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Why this Saturday is different

Every other issue of this newsletter teaches a company. This one teaches a skill, and the company is only the case study. The skill is valuation, the actual mechanical process of turning production numbers, pricing data, and cost structure into a defensible answer for what a business is worth, the same discipline Buffett has practiced across sixty years of shareholder letters. Most retail investors never learn this process. They learn to read a headline instead, a delivery beat, a margin miss, a price target from an analyst whose model they never see, and they call that investing. This issue opens the model itself, states every assumption out loud, and shows the arithmetic connecting each one to the next, so that by the end a reader can rebuild this exercise on any company they choose, oil and gas or otherwise, using nothing but a 10-K and a calculator.

The company chosen for this lesson is Tesla, and the constraint chosen for this lesson is discipline. A retail investor pulls up Tesla’s market capitalization on a Saturday morning, sees a number above one point four trillion dollars, and assumes that figure represents cars. It does not. Somewhere inside that number sits a humanoid robot that has never generated a rupee of revenue, a robotaxi network still waiting on regulatory approval in every jurisdiction that matters, and a full self driving promise that has been eighteen months away for a decade. Strip every one of those bets out of the picture entirely, value nothing but the business of building and selling automobiles, and a very different number emerges. This issue builds that number from scratch, using nothing but disclosed production capacity, real pricing data, and an honest accounting of what it actually costs to run the car business alone.

The rule this issue follows

No credit for Optimus. No credit for robotaxi. No credit for full self driving as a standalone software business. And critically, no cost charged against the car business for building any of those three things either. A valuation that excludes a moonshot’s revenue while still charging that moonshot’s research spend against the core business is not a disciplined valuation. It is a car business punished for sins it did not commit. Tesla does not disclose research and development spend by project, so this issue states its allocation assumption openly rather than hiding it inside a clean looking number, the same way Buffett refuses to value what a company will not show him the cost of.

Production, built from steel rather than slogans

Management has repeated a target of twenty million vehicles a year by 2030 since 2022. That number is not a forecast. It is a speech. Tesla’s own Q4 2025 shareholder disclosure lists installed capacity by factory, not by press release, and adding those figures gives a real base to build from. Fremont carries roughly one hundred thousand units for Model S and X history plus over five hundred fifty thousand for Model 3 and Y. Shanghai carries over nine hundred fifty thousand. Berlin carries over three hundred seventy five thousand. Texas carries over two hundred fifty thousand for Model Y plus over one hundred twenty five thousand for Cybertruck. Total installed capacity today sits near two point three five million vehicles a year, against an actual 2025 output of one point six five million, meaning the company is currently running under its own ceiling rather than against it.

Independent trackers who build bottom up production models from supply chain checks rather than management commentary, the same community that estimated Tesla’s second quarter deliveries closer to the actual result than Tesla’s own analyst consensus did, treat battery cell output as the real constraint behind any capacity number, not floor space or robotic arms. Layer known expansion, Shanghai Phase 3, a pending second approval at Berlin, against that battery ceiling, and a defensible 2030 production range lands between three million and three point five million vehicles a year. That is the number this issue values. Not twenty million.

The price the market will actually pay

Average selling price is not a constant you pull from a brochure. It is what the market clears at once Chinese competition and price sensitive buyers enter the picture, and the direction has been down for years, not up. Model 3 starts at thirty six thousand nine hundred ninety dollars and climbs to fifty four thousand nine hundred ninety at the performance trim. Model Y sits in a similar band. Those two nameplates alone carry roughly ninety seven percent of total volume, so blended ASP is almost entirely their story, and the trend inside that story is one of continued quarter over quarter decline through 2025 and into 2026, driven by the loss of the federal tax credit after September 2025, aggressive price cuts to defend share against BYD’s two point two six million units sold globally in 2025, and the launch of lower cost Standard trims built specifically to hold volume at a lower price point. A 2030 blended ASP near thirty five to forty thousand dollars is the honest assumption, not a rebound toward the mid forty thousands Tesla commanded a few years ago.

Multiply the low end, three million units at thirty five thousand dollars, and the high end, three point five million units at forty thousand dollars, and 2030 automotive revenue lands in a range of one hundred five billion to one hundred forty billion dollars. Call the midpoint roughly one hundred twenty billion.

Margin, built on a real cost curve

Q1 2026 showed total gross margin of twenty one point one percent. Battery pack cost is the largest input sitting behind that number, and it has genuine room to fall further. Lithium iron phosphate adoption, the 4680 cell ramp, and cathode chemistry shifting away from expensive nickel and cobalt have already pulled cost down meaningfully, and the manufacturing thumb rule behind that trend, roughly a fifteen percent cost reduction for every doubling of cumulative production, is not folklore. It comes from Boston Consulting Group’s experience curve research from the 1970s, and automobiles historically sit toward the lower end of that band given how much of the cost base is labor and steel rather than something that compresses like a semiconductor. Apply that curve against a near doubling of cumulative production between today and 2030, and automotive gross margin excluding regulatory credits plausibly climbs from today’s eighteen to twenty percent range toward the mid twenties by decade’s end, assuming no fresh price war resets the baseline entirely, which remains the single biggest risk to this number given that Tesla itself has triggered the last two.

