Venezuela Oil Production, PDVSA 2026 Sanctions & Prediction Markets: What the Odds Are Really Pricing In

Venezuela is one of the few places where a change in policy can move barrels almost as much as geology. That’s why prediction markets keep circling the same macro trade: how much incremental Venezuelan supply can realistically hit the water by 2026 under evolving U.S. sanctions on PDVSA—and who gets paid if it does.

Two flagship market framings dominate trader attention:

1. “Venezuela crude production ≥ X mb/d in 2026” (a pure volume question that implicitly bundles field performance, diluent availability, and export logistics).
2. “Major U.S. sanctions relief on PDVSA by end‑2025” (a legal/regime question that acts as a master switch for financing, services, and buyers).

We’re not hardcoding ‘latest odds’ in this section because prediction-market prices move intraday and vary by venue; SimpleFunctions readers should treat the live board as the source of truth. The key is that these markets are jointly pricing a sanctions pathway and a physical ramp that can’t be willed into existence.

Why do a few hundred thousand barrels per day matter? Because Venezuelan crude is heavy and sour—the stuff that competes with grades like Mexico’s Maya and the U.S. Gulf’s Mars, and that sets the tone for heavy‑crude differentials. A swing of 200–400 kb/d in heavy supply doesn’t just nudge headline Brent; it can reprice spreads and refinery margins in a market where complex refiners are constantly optimizing sour capacity.

This article connects the dots prediction markets often separate: (a) the sanctions and licensing timeline (PDVSA’s 2019 SDN designation; Chevron’s GL 41 opening in late‑2022; the brief broader opening in late‑2023; and the 2025 shift to Chevron wind‑down licenses), (b) production/export history, (c) PDVSA’s infrastructure and capex bottlenecks (upgraders, power, diluents), (d) China/Russia oil‑for‑loans constraints, and (e) a scenario tree for 2026–2030 that’s tradable—not just geopolitical narration.

2. Sanctions Architecture 2017–2025: How U.S. Policy Boxed In PDVSA

Before the sanctions era, PDVSA was already a distressed national oil company—but it was still financeable and marketable. Venezuela exported more than 2 million barrels per day (mb/d) early in the 2010s, with the U.S. Gulf Coast as a natural home for heavy sour crude. The system’s decline began well before OFAC: underinvestment, operational decay, and mounting arrears shrank output and export reliability. U.S. sanctions didn’t start the fall—but they steadily removed PDVSA’s ability to borrow, import critical inputs, and sell crude through normal counterparties.

2017–2018: Financial sanctions (crude still flowed)

The first regime shift was financial, not an oil embargo. Executive Order (EO) 13808 (Aug. 25, 2017) restricted access to U.S. capital markets for the Government of Venezuela and PDVSA—most importantly by prohibiting new PDVSA debt longer than 90 days (and new sovereign debt longer than 30 days). This mattered operationally because PDVSA’s “working capital” model depended on rolling short-term credit, prepayments, and supplier financing.

In 2018, the U.S. added targeted constraints—EO 13827 (Petro crypto) and EO 13835 (limits on certain Venezuelan debt and equity transactions). But at this stage, crude exports to the U.S. were still generally permissible; the choke point was money: fewer banks would clear payments, and fewer service firms would extend credit.

2019: PDVSA becomes a fully blocked party (effective oil embargo)

The second regime shift was the one markets still anchor on: January 28, 2019, OFAC designated PDVSA as an SDN under EO 13850 (oil sector). From a trader’s perspective, this converts PDVSA from “high-risk counterparty” into “blocked property” for U.S. persons—effectively an oil-trade embargo unless a license applies.

Later that year, EO 13884 (Aug. 5, 2019) broadened the blocking to the Government of Venezuela, reinforcing that PDVSA sits inside a comprehensive blocking framework.

OFAC paired the designation with narrow General Licenses (GLs) to manage an unwind rather than to keep the industry functioning:

• The GL 7/8 family allowed limited wind-down/maintenance for specific U.S.-linked entities and activities (e.g., certain operations tied to CITGO and named oil service firms).
• The logic was containment: prevent unsafe abandonment of assets, while denying PDVSA cash and growth capital.

2020–2022: “Maintenance-only” plus rising secondary-sanctions risk

Once PDVSA was fully blocked, the practical system changed in three ways:

1. Financing collapsed (no normal trade finance, fewer insurable cargoes).
2. Diluent imports became episodic (critical for Orinoco extra-heavy blending), because sellers, shippers, and insurers faced compliance risk.
3. Marketing moved gray—ship-to-ship transfers, opaque intermediaries, and deeper discounts.

Washington also increased pressure on non-U.S. actors by designating shipping and trading networks that “materially assisted” PDVSA. Even where sanctions were not formally extraterritorial, the risk migrated through the system via insurers, banks, classification societies, and counterparties.

Nov 2022: Chevron’s GL 41 (a controlled outlet, not broad relief)

The third regime shift was a carve-out: GL 41 (Nov. 26, 2022) authorized Chevron (and subsidiaries) to resume limited activity in its Venezuela JVs. It allowed:

• Limited JV production and lifting;
• Exports to the United States (provided the crude is first sold to Chevron);
• Imports into Venezuela of inputs (including diluents/condensate) needed for JV operations.

But GL 41 was designed to avoid revenue normalization for PDVSA. It explicitly prohibited, among other things:

• Tax/royalty payments to the Government of Venezuela;
• Dividends (including in-kind) to PDVSA;
• Sales to non-U.S. destinations;
• Expansion into new fields beyond projects existing as of Jan. 28, 2019.

In other words: GL 41 increased barrels and protected asset integrity, but tried to cap cash and prevent a full investment cycle.

Oct 2023: GL 44 (brief broader opening tied to elections)

In October 2023, OFAC issued GL 44, temporarily authorizing a broader set of oil-and-gas-sector transactions. The opening was explicitly political—linked to commitments around Venezuelan elections—and it proved reversible.

