $60 Brent gives governments and regulators room to lower or freeze prices without blowing up budgets. Consumers and transport operators are already in a relief phase compared with the $90–100 environment, and a shift to mid-$50s Brent in 2026 would deepen that relief.

Demand Profile: Soft Growth, Not Collapse – Still Enough To Hurt Prices

On the demand side, there is no classic recession-driven crash; the problem is that growth is too weak relative to supply. The IEA has nudged its demand outlook up, not down, projecting growth of about 830,000 bpd in 2025 and 860,000 bpd in 2026 as a somewhat brighter macro backdrop and a softer U.S. dollar support consumption, especially in emerging markets. Cheaper crude and a weaker dollar usually stimulate fuel demand at the margin. But several constraints cap that support. China’s picture is uneven, with EV penetration suppressing gasoline demand and industrial activity remaining volatile. European growth is sluggish. Efficiency gains and electrification in OECD economies continue to curb incremental oil use in transport and industry. With supply running multiple times faster than consumption, even a slightly upgraded demand forecast cannot absorb the flood of new barrels. That asymmetry alone is enough to push CL=F into the mid-$50s and BZ=F into the low-$60s without any outright collapse in usage.

Near-Term Tape For CL=F And BZ=F: Weak Bounces Inside A Bearish Structure

Recent price action confirms the fundamental pressure. Both WTI CL=F and Brent BZ=F have bounced off five-year lows but remain well below the levels that agencies and banks consider sustainable for a tight market. Brent struggles to defend the $60–61 band and faces sellers on every attempt to approach the mid-$60s. WTI repeatedly fails to hold moves toward $60, stalling in the high-$50s. Weekly patterns show the same behavior: 2–3% rallies driven by tanker seizures or Russian export headlines fade quickly as traders refocus on inventory data, the 3.84 million bpd 2026 surplus projection and the reality that both benchmarks are tracking declines of around 19–21% for the year. From a risk-reward standpoint, the path of least resistance in the short term remains downward, toward a $55–60 range for BZ=F and somewhere around $51–57 for CL=F, consistent with the surplus, storage and macro story.

Medium-Term Ranges: Market Already Prices The 2026 Playbook Into Today’s Curve

Forward curves for CL=F and BZ=F show that traders are already trading the 2026 narrative. Baseline forecasts cluster around Brent averaging high-$50s to low-$60s in 2026 and WTI in the high-$40s to low-$50s. The EIA sketches Brent near $69 in 2025 dropping to about $55 in 2026, with WTI around $65 and $51 respectively. Analyst polls center on $62–63 Brent and $59 WTI, while the more bearish houses argue for $56 Brent and $52 WTI with possible dips into the $40s if non-OPEC supply remains resilient or global growth weakens. With BZ=F currently near $60–61 and CL=F around $56–57, the market has already moved most of the way into that target band. The remaining questions are tactical: whether an early-2026 flush drags Brent into the mid-$50s and WTI into the low-$50s before supply responds, and how quickly U.S. shale and fringe producers cut capex if realized prices sit at or below breakevens. A prolonged period of WTI at $50–60 will squeeze returns on higher-cost wells and eventually curb growth, but with a lag, meaning the surplus can persist through much of 2026.

Verdict For Oil – WTI CL=F And Brent BZ=F: Hold With Bearish Bias, Sell Strength Into The High $60s

The combined data set points to a clear stance on oil price (CL=F, BZ=F). Spot levels show WTI CL=F around $56–57 and Brent BZ=F near $60–61, both down almost 20% year to date. The fundamental balance shows a structural surplus near 3.7–3.84 million bpd into 2026 with inventories at 8.03 billion barrels and stock builds of roughly 1.2 million bpd. NOCs are locking in long-life, low-cost capacity and integrated LNG positions that remain profitable in a mid-$50s Brent world. Geopolitics now skew bearish for prices when peace prospects improve and deliver only shallow, short-term support when disruptions intensify. Retail fuel prices in key regions already reflect $60 oil and are positioned to fall further if Brent migrates into the mid-$50s in 2026. Forecasts from the IEA, EIA, OPEC and major banks cluster around mid-$50s to low-$60s Brent and low-$50s WTI, with very few scenarios that justify a durable return above $70 in the near term. Under these conditions, the rational position is Hold with a bearish tilt: treat spikes toward the high-$60s Brent / low-$60s WTI band as opportunities to reduce or hedge long exposure, and view dips into the mid-$50s Brent / low-$50s WTI range as reassessment zones, not automatic buys, unless there is concrete evidence that U.S. shale capex and non-OPEC growth are rolling over. Until the surplus meaningfully narrows or policy removes a chunk of supply, oil is a range trade tilted to the downside, not a high-conviction long back into the $80–100 regime.

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