Opex, with the moonshots actually removed

Q1 2026 showed operating margin of just four point two percent against that twenty one point one percent gross margin, a gap of roughly seventeen points consumed by research and development plus selling, general, and administrative spend before operating income is even reached. Tesla does not break that spend out by project. Analyst and independent researcher estimates, triangulated from headcount allocation and disclosed capex rather than company disclosure, have placed AI and robotics related spend, Dojo compute, Optimus, autonomy software beyond basic driver assistance, somewhere near thirty to forty percent of total research and development in recent years. This issue assumes core automotive opex represents sixty five percent of Tesla’s reported total, a midpoint of that range, stated openly as an estimate rather than a fact.

Apply that split to the current quarter and core automotive opex falls to roughly eleven percent of revenue, versus the seventeen point full company figure. Core automotive operating margin today, stripped of moonshot spend and moonshot revenue alike, sits closer to ten percent than to four. Carry modest operating leverage forward to 2030 as the core business scales against a growing revenue base, and a core automotive operating margin near fifteen to sixteen percent by 2030 is a defensible, disciplined number. It is not a tech multiple number. It is closer to what a genuinely best run automaker produces at scale, Toyota included, which is precisely the point of stripping the story away.

The bridge from operating margin to EBITDA, shown rather than named

Operating margin and EBITDA margin are not the same number, and naming one while meaning the other is exactly the shortcut this newsletter refuses to take. Operating margin, also called EBIT, earnings before interest and tax, already has depreciation subtracted twice over, once inside cost of goods sold as the depreciation on factory equipment and tooling that made each car, and once inside opex as the depreciation on R&D labs and corporate facilities. EBITDA sits one layer above that, before depreciation gets subtracted at all, because EBITDA is trying to answer a different question, how much cash the operating business throws off before accounting for the capital already spent building it.

Tesla’s own Q1 2026 filing makes the bridge visible. Revenue of twenty two point four billion dollars, gross margin of twenty one point one percent, gives gross profit of four point seven three billion. Operating income was reported at nine hundred million, which means operating expenses, research and development plus selling, general, and administrative, absorbed three point eight three billion, or seventeen point one percent of revenue, between gross profit and operating income. Operating margin, nine hundred million divided by twenty two point four billion, equals four point two percent, and that number already has depreciation baked into both the cost of goods sold line above it and the opex line just subtracted. Tesla disclosed depreciation and amortization near one point six billion dollars for the quarter, roughly seven percent of revenue. Add that back to the four point two percent operating margin and the company lands near eleven percent, and that eleven percent is EBITDA margin, not the four point two percent, and not the seventeen point one percent opex figure either. Three different numbers, three different layers of the same statement, and confusing any two of them is how a valuation quietly becomes wrong without anyone noticing the error.

Apply that identical bridge to the isolated core automotive business built above. A projected 2030 core automotive operating margin near fifteen to sixteen percent already has depreciation subtracted within it, the same way Tesla’s real four point two percent does today. Add back a depreciation ratio consistent with a capital intensive manufacturing base scaling toward three to three and a half million vehicles a year, roughly six to seven percent of revenue, and core automotive EBITDA margin lands near twenty one to twenty three percent. That is the number this valuation actually uses, and now the reader has watched it get built rather than being asked to trust it.

The valuation

Revenue near one hundred twenty billion dollars and an EBITDA margin near twenty one to twenty three percent, built through the bridge above rather than assumed, puts 2030 core automotive EBITDA near twenty five billion dollars.

No premium for the EV label. The industry median EV to EBITDA multiple sits near nine and a half times. A car business still growing production meaningfully into 2030, with margin still expanding rather than flat, earns a modest growth premium over that median, not the triple digit multiple the full company trades at today. Call it twelve to fifteen times core automotive EBITDA. Apply that range to twenty five billion dollars and the automotive business alone is worth somewhere between three hundred billion and three hundred seventy five billion dollars in enterprise value. Add back Tesla’s real net cash position, nearly twenty nine billion dollars today, and equity value lands near three hundred thirty to four hundred billion dollars, or roughly eighty five to one hundred five dollars a share against a share count near three point seven six billion.

The P/E cross-check, and where it disagrees

Every retail investor recognizes price to earnings before they recognize EV to EBITDA, so the same business deserves a second look through that lens, built with its own honest bridge rather than borrowed from the number above.

Start from the same twenty five billion dollar EBITDA and walk it down one more layer than before. Subtract depreciation and amortization, roughly six and a half percent of a hundred twenty billion dollars in revenue, near seven point eight billion, and operating income lands near seventeen to eighteen billion, consistent with the fifteen to sixteen percent operating margin this issue already built. Subtract interest next. Tesla carries very little debt today, interest expense running near three hundred fifty million dollars annualized against fifteen point eight nine billion in debt offset by a net cash position of nearly twenty nine billion. Project modest growth in that line to roughly five hundred million by 2030 as capacity expansion adds some debt, and pretax income lands near seventeen point seven billion. Subtract tax last. Tesla’s effective tax rate has been climbing as older credits phase out, recent quarters running between twenty six and thirty one percent. Apply twenty seven percent and net income for the core automotive business alone lands near twelve point nine billion dollars.