2024–early 2025: Reversal and re-tightening (Chevron becomes “wind-down”)

The most recent regime shift is the one traders must price today. Under the new U.S. administration, OFAC moved from “Chevron operating license” back toward “Chevron wind-down.”

• GL 41A (Mar. 4, 2025) reframed Chevron’s authorization as time-bound wind-down activity.
• GL 41B (Mar. 24, 2025) updated wind-down terms and reiterated the core rule: no expansion into new fields.

What “current rules” mean in practice (2025)

For compliance and physical trading, the 2025 posture is simple:

• PDVSA remains an SDN / blocked party. Absent a general or specific license, U.S. persons cannot transact.
• Chevron’s scope is constrained to wind-down parameters, with continued restrictions on payments to PDVSA/government (taxes, royalties, dividends) and on expansion.
• Non-U.S. persons remain exposed if they facilitate non-licensed trade that OFAC views as materially assisting PDVSA—especially where shipping, insurance, or dollar clearing touches the U.S. financial system.

This sanctions architecture is the bridge between “legal headline risk” and “field-level physics.” When financing, diluent imports, and reputable counterparties are constrained, production is constrained—even if the reservoirs are not. Later sections translate each policy phase into bottlenecks at the upgrader, blending, and export-terminal level.

3. Venezuela’s Production and Export Collapse, 2010–2024

The sanctions architecture in Section 2 matters because Venezuela’s oil system was already eroding—then policy shocks turned a slow decline into a step-change collapse. For traders trying to price 2026 outcomes, the key is the starting point: Venezuela is not ramping from a healthy 2+ mb/d base; it is rebuilding from a structurally damaged system where exports, blending, and logistics have repeatedly been disrupted.

3.1 Production: from >2.3 mb/d to “sub-1 mb/d country”

Using OPEC’s Monthly Oil Market Report (MOMR) “secondary sources” series (the benchmark most desks default to), Venezuela’s national crude output was roughly 2.4–2.6 million b/d in the early 2010s. The downtrend begins well before the oil embargo era:

• 2014–2016: the decline accelerates alongside low prices and deepening operational decay—loss of skilled labor, rising well downtime, failures in power and water handling, and mounting maintenance backlogs.
• 2017–2018: output falls faster after U.S. financial sanctions constrain PDVSA’s ability to roll working capital, import parts, and pay service providers on normal terms.
• 2019–2021: the sharpest break occurs after PDVSA’s SDN designation (Jan 2019), which functionally blocks normal marketing, insurance, and trade finance. Venezuela spends much of this period as a ~0.5–0.7 mb/d producer in OPEC secondary-source estimates.
• 2022–2024: output improves modestly as new workarounds and selective licenses (notably Chevron’s GL 41) support maintenance, diluent logistics, and more predictable lifting. Even so, the recovery is incremental—by 2024, the country is still roughly a ~0.75–0.9 mb/d producer by mainstream secondary estimates, far from its early‑2010s level.

A practical interpretation for 2026 market pricing: the “easy” bounce is largely behind Venezuela. Every additional 100 kb/d beyond today requires not just wells, but diluent, upgrader/blending reliability, and export-terminal throughput that have all proven fragile.

3.2 Exports and destinations: U.S. fades, Asia dominates, opacity rises

Exports tell the sanctions story more cleanly than production because they capture the marketing constraint.

U.S. Gulf Coast: from core customer to near-zero (then small licensed return). In the early 2010s, the U.S. was Venezuela’s natural home for heavy sour barrels (complex Gulf Coast refineries plus CITGO-linked flows). EIA import data show Venezuelan barrels steadily fading through the mid‑2010s, then collapsing to near zero by mid‑2019 after PDVSA was blocked.

China (and “China via somewhere else”): the dominant outlet post‑2019. After the embargo, Venezuela’s export system increasingly pointed to Asia—often indirectly via ship‑to‑ship transfers, intermediaries, and re‑documented origin. Commercial tanker-tracking analyses commonly estimated 60–70% of Venezuelan exports ending up in China in 2020–2021, not because China “needed” the barrels, but because few others could clear the compliance and payment risk at scale.

India: large buyer early in the decade, then pullback. India was meaningful in the 2010–2018 period, but U.S. enforcement pressure and the post‑2022 availability of discounted Russian barrels reduced the incentive for Indian refiners to remain the marginal buyer of Venezuelan heavy crude.

Dark fleet / opaque routing becomes part of the supply function. Post‑2019, the method of export changes the realized value of a Venezuelan barrel. PDVSA’s dependence on gray logistics (STS transfers, AIS gaps, intermediary traders) acts like a tax: it widens discounts and reduces the cash PDVSA can reinvest.

3.3 Chevron’s 2022–2024 effect: visible barrels, modest scale

Chevron’s return under GL 41 (late‑2022) didn’t “solve” Venezuela’s oil problem, but it did create a more transparent, insurable channel for some flows—especially to the U.S.

By late‑2024, observed export totals improved to the ~0.55–0.65 mb/d range (depending on source and month). Public series commonly cited include Statista’s 2023 average near ~550 kb/d and CEIC’s late‑2024 readings around the mid‑600 kb/d range. Reuters/S&P Global reporting also points to Chevron‑linked joint venture production as a material share of the country’s incremental gains in this period.

3.4 Orinoco vs conventional: why “type” matters for ramp scenarios

Granular basin/type data are not published consistently, so any split is modeled, not official. But the directional trend is clear: as conventional provinces decline, the Orinoco Belt’s share rises. A reasonable working range used in industry modeling is:

• Early 2010s: Orinoco roughly ~45–55% of national crude.
• Early 2020s: Orinoco roughly ~65–80%, as conventional output depletes and maintenance failures bite harder.

