FINWIRES · TerminalLIVE
FINWIRES

US-Venezuela Oil Agreement Sparks Growth, Execution Risks, Analysts Say

By

The US finalized an energy agreement on Monday with Venezuela granting US authorities governance rights and a 35% equity stake in North American Blue Energy Partners, a private operator awarded a 100-year concession for 17 strategic developments holding roughly 65 billion barrels of recoverable crude.

Announced via a White House fact sheet the pact gives the US Department of State a guaranteed 20% offtake at production cost alongside a right of first refusal for the remaining output.

The framework is governed by US law, includes strict US board majorities and veto powers, and marks a sweeping geopolitical reorientation that explicitly displaces Chinese and Russian influence from the region.

While the deal bypasses traditional constraints to secure Western hemispheric energy supplies, industry analysts emphasize that production recovery will be gradual and fraught with hurdles.

Rystad Energy noted that near-term output will be brownfield-led, scaling from roughly 157,000 barrels per day in 2027 to 680,000 bpd by 2030 as existing wells and infrastructure are rehabilitated.

Significant greenfield development in the Orinoco Belt supported by a projected $100 billion capital expenditure plan from NABEP is not expected to become meaningful until around 2035, with total output potentially reaching 3 million bpd by 2050 under optimal conditions, Rystad said.

Execution and political continuity remain core concerns for energy markets.

The agreement has drawn domestic pushback from both Chavista and opposition figures in Venezuela, raising long-term contractual risks for international investors regarding whether future governments will honor the century-long terms.

Rystad analysts said that "investors looking at multi-decade projects need confidence that a contract signed today will be honored by whoever governs Venezuela in ten or twenty years."

Furthermore, while proposed fiscal adjustments such as a 16% minimum royalty and a 34% corporate tax rate, improve project breakevens by 7% to 13%, analysts caution that Venezuela must still overcome severe operational bottlenecks, rig shortages, and regional competition to establish durable global cost competitiveness.

What else is happening in Commodities?

Commodities

Venezuela Oil Deal May Boost US Refiners as Heavy Crude Supply Rises, TPH Says

The US-Venezuela oil deal could boost heavy crude supplies for US refiners and widen discounts on heavy grades, TPH Energy Research said in a Monday note.US refiners processed 18.3 million barrels per day this year, including 4 million b/d of heavy crude from foreign suppliers, TPH Energy Research said.Heavy crude imports fell from 4.5 million b/d during 2016 to 2018, but Venezuela increased US shipments to 341,000 b/d from 140,000 in 2025.Venezuelan shipments reached 471,000 b/d in May 2026, accounting for about one-third of the country's 1.1 million b/d of production, according to the note.Valero Energy (VLO) led Venezuelan crude imports at 137,000 b/d, up from 69,000 in 2025, followed by Chevron (CVX) at 52,000 b/d and Phillips 66 (PSX) at 46,000 b/d, TPH said.Citgo imported 29,000 b/d and PBF Energy (PBF) took 24,000 b/d, while third-party traders Vitol and Trafigura handled 40,000 barrels per day, some of which could reach US refiners.Additional heavy crude supply could widen discounts, with Maya and Western Canadian Select at Houston trading $11 per barrel and $14/bbl below Brent, versus $8/bbl and $7/bbl in 2025, TPH said.

$CVX$PBF$PSX$VLO
Commodities

Indonesia Should Embrace Least-Cost Power Planning as Coal Costs Rise, IEEFA Says