Divide that across a share count near three point eight seven billion, allowing modest dilution from today’s three point seven six billion, and core automotive earnings per share in 2030 comes to roughly three dollars and thirty cents. A mature but still growing automaker, no story premium, earns somewhere between fifteen and eighteen times earnings. Apply seventeen times and the implied share price sits near fifty seven dollars.

Compare that to the eighty five to one hundred five dollar range the EV to EBITDA method just produced on the identical business, built from the identical production and margin assumptions. Two honest methods, same company, same year, and a gap of nearly forty percent between them. This is not a mistake either method made. EBITDA never charges the business for interest and tax, and net income always does, so any multiple applied to EBITDA is quietly more generous than the same story told through earnings unless the multiples themselves are chosen to offset that gap, which neither of ours were, on purpose. A twelve to fifteen times EV to EBITDA multiple and a fifteen to eighteen times P/E multiple both sound conservative in isolation. Placed side by side on the same business they reveal that at least one of them, possibly both, was picked without checking what it implied about the other.

This is the actual folly worth sitting with rather than resolving. Professional research notes present a single price target as though the method behind it were the only honest one available. It rarely is. A reader who only ever sees the EV to EBITDA number walks away thinking the car business alone is worth roughly a hundred dollars a share. A reader who only sees the P/E number walks away thinking fifty seven. Both readers are looking at the same production range, the same falling ASP, the same disciplined cost curve. The forty percent gap between their answers exists entirely in the multiple, not in the business, and no multiple is neutral just because it looks like a small, reasonable number on the page.

The stress test

Tesla’s enterprise value today sits near one point four trillion dollars, close to four hundred nine dollars a share. Both car only valuations built in this issue, fifty seven dollars through earnings and roughly eighty five to one hundred five dollars through EBITDA, sit far below that price, and the size of the gap depends on which honest method a reader chooses to trust. That range itself, not a single resolved number, is the honest output of this exercise. What the market is actually paying for, somewhere between three hundred and three hundred fifty dollars a share of the four hundred nine, is Optimus, robotaxi, and full self driving, three businesses generating no meaningful disclosed revenue today. If those three businesses never convert from promise to income statement, the stock has a long way to fall to meet either car only number built here. If even one of them converts at scale, both numbers understate the company, by design, because that was the rule set at the top of this issue. What this issue will not do is pretend the fifty seven dollar number and the hundred dollar number are actually the same number wearing different clothes. They are not. Sitting with that disagreement honestly is worth more to a reader than a false single answer would be.

The one word

Every company in this newsletter earns one word describing what it actually does once the story gets stripped away. Tesla sells cars at a falling price to defend volume against cheaper competition, on a cost curve that is real but not infinite, funded by research spending it will not itemize. Tesla manufactures.

Sources: Tesla Q1 2026 and Q4 2025 financial and delivery disclosures, Tesla 10-K installed capacity disclosures by factory, Tesla U.S. retail pricing as published on tesla.com, BYD 2025 global delivery figures, Boston Consulting Group experience curve research, and third party analyst and independent researcher estimates on Tesla R&D allocation and bottom up production capacity.

This content is for educational purposes only and does not constitute investment advice. Nothing in this issue is a recommendation to buy, sell, or hold any security. Always conduct independent research or consult a licensed financial advisor before making investment decisions.

July 8 2026, The Woodlands, Texas. Kodiak Gas Services and Baker Hughes

announce a multi year agreement anchored by an initial order for roughly a gigawatt of gas turbines and generators, deliverable by 2030, with a stated pathway toward one point eight gigawatts if the relationship keeps expanding. The turbines are destined for behind the meter power plants feeding data centers, the physical infrastructure underneath the artificial intelligence buildout every technology company on earth is racing to fund. A gigawatt is enough electricity for roughly seven hundred thousand American homes. Baker Hughes is now in the business of building that much generating capacity for a single customer’s server farms.

One hundred seventeen years earlier, in 1909, a Texas oilman named Howard R. Hughes Senior and his partner Walter Sharp patented a two cone rotary drill bit that let wells punch through hard rock formations no fishtail bit could penetrate. That patent is the actual origin point of the modern oil industry’s ability to drill deep, and it is also, through an unbroken corporate lineage running merger through merger for more than a century, the same company now selling gigawatts of turbine capacity to power artificial intelligence. Understanding how a rock bit patent from the Taft administration turned into a data center power supplier is the entire subject of this issue, because the mechanism connecting those two facts is not incidental. It is the whole business model.