This matters because Orinoco barrels are extra‑heavy and operationally input‑intensive—they need upgrading or blending, and they are more exposed to diluent constraints and midstream reliability.

3.5 What the supply collapse did to pricing power

The disappearance of Venezuelan heavy sour barrels tightened the global heavy pool. In the U.S. Gulf, fewer Latin American heavy barrels contributed to structurally higher value for replacement grades and changed heavy‑sour crack economics at complex refiners. In Asia, the opposite dynamic emerged: when Venezuela was forced into opaque channels, China’s bargaining power increased, and Venezuelan barrels often cleared only at deep discounts reflecting sanctions and logistics risk.

The main implication for prediction markets: any 2026 scenario needs to start from a system whose binding constraints are commercial and infrastructural, not geological. Barrels can return—but not instantly, and not evenly across crude types or destinations.

If Section 3’s takeaway was that Venezuela’s decline is mostly “above-ground,” this section is the mechanical reason why. Even in a world where OFAC rules suddenly become permissive, PDVSA still has to move extra-heavy Orinoco bitumen through a chain of equipment that is both capital‑intensive and fragile: wells → gathering → blending/upgrading → pipelines → export terminals (and, separately, a refinery system that has struggled to run reliably).

4.1 Orinoco isn’t “just oil” — it’s 8–10° API bitumen

The Orinoco Belt holds an enormous resource base, but much of what comes out of the ground is extra‑heavy crude in the ~8–10° API range. That material is closer to “bitumen” than a conventional export stream. To be exportable at scale, it typically needs one of two treatments:

1. Upgrading: converting extra‑heavy into higher‑API synthetic crude (and/or upgraded blendstock) using coking/hydroprocessing units that are maintenance‑hungry and catalyst‑dependent.
2. Blending: mixing extra‑heavy with enough condensate or light crude (diluent) to reach a transportable/exportable gravity, commonly ~16–22° API blends.

Venezuela built its heavy‑oil strategy around four large upgrader complexes:

• Petromonagas
• PetroPiar
• PetroCedeño
• PetroSanFelix

In theory, these assets are the bridge between Orinoco barrels and a global refinery system. In practice, they’ve often been the bottleneck.

4.2 Upgraders: under-invested, intermittently run, increasingly “blending-first”

A modern upgrader is not like “turning a valve.” It depends on stable power, functioning instrumentation/control systems, rotating equipment reliability, corrosion management, and—critically—foreign catalysts, specialty chemicals, and OEM spares.

After years of under‑investment and sanctions‑era procurement constraints, analysts and trade reporting consistently describe Venezuelan facilities as operating far below potential and facing chronic reliability issues. One operational adaptation has been a shift away from full‑severity upgrading toward simpler blending/partial processing, because blending can tolerate degraded equipment and reduces the need for high‑spec catalysts and hydrogen-intensive units.

The market implication is subtle but important: extra-heavy production can rise for a few months on “hero operations,” but sustaining higher levels requires upgraders to run with acceptable on‑stream factors. That means inspections, turnarounds, and supply chains—none of which are instant even with legal permission.

4.3 Refineries: large nameplate, low realized throughput

Venezuela’s domestic refining system—Amuay and Cardón (Paraguaná), El Palito, and Puerto La Cruz—was historically configured to handle medium/heavy sour slates. But repeated fires, outages, and lack of spares have driven utilization far below what nameplate capacity suggests.

A key technical limiter is hydrogen. Running heavy sour through upgrading and hydrotreating requires reliable hydrogen production and sulfur handling; when hydrogen units, compressors, or critical catalysts are unavailable, refineries are forced to reduce runs or simplify operations. That creates a vicious cycle:

• low utilization reduces revenue and cash for maintenance,
• deferred maintenance raises the probability of another outage.

From a system perspective, weak refining performance also creates a strategic trade‑off: PDVSA must decide whether scarce light barrels and condensate should be used to support domestic fuels production or maximize exportable Orinoco blends.

4.4 The diluent constraint: the hidden ceiling on “rapid ramp” stories

The fastest way to move more Orinoco barrels is usually blending—not full upgrader restoration. But blending is only as scalable as diluent supply.

Venezuela does not reliably produce enough domestic condensate/light crude to blend all incremental extra-heavy output. When financing and sanctions constraints allow, PDVSA has relied on imports (often reported as Iranian condensate/light crude flows) to keep blending programs functioning.

That dependence creates a hard, quantitative ceiling: even if you have wells available, you can’t export heavy without the light.

This rule-of-thumb is why “sanctions relief” is not a single variable. A legal change that allows crude sales but still constrains shipping insurance, trade finance, or condensate procurement can leave production stuck. Conversely, a narrow allowance that reliably enables diluent imports can sometimes lift exports more than headline policy suggests.

4.5 Maintenance backlog: wells to pipelines to turnarounds

Across the chain—wells, gathering systems, pipelines, upgraders, and refineries—PDVSA is working through a long period of deferred turnarounds and integrity management. The risk here isn’t only “lower output.” It is operational volatility: leaks, unplanned shutdowns, and equipment failures that can erase a quarter’s gains in a week.

For traders, this backlog matters because it makes Venezuela’s path lumpy. Prediction markets that imply a smooth linear ramp to a high 2026 level may be overpricing the ease of execution. The system can add barrels, but it typically does so in steps—and those steps are often followed by setbacks when a critical unit fails.

4.6 What it costs—and how long it takes

Analyst ranges converge on a blunt message: modest recovery is affordable; a return to past glory is not.

• S&P Global/CERA-style framing (as reported in industry coverage): getting marketed output up toward roughly ~1.5 mb/d would require “at least several billion dollars” in fresh investment, even assuming a cooperative sanctions environment.
• Moving materially beyond that—toward pre‑2010 capacity levels—requires tens of billions of dollars and multiple years of stable policy, contracting, and supply chains.