Indonesia should shift to least-cost electricity planning as renewable energy becomes cheaper than coal, supporting the country's 100-gigawatt solar program, the Institute for Energy Economics and Financial Analysis said in a Friday note.The report urges Indonesia to update its Electricity Supply Business Plan, or RUPTL, using current generation costs, fuel risks, financing conditions and regional market differences.Indonesia announced the 100 GW solar program in June 2025 and President Prabowo Subianto formally launched it Aug. 25, 2026, according to the note.IEEFA said Indonesia should integrate the solar initiative into its broader power strategy rather than treating it as a standalone target, thereby enabling renewables to reduce costs and improve energy security.The report also calls for the earlier retirement of inefficient fossil-fuel plants, particularly coal-fired power plants, to free up grid capacity, reduce subsidies, and accommodate additional renewable generation.Coal generation costs climbed 46% from 637 Indonesian rupiah ($0.03) per kilowatt-hour in 2020 to 930 Indonesian rupiah/kWh in 2025, while IEEFA projects costs could reach about 1,060 Indonesian rupiah/kWh in 2026.The report said Indonesia's domestic coal pricing policies obscure the actual economics of coal power, limiting the ability of renewable projects to compete on an equal basis.Without the Domestic Price Obligation, coal generation would have cost 1,455 Indonesian rupiah/kWh in 2025, 56% above the 930 Indonesian rupiah/kWh cost under the regulated pricing system, IEEFA estimated.Levelized costs also favor renewables, with coal ranging from 10 US cents/kWh to 15.1 US cents/kWh, compared with 5.6 to 8.4 US cents/kWh for utility-scale solar photovoltaic projects.Onshore wind carries an estimated cost of 6.8 to 10.3 US /kWh, while gas ranges from 14 to 21 US cents/kWh, making gas the costliest fossil-fuel option.IEEFA estimates utility-scale solar costs are about 44% lower than coal, while onshore wind costs roughly 32% lower, highlighting the changing economics of new power generation.Higher fossil-fuel costs and currency swings have increased pressure on Indonesia's national utility, PT Perusahaan Listrik Negara, or PLN, as regulated consumer tariffs fail to cover rising electricity supply expenses.Consumers paid an average retail tariff of about 1,112.69 Indonesian rupiah/kWh in 2025, while PLN's generation cost plus business margin reached 1,785.64 Indonesian rupiah/kWh, according to IEEFA.Government subsidies and compensation covered the resulting shortfall, with those payments rising sharply from 65.9 trillion Indonesian rupiah in 2020 to 200 trillion Indonesian rupiah in 2025, the analysis said."Leveraging least-cost planning and competitive procurement would allow Indonesia to diversify away from coal and gas while reducing long-term generation costs and easing financial pressure on PLN and the government," said IEEFA's Energy Finance Specialist, Randi Bachtiar.Eastern Indonesia offers particularly large savings opportunities, as Maluku, Papua, West Nusa Tenggara and East Nusa Tenggara rely heavily on costly diesel generation across smaller power systems.IEEFA said utility-scale solar combined with battery energy storage systems can already undercut diesel generation in those regions while providing dependable power beyond daylight hours.Replacing diesel with renewable generation could also reduce fuel imports and exposure to volatile commodity prices, while isolated systems can make the switch without major transmission investments, IEEFA said."Replacing diesel generation with renewable energy offers multiple benefits: lower generation costs, reduced fuel imports, greater energy security, and less exposure to volatile fuel markets," said IEEFA's Energy Finance Analyst, Yusuf Kresna.The RUPTL 2025-2034 already targets 42.6 GW of renewable capacity and 10.3 GW of energy storage by 2034, alongside transmission investment, according to the report.IEEFA recommends directing new solar and storage projects toward high-cost regions, while using competitive procurement, bankable power purchase agreements and clearer regulations to attract private investment and reduce Indonesia's long-term electricity costs.

Commodities

US Power Update: US Wholesale Power Prices Mostly Higher; SPP Intraday LMP Hits $1,910.34/MWh

US wholesale electricity markets were mostly higher Monday afternoon, with Southwest Power Pool's intraday high touching $1,910.34 per megawatt-hour, according to data from GridStatus.io.Electric Reliability Council of Texas' real-time locational marginal price stood at $38.55/MWh at 4 p.m. ET. Net load was 48.33 gigawatts, with natural gas making up the largest share of the generation mix at 38.5%.California Independent System Operator's real-time LMP came in at $23.75/MWh at 4 p.m. ET. Net load was 0.9 GW, while solar led the generation mix at 60.5%.SPP's real-time LMP reached $51.43/MWh at 4 p.m. ET. Net load totaled 46.38 GW, with natural gas comprising the largest portion of the generation mix at 42.1%. Prices climbed to an intraday peak of $1,910.34/MWh at 2:40 p.m. ET.PJM's real-time LMP was $33.81/MWh at 4 p.m. ET. Net load stood at 122.42 GW, while gas represented the largest share of the generation mix at 44.9%.Midcontinent Independent System Operator's real-time LMP came to $42.46/MWh at 4 p.m. ET. Net load was 93.75 GW, with natural gas supplying the largest share of the generation mix at 35.3%.New York Independent System Operator's real-time LMP stood at $43.42/MWh at 4 p.m. ET. Net load reached 20.75 GW, with dual fuel accounting for the biggest portion of the generation mix at 31.4%.ISO New England's real-time LMP was $43.79/MWh at 4 p.m. ET. Net load came in at 13.87 GW, with natural gas making up the largest share of the generation mix at 53%. The market reached an intraday high of $98.13/MWh at 2:05 p.m. ET.Ontario's Independent Electricity System Operator's real-time LMP reached $49.07/MWh at 4 p.m. ET. Net load was 18.94 GW at 3:55 p.m. ET, with nuclear providing the largest share of the generation mix at 44.6%. Prices touched an intraday peak of $123.63/MWh at 1:55 p.m. ET.The National Weather Service's Climate Prediction Center forecasts temperatures to remain above normal across much of the central and eastern US from Sep. 8 to Sep. 14, with near-normal readings across parts of the West.