THE HUNDRED SEVENTEEN YEAR MACHINE

Two separate men built the companies that eventually became Baker Hughes, and neither one set out to build an oilfield services conglomerate. Reuben C. Baker, an inventor working the Coalinga oil fields of California, patented a casing shoe in 1907 that solved a specific mechanical problem, keeping a well’s steel casing properly seated against hard rock formations during cementing. He incorporated the Baker Casing Shoe Company the same year, which grew through the following decades into Baker Oil Tools, then Baker International by 1976. Howard Hughes Senior, working alongside Walter Sharp in Houston, solved a different problem entirely, how to drill through rock formations too hard for the fishtail bits then in common use. Their two cone roller bit, patented in 1909, worked so well that Hughes maintained a near total monopoly on hard rock drilling technology for decades simply by patenting every conceivable variation of his own design and buying up any competing patents that emerged. When Sharp died in 1912, Hughes bought out his widow’s stake and renamed the company Hughes Tool in 1915. When Hughes himself died in 1924, his son, the aviator and film producer Howard Hughes Junior, inherited the company and used its steady drill bit profits to fund an entirely unrelated empire in aviation, motion pictures, and Las Vegas real estate for the next four decades, eventually selling Hughes Tool’s actual tool division to the public in 1972.

Baker and Hughes operated as separate companies, competitors even, for most of the twentieth century, until the mid 1980s oil price collapse forced a reckoning across the entire oilfield services industry. In 1987, Baker International and Hughes Tool merged to form Baker Hughes Incorporated, a deal complicated enough that it nearly fell apart entirely. The Justice Department moved to block the merger on antitrust grounds, forcing a consent decree that required divesting Hughes’ Reed Tool subsidiary. Hughes then attempted to walk away from the agreement after accepting those terms, and Baker responded by threatening to sue for a billion dollars if the deal collapsed, a threat serious enough that Hughes shareholders overruled their own management and voted to complete the merger anyway. The combined company emerged as the second largest oilfield services provider on earth, trailing only Schlumberger, and immediately began the acquisition pattern that would define the next four decades, Eastman Christensen’s directional drilling technology in 1990, Teleco’s measurement while drilling capability in 1992, Western Atlas’ seismic and wireline business for roughly three point three billion dollars in 1998, and BJ Services’ pressure pumping and hydraulic fracturing capacity for five point five billion dollars in 2010.

The single most consequential deal in the company’s modern history arrived in 2017, when Baker Hughes merged with General Electric’s oil and gas division to form Baker Hughes, a GE Company, with GE holding sixty two point five percent of the combined entity. That merger did more than add GE’s turbine and compression manufacturing capability to Baker Hughes’ existing service business. It planted the genetic material for everything the company has become since, because GE’s industrial equipment heritage, gas turbines, compressors, power generation technology built originally for utilities and industrial customers far removed from oil and gas, gave Baker Hughes a foothold in a business line with none of the boom and bust exposure that defines pure oilfield services. GE divested its entire stake by early 2021 to shore up its own balance sheet, leaving Baker Hughes as a fully independent public company again, but the DNA GE left behind reorganized itself in 2022 into the two segment structure the company runs today, Oilfield Services and Equipment, and Industrial and Energy Technology. Chief executive Lorenzo Simonelli, who ran GE Oil and Gas before overseeing the 2017 merger and has led Baker Hughes ever since, has spent the years since calling the current strategic period Horizon Two, an explicit internal acknowledgment that the company is no longer primarily an oilfield services business wearing an energy technology label, but an energy technology business that still happens to carry a large oilfield services division alongside it.

THE BUSINESS MODEL, TWO ENGINES RUNNING ON DIFFERENT CLOCKS

Oilfield Services and Equipment is the business every reader of this newsletter already recognizes, drilling, completion, production, well intervention, subsea systems, and flexible pipe, sold directly against a customer’s decision to drill a well this quarter or not. Revenue here moves with rig counts and drilling activity almost in real time, the same short cycle exposure this newsletter documented running through Halliburton’s own 2025 results, a business that lives or dies by how many wells North America decides to drill in any given three month window.

Industrial and Energy Technology is a structurally different business wearing the same corporate name. It sells mechanical drive equipment, compression systems, power generation technology, measurement instrumentation, and increasingly, climate related technology including carbon capture and hydrogen infrastructure, into contracts that run years rather than weeks. A customer ordering gas turbines for a data center power plant is not deciding whether to drill next month. They are committing to a power infrastructure investment that will run for decades, and the order Baker Hughes books today converts into revenue and service contracts stretching years into the future. This is the business line inherited from GE, and it is the business line that has spent the last three years growing while OFSE has spent the same period shrinking.

THE NUMBERS, BUILT LAYER BY LAYER

Full year 2025 revenue came to twenty seven point seven billion dollars, essentially flat against 2024, a headline number that conceals two segments moving in opposite directions underneath it. Orders for the full year reached twenty nine point six billion dollars, including a record fourteen point nine billion dollars of IET orders specifically, with non LNG equipment orders representing roughly eighty five percent of total IET bookings for a second consecutive year, evidence the segment’s growth is broad based across power systems, compression, and industrial technology rather than dependent on any single liquefied natural gas mega project landing in a given quarter. Attributable net income for the year came to two point five nine billion dollars, adjusted EBITDA reached four point eight three billion dollars, up five percent, and the company generated a record two point seven billion dollars of free cash flow, helped along by working capital efficiency and customer down payments flowing in ahead of equipment delivery.