Those numbers are consistent with the broader institutional view that Venezuela’s constraint is not reserves, but rehabilitation capital plus time—especially for upgraders, power, and midstream integrity.

4.7 What prediction markets should separate (but often don’t)

Most 2026 prediction markets implicitly bundle two different questions:

1. Legal access: Are companies allowed to finance, service, and lift Venezuelan crude (and to import diluent, parts, catalysts, and chemicals) without sanction risk?
2. Physical ramp: Can PDVSA and partners execute a stable, safe, high on‑stream‑factor ramp through damaged infrastructure?

These variables interact—but they are not the same. Legal permission can unlock financing and inputs, yet upgrader reliability, diluent logistics, and refinery/pipeline integrity are time-bound constraints with real lead times.

If your market is pricing “sanctions relief” as if it automatically implies “fast, sustained production growth,” the mispricing is usually here: Orinoco barrels are manufactured barrels, and manufacturing requires functioning plants, steady diluent, and deferred maintenance paid back with interest.

5. Oil-for-Loans and JVs with China and Russia: Hidden Claims on Future Barrels

Section 4 explained why Venezuela’s “headline production” is constrained by upgraders, diluent, and maintenance. But even if those physical bottlenecks loosen, not every incremental barrel is economically “free.” A meaningful share of future exports is already encumbered—by legacy oil‑backed finance with China, Rosneft-era prepayments with Russia, and newer opaque contracts that effectively re‑pledge future barrels.

5.1 China: large historical lending, smaller—but still binding—remaining claims

China’s role is often simplified as “China buys Venezuelan crude.” In reality, much of the relationship was structured finance.

• Cumulative Chinese lending to Venezuela is widely cited around ~$60 billion over multiple oil‑backed facilities (policy-bank style lending plus related JV capex).
• Estimates of what remains outstanding are lower—but still large relative to PDVSA’s investable cashflow: ~$10–20 billion outstanding is a common band.

Mechanically, oil‑for‑loans works like a senior offtake. PDVSA (often via PDVSA–CNPC structures and marketing entities) earmarks cargoes as “repayment barrels.” Those barrels are valued at contract formulas that often embed discounts, and the realized proceeds net down further because sanctions-era trade adds: (1) extra freight and transshipment, (2) insurance/compliance risk premia, and (3) intermediary margins. The result is simple: each barrel repays less debt per unit than it would in a transparent, insurable market, slowing amortization.

Columbia Energy Exchange-style analyses have described post‑sanctions Chinese debt service as only ~50–100 kb/d worth of crude allocations in recent years—enough to keep the relationship alive, but not enough to rapidly reduce the remaining stock when discounts are wide and costs are high.

5.2 Russia: smaller balances, but “sticky” claims and services-for-oil

Russian exposure is smaller in stock terms but can be more operationally entangling. Russia’s footprint combines:

• state-to-state lending, plus
• Rosneft-related prepayments/offtake structures that provided PDVSA liquidity in exchange for future cargoes.

Remaining Russian claims are often framed around ~$5 billion. After U.S. sanctions targeted Rosneft Trading/TNK Trading, the model shifted away from clean, visible prepayment deals toward more opaque barter and service-for-oil arrangements (e.g., logistics support, field services, or intermediated trading against crude allocations). These structures can behave like debt even when they are not labeled as such: they still subordinate a slice of export revenue to prior commitments.

5.3 Sanctions don’t just reduce volume—they increase “debt barrels” per dollar

Under tighter U.S. enforcement, PDVSA’s traditional repayment channels are disrupted. Payments avoid dollars; cargoes route through gray-market intermediaries, ship‑to‑ship transfers, and relabeled blends. That raises effective transaction costs and forces larger discounts—meaning more barrels must be dedicated to satisfy the same nominal obligation.

A key twist for 2026–2030: Venezuela’s Anti‑Blockade Law (2020) enables confidential contracting. To secure fresh capital and inputs under sanctions, PDVSA can enter opaque deals that re-collateralize future export streams—potentially giving certain counterparties priority on cashflows even if sanctions later ease.

5.4 What this means in net supply terms (the prediction-market translation)

For markets pricing “Venezuela production ≥ X in 2026,” the hidden variable is net exportable supply available to discretionary buyers (spot Asia, Atlantic Basin, or U.S. refiners under licensing).

Even if Venezuela grows into a higher-output band in the late 2020s, a reasonable trading assumption is:

• some portion of incremental barrels will be captured by (a) Chinese debt service/of‑ftake and (b) Russian/Iranian style service-for-oil arrangements, before PDVSA sees cash it can reinvest.

That matters most for prediction markets targeting exports by destination (“U.S. imports from Venezuela,” “exports to China”) or PDVSA cashflow (which can remain weak even as production rises). Headline production can increase while free cashflow and freely marketable exports lag, because the marginal barrel is pledged at a discount.

6. 2026–2030 Production Scenarios: What Analysts Expect from PDVSA

The key for prediction-market traders is to stop treating “sanctions relief” as an on/off switch and start treating it as a path—because most institutional and sell‑side outlooks effectively converge on one idea: Venezuela can add barrels, but sustained gains are gated by investment, contracting, and infrastructure lead times.

Across IEA/EIA-style “continuation” baselines, OPEC reference paths, and consultant/bank upside cases (Rystad/WoodMac/JPMorgan), the 2026–2030 range can be framed cleanly as three tradable scenarios. The difference between them isn’t geology; it’s policy stability + investable cashflow + execution.

Scenario A — Status Quo / Limited Easing

This is the world where PDVSA remains constrained by recurring OFAC noise (waivers, wind‑downs, short renewals), limited access to trade finance and OEM supply chains, and a JV model that’s mostly maintenance/debottleneck rather than expansion.