The fourth quarter isolates exactly where the strain sits. OFSE revenue came to three point five seven two billion dollars, down two percent sequentially and down eight percent year over year, a genuine structural decline tracking the same North American activity slowdown that gutted Halliburton’s 2025 results. IET, over the same three months, booked four billion dollars of orders, pushing full year IET backlog to a record thirty two point four billion dollars with book to bill exceeding one times, meaning the segment is booking new work faster than it can complete the work already on its books.

The first quarter of 2026 confirms the divergence is accelerating rather than stabilizing. Total orders reached eight point two billion dollars, including four point nine billion dollars of IET orders alone, the third consecutive quarter IET bookings have cleared four billion dollars, with one point four billion dollars of that total coming from Power Systems specifically. Remaining performance obligations, the company’s own measure of contracted future revenue, climbed to thirty six point one billion dollars overall, including a record thirty three point one billion dollars sitting inside IET alone. Total revenue reached six point six billion dollars, up two percent year over year, attributable net income hit nine hundred thirty million dollars, and adjusted EBITDA reached one point one five eight billion dollars, up twelve percent. Simonelli’s own language framing the quarter is worth quoting directly, since it names the pressure the numbers only imply, telling investors the results exceeded guidance despite significant disruptions in the Middle East, a direct acknowledgment that the Iran war disrupting the region throughout the first months of 2026 registered as a headwind the company still managed to outperform against.

THE BIGGEST BET IN THE COMPANY’S HISTORY

On July 28 2025, Baker Hughes announced a definitive agreement to acquire Chart Industries entirely, in an all cash transaction valuing the company at thirteen point six billion dollars, two hundred ten dollars a share, a multiple of roughly nine times Chart’s expected 2025 EBITDA on a fully synergized basis. Chart is not an oilfield services company at all. It designs and manufactures cryogenic equipment, heat exchangers, and small scale compression technology used across the entire liquid gas supply chain, generating four point two billion dollars of revenue and roughly one billion dollars of adjusted EBITDA in 2024 across sixty five manufacturing sites worldwide, with meaningful exposure to markets Baker Hughes had limited direct access to on its own, data centers, space applications, hydrogen, industrial gas, metals and mining, and food and beverage processing.

Chart shareholders approved the deal on October 6 2025. Baker Hughes financed the cash consideration by pricing six point five billion dollars in dollar denominated notes and three billion euros in euro denominated notes on March 11 2026, a nine tranche offering spanning maturities from 2029 out to 2056, immediately terminating the bridge financing facility the company had arranged the previous July as a fallback. Management has identified three hundred twenty five million dollars of annualized cost synergies achievable by the end of the third year post close, drawn from consolidated manufacturing scale, integrated supply chains, and reduced overlap across sales, general and administrative, and research and development functions. As of this writing, the deal remains in its final regulatory stretch, Baker Hughes filed a Form CO with the European Commission on May 21 2026, opening the Commission’s Phase One antitrust review, with both companies currently targeting a July 2026 close, meaning the acquisition that will most define Baker Hughes’ next decade is closing at almost the exact moment this issue is being written.

Chart is not a bolt on. It is close to a doubling down on the entire IET thesis, a bet that the future of this company runs through manufacturing the physical equipment that moves and processes gas molecules, rather than through the services business that built the company’s original reputation.

THE GIGAWATT RACE

The Kodiak deal this issue opened with did not arrive in isolation. Baker Hughes signed a smaller but structurally identical agreement with Twenty20 Energy on February 11 2026, an initial order for ten Frame Five gas turbines supporting up to two hundred fifty megawatts of generation capacity for data center projects in Georgia and Texas, explicitly described by both companies as an early step toward a larger multi gigawatt strategic collaboration. Baker Hughes has since doubled its own three year target for data center related orders, from one point five billion dollars to three billion, a target the company is on pace to clear well ahead of schedule given the Kodiak agreement’s scale alone. Elsewhere across the IET portfolio, Baker Hughes won a significant contract to supply compression and pumping technology for a large QatarEnergy LNG expansion, extended a long term service agreement with Nigeria LNG supporting a critical expansion project, was awarded a significant long term service agreement with ANOH Gas Processing Company for a Nigerian gas plant, agreed to deliver subsea production systems supporting Azule Energy’s Greater PAJ development in Angola, and struck a strategic agreement with Mantle Reach Power, an EnCap Energy Transition portfolio company, to accelerate large scale geothermal development across North America. None of these deals individually rivals Kodiak’s scale, but together they describe a company placing simultaneous bets across LNG, data center power, and geothermal, three genuinely different growth markets unified only by the fact that all three need the kind of heavy rotating equipment Baker Hughes and its newly acquired Chart division both know how to build.

THE INDIA RELATIONSHIP, TWENTY YEARS RUNNING

Baker Hughes and ONGC have worked together for two decades, and the relationship produced fresh, material news in the second quarter of 2026 alone. On July 6 2026, Baker Hughes announced multiple new awards from ONGC covering advanced wireline services across both offshore and onshore India, deploying up to forty six wireline units and seven drill stem testing kits carrying the company’s Proxima logging, RCX MAGNA sampling, and DeepConnect perforating technologies. The work spans a genuinely wide swath of India’s producing basins, Mumbai High, Neelam Heera, Bassein Satellite, Mahanadi, Andaman, Cauvery, the KG basin, and the Assam Arakan basin in the northeast, covering both mature fields needing enhanced recovery and greenfield developments needing first characterization. Amerino Gatti, Baker Hughes’ Executive Vice President of Oilfield Services and Equipment, tied the award explicitly to the two decade relationship, framing the new work as an extension of a partnership that has already played a material role in India’s own hydrocarbon development. The company maintains dedicated wireline facilities in Taloja near Mumbai and in Duliajan in India’s northeast specifically to support maintenance, calibration, and testing without routing equipment through a foreign base first, infrastructure that only makes sense for a company planning to remain embedded in India’s upstream sector for decades rather than servicing it opportunistically.

THE WAR THAT DID NOT MOVE THE NUMBERS THE WAY IT MOVED PRICES

This newsletter has already documented how the 2026 Iran war pushed Brent from roughly seventy dollars to above a hundred twenty five within six weeks, and how that spike barely moved activity at Halliburton, since Permian operators kept capital discipline rather than chasing a price rally they did not trust to last. Baker Hughes tells a related but distinct version of the same story. OFSE’s own revenue decline through the back half of 2025 and into 2026 reflects the identical capital discipline dynamic, a services business that only gets paid when producers decide to drill, and producers scarred by war driven volatility choosing not to. IET, by contrast, barely noticed the war at all in its own order book, since a data center developer signing a multi year power agreement is not pricing in this month’s Brent quote, and Simonelli’s own acknowledgment of significant Middle East disruptions in the same breath as beating first quarter guidance is the clearest evidence available that the two segments experienced 2026’s defining geopolitical shock in almost entirely different ways.

THE HISTORY THE COMPANY DOES NOT PUT ON ITS HOMEPAGE

In April 2007, Baker Hughes pleaded guilty in United States federal court to violating the Foreign Corrupt Practices Act, agreeing to pay forty four point one million dollars in fines and penalties over roughly four point one million dollars in commission payments made between 2001 and 2003, payments federal prosecutors alleged secured an oil services contract in Kazakhstan’s Karachaganak field. The case remains the most serious corporate accountability failure in the modern company’s history, a reminder that the same global footprint enabling Baker Hughes to win contracts across a hundred twenty countries also exposed it to exactly the kind of corruption risk that global footprint invites, and that the company’s current branding around safety, sustainability, and energy transition sits on top of a compliance history that once cost it real money and real reputational standing in exactly the kind of frontier market the company still operates in today.

WHETHER THIS BUSINESS IS REPLACEABLE

The honest answer runs in two directions depending on which half of the company you are asking about. OFSE faces a genuine long term replaceability question that has nothing to do with Baker Hughes specifically and everything to do with the maturity of the resource base it serves, shale wells decline steeply enough that services demand should structurally shrink as the most productive basins age, automation and digital tools like the company’s own AutoTrak rotary steerable systems reduce the labor intensity of drilling operations that once required larger crews, and the broader energy transition, however slowly it actually proceeds, points toward a smaller addressable market for pure oilfield services a decade or two from now than exists today.

IET faces close to the opposite risk profile. Its growth is currently driven by an artificial intelligence buildout still in its early innings, and the same automation and digital transformation trend threatening OFSE’s labor intensive service model is the direct source of demand for the gas turbines IET is racing to manufacture, since every data center powering that automation needs electricity Baker Hughes and its newly acquired Chart division are now positioned to help supply. This is the genuinely interesting structural irony sitting underneath the entire company today, the same technological wave that shrinks the addressable market for one half of Baker Hughes’ business is simultaneously growing the addressable market for the other half, and the Chart acquisition, closing almost exactly as this issue publishes, is the clearest signal available that Baker Hughes’ own management believes the second half of that trade is the one worth betting the company’s balance sheet on.

THE POLITICS OF WHO NEEDS GIGAWATTS FASTEST

Washington’s own posture toward the AI infrastructure buildout functions as a direct subsidy to Baker Hughes’ IET growth, even without a single dollar changing hands directly, since federal policy racing to secure domestic power generation capacity for data centers creates exactly the demand environment IET is currently monetizing at record order volumes. That same administration’s tariff policy on imported steel and components, struck down in part by the Supreme Court’s February 2026 ruling on emergency powers this newsletter has already covered in depth, still cost Baker Hughes and Halliburton alike real money through 2025 before that ruling landed, an inconsistency between one policy accelerating IET’s core market and another policy raising IET’s own input costs that the company has simply had to absorb rather than resolve.