• Analyst anchor: desks citing IEA/EIA-style assumptions and conservative bank work tend to keep Venezuela sub‑1.0 mb/d through the mid‑2020s.
• Numerically: think ~0.8–0.9 mb/d in 2026, with only modest gains to ~0.9–1.1 mb/d by 2030.
• Why it caps out: incremental volumes arrive via workovers, short-cycle repairs, and intermittent diluent availability—not through a sustained drilling + facilities rebuild cycle.

For prediction markets, this is the “most likely” path if licenses remain reversible and if capital remains trapped behind compliance risk.

Scenario B — Managed Opening (Partial, Stable Relief)

Here, the U.S. allows a clearer, longer-dated channel for investment and exports—something closer to a durable “Chevron‑type JV template,” potentially with additional partners—but still short of full normalization.

• Mechanism: partial, stable sanctions relief; more predictable diluent imports; more service-sector participation; incremental midstream/upgrader rehabilitation; and a marketing structure that widens the buyer set beyond gray channels.
• Numerically: production can plausibly climb into ~1.2–1.5 mb/d by 2030 (with 2026 often still near ~0.9–1.1 mb/d because projects need time to translate into barrels).

This scenario is consistent with the idea that Venezuela can recover meaningfully without “miracle” reforms—but it still requires multi‑year policy credibility so contractors will mobilize, and so partners will fund power, integrity work, and upgrader reliability.

Scenario C — Full Reform & High Investment

This is the upside case traders love—and forecasters label as possible but conditional. It assumes broad sanctions relief plus deep changes that make Venezuela investable at scale: credible contract terms, arrears resolution, operating autonomy, and security/logistics normalization.

• Near-term upside anchor: JPMorgan analysts cited by Reuters have suggested ~1.3–1.4 mb/d within about two years under meaningful easing and investment.
• Late-decade potential: some bullish frameworks (e.g., Rystad-style “rebuild” narratives) contemplate ~2.0–2.5 mb/d later in the decade, but only if Venezuela sustains roughly $8–9 billion per year of capex and executes major infrastructure restoration.

The prediction-market translation: a “full relief” headline is not enough—the capital program has to be big, sustained, and protected from political reversals.

The overlooked constraint: policy-to-barrel time lags (18–36 months)

Even in the best case, sanctions decisions don’t instantly produce exports. The physical ramp depends on cycles that typically take 18–36 months to show up as stable incremental output:

• drilling/workover programs and equipment mobilization;
• upgrader overhauls and turnaround backlogs;
• pipeline integrity repairs and power-system fixes;
• diluent contracts, shipping/insurance re‑rating, and marketing re‑papering.

That lag is why high 2026 production targets require not just “a deal,” but a deal early enough for the field system to respond.

From production to exports: what’s actually available to the water

Exports are what markets feel. A simple way to map scenarios is to net out ~0.2–0.3 mb/d of domestic demand (fuels + internal system needs), recognizing that refinery volatility can swing this.

• Status Quo (2030): ~0.9–1.1 mb/d production → ~0.6–0.8 mb/d exports
• Managed Opening (2030): ~1.2–1.5 mb/d production → ~0.9–1.3 mb/d exports
• Full Reform (late‑decade bullish): ~2.0–2.5 mb/d production → ~1.7–2.3 mb/d exports

This is also where Section 5’s “encumbered barrels” matter: even if headline exports rise, some flows may be pre-committed (debt service, services-for-oil), reducing discretionary spot supply.

Market impact: heavy crude spreads, balances, and OPEC+ reactions

Venezuelan crude is predominantly heavy/sour. More supply tends to soften heavy crude differentials (e.g., competing with Latin heavy grades and pressuring heavy-sour cracks), while also shifting OPEC+ strategy. If Venezuela grows into the 1.2–1.5 mb/d band, OPEC+ can often absorb it via quota management elsewhere. If it approached 2.0+ mb/d quickly, the marginal impact is larger: global balances loosen, heavy spreads compress, and OPEC+ cohesion is tested—feedback loops that prediction markets frequently underprice.

7. Policy Pathways: U.S. Sanctions Choices, Venezuelan Politics, and OPEC Dynamics

By 2026, Venezuela’s production path isn’t determined by “oil price” so much as by policy credibility—whether counterparties believe today’s rules will still hold 18–36 months from now (the lag you need for services, parts, and plant reliability to show up as sustained barrels). The policy tree has three branches that prediction markets can actually track.

7.1 U.S. decision points through 2026: licenses, relief-for-benchmarks, and enforcement

(1) Chevron / sectoral license posture: Markets should distinguish “a license exists” from “a license is investable.” A renewal that looks like short-dated wind-down language (or frequent amendments) keeps suppliers cautious and prevents the financing and contractor mobilization needed for a durable ramp.

(2) Broader relief tied to governance benchmarks: Washington has already demonstrated a playbook: broader openings can be conditional and reversible. If the U.S. reverts to an “elections/governance benchmarks” framework, odds should hinge on verifiable milestones (electoral access, political prisoners, independent institutions), not on diplomatic tone.

(3) Secondary-sanctions enforcement on shippers/buyers: Even without new executive orders, the U.S. can tighten the regime by targeting shipping networks, traders, insurers, and payment rails that “materially assist” PDVSA. That tends to reduce realizable exports and widen discounts—even if production inches up.

7.2 Venezuelan political scenarios: contract credibility is the binding constraint

The physical system needs investment, but capital only arrives when contracts are enforceable. Three internal regimes matter for market pricing:

• Durable post‑Maduro transition: The upside isn’t “privatization overnight,” it’s legal stability: credible arbitration, transparent terms, and autonomy for JVs and service providers. This is the only pathway that materially increases the probability of structural reforms at PDVSA and large multi‑year capex.
• Elite fragmentation: Policy becomes hostage to factional bargaining. In practice, this raises expropriation/renegotiation risk and increases payment frictions—keeping IOC activity in “short-cycle repairs” mode.
• Authoritarian retrenchment: Even if barrels can move via opaque channels, the investable set of partners shrinks. You can get episodic output gains, but contract credibility and procurement remain brittle.

7.3 U.S. politics and the Iran/Russia lens

Venezuela is often treated as a “geopolitical balancing barrel” when Washington wants flexibility against Iran/Russia disruptions. But that appetite is cyclical: it rises when global spare capacity looks tight, and collapses when domestic politics prioritizes “maximum pressure” signaling. In other words, Venezuela’s 2026 supply is partly an output of how the U.S. frames sanctions as a tool across multiple theaters—not only Caracas.

7.4 OPEC+: Venezuela’s incentive is capacity; OPEC’s incentive is price management

OPEC has a long-run incentive to keep Venezuela as a latent capacity holder, but OPEC+ as a group has a near‑term incentive to avoid a disorderly ramp that weakens prices. If Venezuela were to surprise to the upside, the most likely OPEC+ response is quota rebalancing elsewhere (or pressure on Venezuela to “self-manage”), rather than welcoming a free-for-all increase.

7.5 Regulatory/ESG constraints: even with relief, capital may not rush in

Even under sanctions relief, Western capital faces tighter climate policy, methane scrutiny, and investor pressure—especially for long‑dated, heavy‑oil projects with large scope‑1/2 emissions and upgrader/refinery linkages. That doesn’t kill the upside scenario, but it lowers its probability versus what “headline reserves” narratives imply.

Prediction markets around Venezuela tend to look “binary” on the surface (license renewed: yes/no), but the tradable reality is a bundle: legal authorization → financing/services → inputs (especially diluent) → plant reliability → exportable barrels. That chain is why the cleanest Venezuela contracts fall into a few repeatable families—and why mispricings often show up when traders skip the 18–36 month lag between a sanctions headline and durable supply.

The core contract types (and how to read them)

A) Headline production thresholds (2026–2027). These are the flagship “macro barrel” markets: “Venezuela crude production ≥ 1.0 / 1.2 / 1.5 mb/d in 2026” or “average 2027 production above X.” They’re attractive because they’re simple, but they’re also the most path-dependent: hitting ≥1.2 mb/d by 2026 is not just “more wells,” it’s diluent logistics + upgrader/blending uptime + export-terminal throughput (Sections 4–5).

B) Broad U.S. sanctions relief by date. These contracts usually settle on an observable legal state: “OFAC issues broad oil-and-gas general license (GL 44-type) by Dec 31, 2025” or “PDVSA removed/relieved from SDN blocking in 2026.” The key is to define relief precisely: broad sectoral authorization is very different from a narrow Chevron-type carve-out.

C) Chevron JV activity (license status + output/exports). Natural markets include “Chevron Venezuela authorization extends beyond wind-down” and “Chevron JV exports to U.S. exceed X kb/d in 2026.” These are often higher-signal than national production because JV flows are relatively observable and directly tied to U.S. policy.

D) Export destinations (U.S. vs China). Markets like “U.S. imports from Venezuela average ≥150 kb/d in 2026” or “China share of Venezuelan exports ≥60% in 2026” translate sanctions regimes into trading reality. Post‑2019, a large share of exports ended up in China (often indirectly), with commercial trackers frequently estimating ~60–70% in 2020–2021; by 2023–2024 total exports were roughly ~550–650 kb/d (Statista/CEIC).

E) PDVSA default/restructuring milestones tied to oil flows. These are “credit-through-oil” contracts: “PDVSA announces restructuring framework by 2026” or “CITGO/PDV Holding litigation milestone by date.” They matter because sustained export normalization is one of the few pathways to a credible restructuring offer.

Flagship markets: translating odds into scenario probabilities

SimpleFunctions readers should treat the live board as the source of truth. The examples below show the translation step (replace the example probabilities with live odds).

If a market prices P(≥1.2 mb/d in 2026) ≈ 35%, it is implicitly assigning something like a ~30–40% weight to the “Managed Opening” path from Section 6—despite the physical ramp constraints and lag structures.

Conversely, if a market prices P(broad relief by end‑2025) ≈ 25%, it may still be compatible with P(≥1.2 mb/d in 2026) < 25% because even broad relief in late‑2025 typically cannot create stable incremental barrels by 2026 without front‑loaded mobilization.

Where markets often look too optimistic (or too pessimistic)

1) Conflating legal change with immediate barrels. Analysts who model Venezuela conservatively (IEA/EIA-style baselines and bank base cases) keep Venezuela around ~0.8–0.9 mb/d in 2026 (Goldman’s base case is ~0.9 mb/d). To beat that meaningfully by 2026, traders must believe policy clarity arrives early enough for the system to respond—while still clearing diluent and upgrader constraints.

2) Overpricing smooth ramps. Venezuela’s system is “lumpy”: maintenance backlogs and upgrader reliability create step-changes and reversals. A threshold market can look cheap until you price the probability of a single multi-month outage.

3) Underpricing correlation risk. Venezuela odds are not independent of: (a) U.S. election dynamics, (b) the U.S. posture toward Iran/Russia barrels, and (c) global spare capacity. Traders can structure hedges by pairing Venezuela supply-upside positions with global oil price downside protection.

Binary vs continuous: a practical scoring rule

• Binary policy markets (license renewed / broad GL issued) are best treated as event timing bets.
• Production/export markets are distribution bets with embedded lags. A useful discipline is to force a two-step model: P(policy) × P(execution | policy). Many boards implicitly treat execution as ~1.0, which is exactly where physical-constraint mispricings emerge.

Liquidity and structural risk

Venezuela markets can be thin. In low liquidity, odds often anchor to the last headline (license rumor, election news) and stay stale. A trading thesis should explicitly include a “staleness discount”: require a larger edge versus your fair value, and size positions assuming wider spreads and slower convergence.