The Chart acquisition’s European Commission review adds a second political dimension entirely, since Brussels’ own antitrust scrutiny of a deal between two American companies demonstrates how thoroughly global Baker Hughes’ operations have become, a merger between a Houston headquartered energy technology company and an Atlanta headquartered industrial manufacturer still requires sign off from a European regulator because both companies sell enough equipment into European markets to trigger review. Layered against the company’s genuinely global contract book, Qatar, Nigeria, Angola, Colombia through the Ecopetrol relationship this newsletter has already profiled, and India through two decades of ONGC work, Baker Hughes sits inside more simultaneous political relationships than almost any company covered in this newsletter’s run so far, each one carrying its own regulatory calendar, tariff exposure, and sanctions adjacent risk profile entirely independent of the others.

WHAT THE TAPE IS SAYING NOW

China exports deflation into whatever industry it decides to scale, and this newsletter has returned to that mechanism issue after issue describing how global oversupply flattens prices across oil, gas, and even Russian pipeline exports. Gas turbines are currently running the opposite pattern entirely. Global heavy duty turbine manufacturing capacity across Baker Hughes, GE Vernova, Siemens Energy, and Mitsubishi Power has been effectively sold out for years at a stretch, since decades of underinvestment in new manufacturing capacity collided head on with a data center buildout nobody in the turbine industry planned for a decade ago. IET’s record backlog and record book to bill ratio are not simply evidence of Baker Hughes executing well. They are evidence of a genuine supply constrained market, the rare corner of the global energy economy currently experiencing pricing power rather than the deflationary pressure squeezing almost every other commodity this newsletter covers.

STRESS TEST

Chart integration risk is the largest single variable hanging over the next eighteen months. A thirteen point six billion dollar acquisition closing on the heels of a nine and a half billion dollar debt raise materially increases Baker Hughes’ leverage at the exact moment OFSE revenue is declining, and the three hundred twenty five million dollar synergy target assumes a smooth integration across sixty five manufacturing sites that has not yet been tested at this scale.

IET’s record backlog is a promise, not delivered revenue, and converting thirty three point one billion dollars of remaining performance obligations into shipped, installed, and commissioned power infrastructure on schedule is an execution challenge distinct from the sales success that built the backlog in the first place.

OFSE’s structural decline shows no clear floor. Shale basin maturity, digital automation reducing labor intensity, and producer capital discipline in the face of volatile prices are all long term trends working against the segment simultaneously, and nothing in Baker Hughes’ current strategy suggests a plan to reverse that decline rather than simply outgrow it through IET’s expansion instead.

THE INSTITUTIONAL LABEL

Baker Hughes reinvents. A company built on a rock bit patent from 1909 has spent the last decade systematically trading its own oldest identity for a new one, GE’s turbine heritage grafted on in 2017, a two segment structure formalized in 2022, and now Chart Industries’ cryogenic and industrial gas expertise absorbed in 2026, each move pulling the center of gravity further from the oil well and closer to the power plant. The rock bit that started this company in 1909 still gets used somewhere in the world today. It is no longer close to the reason Baker Hughes is worth what it is worth.

SOURCES

Baker Hughes fourth quarter and full year 2025 results, Form 8-K, January 2026. Baker Hughes first quarter 2026 results, Form 8-K, April 23 2026. Baker Hughes Form 10-K, fiscal year 2025, and Form 10-Q, first quarter 2026, SEC filings. Baker Hughes and Chart Industries joint press release and Form DEFA14A, July 29 2025. StockTitan, Baker Hughes senior notes pricing for the Chart acquisition, March 5 2026, and European Commission Form CO filing coverage, May 21 2026. Baker Hughes and Twenty20 Energy joint press release, GlobeNewswire, February 11 2026. Kodiak Gas Services and Baker Hughes joint press release, Business Wire, July 8 2026. JPT SPE, coverage of the Twenty20 Energy order and Baker Hughes’ data center strategy, February 16 2026. Baker Hughes and ONGC joint press release, July 6 2026, and Zawya, TradeArabia, and Egypt Oil and Gas syndicated coverage of the same announcement. Wikipedia, Baker Hughes and Hughes Tool Company corporate history. Texas State Historical Association, American Oil and Gas Historical Society, FundingUniverse, and Encyclopedia.com, Baker Hughes and Hughes Tool Company founding history and the 1987 merger. The New York Times, Baker Hughes admission of Foreign Corrupt Practices Act violations, April 27 2007.

March 12 2026, before dawn. Ukrainian drones strike the Russkaya and Beregovaya compressor stations, the pumping

infrastructure feeding what remains of Gazprom’s export routes toward Turkey and southern Europe. It is not the first such strike and will not be the last. Three years earlier, in 2023, Gazprom posted a loss of six hundred twenty nine billion rubles, its first annual loss since 1999, a year before Vladimir Putin had even become prime minister. The war in Ukraine is the reason Gazprom lost its largest export market. The Russian state’s own tax code is the more immediate reason Gazprom actually lost money, since Moscow raised the mineral extraction tax on its own gas company specifically to fund the military spending that war required, costing Gazprom one point three trillion rubles in a single year, more than double the company’s headline loss. Gazprom did not simply lose the war’s collateral damage. It got taxed to help pay for the war directly.