9. Data-Driven Signals: Linking Sanctions, Rigs, Chevron Exports, and Market Prices

Prediction markets often move on the headline (“OFAC eases/tightens”), but Venezuela supply moves on the plumbing: rigs, workovers, diluent logistics, upgrader uptime, and who can legally lift barrels. You don’t need a fancy model to trade this—just a clean set of time series and a repeatable “policy shock → physical response” checklist.

9.1 The core quantitative series to track (and why)

Build one monthly panel with these columns:

1. Production (kb/d)

• OPEC MOMR (secondary sources): market-standard, monthly.
• Cross-check with EIA/IEA when available.

2. Exports (kb/d)

• Tanker-tracked exports (Kpler/Vortexa/Refinitiv-style datasets): best for timing and destination shifts.
• CEIC/Statista aggregates: good sanity checks (less granular).

3. Chevron channel (kb/d)

• Chevron JV output (reported in trade press) and EIA U.S. imports from Venezuela (hard, official series).
• This is the cleanest “licensed barrel” proxy because it’s more observable than most PDVSA trade.

4. Activity / constraints

• Rig count / completion activity (Baker Hughes-style or local proxies): directionally signals whether the system is actually mobilizing.
• Where available: upgrader/refinery outage notes, power disruptions, diluent import indicators.

5. Pricing signals

• Heavy-sour differentials/cracks (e.g., Latin heavy vs Gulf benchmarks): these often react faster than OPEC production prints.

6. Event dates

• Sanctions and licensing milestones (2017 financial sanctions; 2019 SDN; 2022 GL 41; 2023 GL 44; 2025 GL 41A/41B wind-down).

The goal isn’t to “forecast Venezuela” perfectly—it’s to create thesis checks: If the market is buying a big 2026 ramp, are rigs, diluent access, and export channels confirming it?

9.2 Example “regime shift” charts traders should keep on one dashboard

Three charts capture most of the story:

• Chart A: OPEC secondary-source production vs time, with vertical lines at key OFAC shifts. You typically see step-changes rather than smooth trends.
• Chart B: tanker-tracked exports vs time, split by destination (U.S. vs China/Asia). This highlights how 2019 pushed flows into opacity and how 2022–2024 brought some barrels back into a visible U.S. channel.
• Chart C: heavy-sour differential vs time (choose one consistent spread). The pricing response can precede the volume response, especially when buyers start to anticipate compliance tightening or loosening.

A simple read: when policy tightens, the first signals often show up as wider discounts and messier routing, then later as lower exports/production (with months of lag).

9.3 A simple event-study framework (good enough for trading)

Define events as specific, timestamped policy shocks. For each event e:

1. Compute baseline averages of output/exports in [-6, -1] months.
2. Measure changes in [+6, +12] and [+12, +24] months windows.
3. Run the same on Chevron-linked series (JV output, U.S. imports) to see whether the “licensed channel” reacts differently.
4. Overlay prediction market pricing: measure price change in [-30, +30] days around the announcement and compare it to the later realized physical delta.

This lets you test a common behavioral pattern: markets often overreact immediately to legal headlines, then underreact to long lags (18–36 months) that determine whether barrels actually arrive.

9.4 Chevron JV volumes: leading indicator, until wind-down makes them lag

In 2023–2024, Chevron-linked flows often behaved like a leading indicator for “sanctions-permitted barrels,” because they were among the few that could move with insurance and a clear buyer (the U.S.). But under a 2025–2026 wind-down regime, Chevron volumes can flip to a lagging indicator:

• If wind-down forces activity into “maintenance/decline mode,” JV exports may fall even while PDVSA tries to compensate via opaque channels.
• In that world, tanker-tracked exports to Asia (and widening discounts) may better capture “true activity,” while U.S. imports understate total exports.

9.5 Practical workflow for prediction-market traders

A disciplined weekly process:

1. Start with a baseline: take conservative consensus (e.g., desks that keep 2026 near ~0.9 mb/d in status quo paths).
2. Overlay constraints: diluent availability, upgrader outages, logistics/insurance tightening.
3. Score policy credibility: short-dated licenses and wind-down language should reduce your “execution conditional on policy” factor.
4. Translate into probabilities: when market odds imply a ramp that requires an immediate activity pickup (rigs/services/diluent) you don’t see, treat it as a candidate short.
5. Use scenario bands: trade distributions (0.8–0.9 / 0.9–1.1 / 1.1–1.3 mb/d) instead of point estimates.

9.6 Data caveats (and how to trade with them)

• Tanker tracking is noisy (AIS gaps, STS transfers, relabeling). Use 3‑month averages.
• OPEC secondary sources revise and may lag reality. Treat it as “official consensus,” not ground truth.
• Condensate/diluent flows are partially unobservable, yet they can be the binding constraint. Use proxy indicators and widen scenario bands when diluent is uncertain.

The edge comes from being systematic: if your dashboard says policy noise is rising but the physical series aren’t confirming a ramp, don’t let headline-driven market prices do your thinking for you.

With the dashboard from Section 9 in place, the next step is to turn “Venezuela in 2026” into tradable questions you can size, hedge, and update. The goal isn’t a heroic point forecast—it’s a repeatable workflow that forces you to separate (1) legal regime changes from (2) 18–36 month physical execution, and then price the gap.

A step‑by‑step framework (works on any venue)

1. Pick one settlement rule you can defend. Start with a single contract: e.g., “2026 average crude production ≥ 1.2 mb/d” (OPEC secondary sources) or “broad OFAC oil-and-gas relief by Dec‑2025.” Read the market’s resolution criteria before you model anything.

2. Map the contract to the scenario tree. Use the three scenarios from Section 6 (Status Quo / Managed Opening / Full Reform), but translate them into the contract’s exact measurement window. As a sanity check, note where conservative institutional baselines sit: Goldman has framed a base case around ~0.9 mb/d in 2026 under continued constraint.

3. Assign your own probabilities—explicitly as a conditional chain. A clean way is:

• P(policy change by date) × P(execution | policy) × P(no major outage). This is where markets often “cheat” by implicitly setting execution ≈ 1.

4. Compare to implied odds and demand an edge premium. Venezuela contracts are often thin; require a wider margin of safety than you would in liquid election markets. Size accordingly (smaller unit size, staged entries, and hard caps on total exposure).

Expressing views on timing (using markets jointly)

Timing is where spreads and “calendar logic” show up:

• A market like “broad sanctions relief by end‑2025” is mostly about politics/OFAC.
• A market like “output ≥ X mb/d in 2027” is policy plus the physical lag.

If your thesis is “relief might arrive late, but barrels can’t ramp fast,” you’d expect sanctions‑relief odds to be higher than high‑threshold production odds, and the gap to persist. If the board prices them as near‑equivalents, that’s a classic misalignment candidate.

Don’t confuse ‘more output’ with ‘more free barrels’

China/Russia oil‑for‑loans and services‑for‑oil can absorb early incremental production. Estimates commonly place remaining China exposure around ~$10–20B and Russia around ~$5B, with reported debt-service flows sometimes only ~50–100 kb/d—and at sanctions-era discounts. Translation: even if production rises, PDVSA’s discretionary, cash‑generating exports can lag—which matters for destination markets (U.S. vs China) and any cash‑flow proxy contracts.

Common pitfalls to bake into risk management

• Overestimating ramp speed (upgraders, power, pipelines, and workover capacity don’t scale instantly).
• Ignoring diluent constraints (the hidden ceiling on Orinoco blends).
• Underweighting OPEC+ behavior (a surprise ramp can trigger compensating cuts elsewhere).
• Assuming Western IOCs move like 2010–2014 (today’s ESG, compliance, and contract-risk reality is different).

Examples of thesis-driven positioning (illustrative, not advice)

• Underpriced re‑tightening risk: if odds imply a smooth opening, but enforcement headlines and shipping designations rise, a trader might favor “no broad relief by end‑2025” or fade aggressive production thresholds.
• Overhyped 2.0 mb/d narratives: if a contract implies a rapid return toward pre‑sanctions levels, stress-test it against the 18–36 month lag and outage risk.
• Chevron-volume vs relief mismatch: if “broad relief” is priced high but “Chevron/U.S. lift volumes” are priced low (or vice versa), that divergence can be a signal that the market is conflating narrow licenses with sectoral normalization.

Updating probabilities fast

Pre‑commit triggers that force you to revise: election outcomes, new OFAC GLs/specific licenses, a major JV capex announcement, or an upgrader/pipeline incident. Update the chain (policy → execution) rather than whipsawing your whole view.

Venezuela’s base reality hasn’t changed: it has world‑class geological endowment, but a production system that has been hollowed out by years of underinvestment, outages, and procurement constraints. U.S. sanctions have oscillated between maximum pressure and tightly controlled openings (notably Chevron’s carve‑out), and the 2025 shift to a Chevron wind‑down posture is a reminder that reversibility is the central variable traders must price.

For prediction‑market participants, the clean way to hold the narrative in your head is: there is upside to production in 2026–2030, but it is constrained, path‑dependent, and not automatically monetizable.

The 5 insights worth retaining (and trading)

1. Legal relief ≠ instant barrels. Even broad OFAC action needs time to translate into rigs, workovers, parts, diluent contracts, and reliable upgrader/blending uptime.
2. Chevron’s channel is a policy thermometer. A wind‑down regime should be read as “maintenance/decline bias” for the most transparent barrels, even if PDVSA tries to offset via opaque exports.
3. The marginal barrel may already be spoken for. China’s remaining claims (commonly framed at ~$10–20B) and Russia’s (~$5B) plus services‑for‑oil arrangements can absorb early incremental volumes; some analyses estimate only ~50–100 kb/d has been allocated to Chinese debt service in recent years, implying slow amortization at sanctions-era discounts.
4. Diluent and plant reliability are the hard ceilings. Extra‑heavy Orinoco supply is “manufactured” supply: without stable diluent imports and functioning plants, upside scenarios revert.
5. Expect lumpy outcomes. Venezuela’s system tends to move in step‑changes (repairs, then setbacks), which makes threshold‑style prediction contracts especially sensitive to outage risk.

A concrete watchlist: leading indicators that move 2026 probabilities

• OFAC posture: new GLs, amendments, specific licenses, enforcement actions (shipping/trading).
• Venezuelan political stability: cabinet/PDVSA leadership churn, protest/elite‑split signals, election‑rule changes.
• FDI/JV announcements: capex commitments with long lead times (power, pipelines, upgraders), not just MOUs.
• Service activity: rig counts, workover intensity, oilfield service company re‑entry, diluent import visibility.
• Exports (tanker‑tracked): 3‑month avg export levels and destinations; late‑2024 exports were reported around the mid‑600 kb/d range (e.g., ~656 kb/d in Dec‑2024 via CEIC).
• OPEC rhetoric and quota signaling: any indication Venezuela is being “re‑integrated” into quota discipline.

The surprise events markets underprice

• Abrupt U.S. re‑tightening (designations/enforcement) or a broader, longer‑dated opening that makes multi‑year capex investable.
• Faster‑than‑expected infrastructure rehabilitation (power + upgrader uptime) that turns short bursts into sustained output.
• A credible PDVSA restructuring that changes cashflow routing and JV bankability.
• New oil‑for‑loan or services‑for‑oil deals that change net supply available to open buyers (even if headline production rises).

Prediction markets are useful here because they convert headlines into a live probability curve. But the edge comes from forcing a two‑step model—P(policy) × P(execution | policy)—and updating it with observable field and export data. Venezuela’s story will keep producing narrative noise; disciplined tracking of licenses, activity, and barrels is how you identify mispricings as beliefs shift into 2026 and beyond.