THE LOSS, AND WHERE IT ACTUALLY CAME FROM

Strip away the tax increase and Gazprom’s underlying 2023 business looks considerably less catastrophic than the headline number suggests. Total revenue that year actually grew compared with pre war, pre pandemic 2019, from seven point six trillion rubles to eight point five trillion, despite losing most of the European gas market that had defined the company for decades. The real damage came from two sources layered on top of an already difficult year, the one point three trillion ruble mineral extraction tax increase Deputy Finance Minister Alexei Sazanov described plainly as an effort to skim windfall profits from oil and gas producers to fund the budget, and a separate one point one five trillion ruble writeoff of European assets, pipeline stakes, storage facilities, and joint ventures that had simply lost their value once the political relationship underpinning them collapsed, up from a mere twenty nine billion rubles in 2019.

The following year produced a headline reversal striking enough to demand its own explanation. Gazprom’s 2024 IFRS results showed a net profit of one point two trillion rubles, and the mechanics behind that swing say more about accounting opportunism than operational recovery. Gazprom paid ninety four billion rubles for Shell’s twenty seven point five percent stake in Sakhalin Energy, the operator of the Sakhalin Two liquefied natural gas project, in March 2024, yet recognized an immediate accounting gain of roughly a hundred ninety one billion rubles because the purchase price sat well below the asset’s fair value following Shell’s forced exit, a paper gain rather than cash in hand, but one IFRS rules required Gazprom to book in full the moment the deal closed. Shell itself wrote off one point six billion dollars walking away from the same stake. One company’s forced retreat became another company’s accounting windfall, and the full consolidation of Sakhalin Energy’s revenue from the second quarter of 2024 onward added four hundred sixty four billion rubles to Gazprom’s books entirely on its own. Layer in another trillion rubles from oil, gas condensate, and refined product sales, boosted by a Urals crude price running six dollars a barrel higher than the year before on essentially flat physical volumes, and the picture of 2024’s turnaround becomes clear, a company that grew gas production from three hundred fifty nine billion cubic metres to four hundred sixteen billion, but whose profit swing depended just as heavily on one opportunistic acquisition and a favorable oil price as it did on any structural repair of the European market it had actually lost.

That repair still has not happened, and 2025 showed the tax pressure has not eased either. A Duma lawmaker warned in committee that Gazprom’s continued tax burden, layered onto declining export revenue, could drive the company to another loss approaching a trillion rubles for the year, telling colleagues that gas transportation costs keep rising even as the export volumes that once justified that infrastructure keep falling. Gazprom’s own board cut the 2025 investment program to one point five trillion rubles, down from a record above two point six trillion in prior years, a company deliberately shrinking its own forward capital commitment because the revenue base that used to support a larger one no longer exists.

THE PIVOT TO CHINA, MEASURED AGAINST WHAT IT REPLACED

Gazprom’s answer to losing Europe has been the Power of Siberia pipeline into China, and 2025’s results show real progress against a genuinely small base. Deliveries reached thirty eight point eight billion cubic metres for the year, nearly twenty percent above 2024’s thirty one billion, slightly exceeding the pipeline’s contracted annual volume of thirty eight billion cubic metres through operational optimization, with chief executive Alexei Miller telling reviewers Gazprom delivered almost eight hundred million cubic metres beyond its contractual obligation to China. That is a genuine operational achievement. It is also a fraction of what Gazprom used to sell into Europe at the relationship’s peak, when annual pipeline exports ran several multiples higher than the volume China currently takes, meaning the pivot east has replaced a portion of the lost market rather than the whole of it, years into the effort.

The next leg of that pivot, Power of Siberia Two, running through Mongolia, remains stuck in negotiation despite years of intergovernmental agreements and memoranda between Moscow and Beijing. Neither side has signed a final investment decision or a binding gas purchase contract, and the sticking point is the same one that stalls most deals between a desperate seller and a buyer with no urgency, price, with China reportedly unwilling to commit to terms anywhere near what Gazprom needs to justify the pipeline’s cost. Construction could take up to a decade even once terms are settled, according to estimates from China’s own state energy officials, and financing for a project this size remains unresolved. Turkey has, in the meantime, quietly become Russia’s largest remaining market touching Europe at all, surpassing the European Union itself as a destination for gas moving through the TurkStream system, the same infrastructure the March 2026 drone strikes targeted directly.

Worth noting plainly, Gazprom itself is barely a participant in Russia’s other major gas growth story, liquefied natural gas. Novatek, not Gazprom, is Russia’s dominant LNG exporter, running the Yamal LNG project under a twelve year exemption from the same mineral extraction taxes that have been squeezing Gazprom specifically, an asymmetry in how Moscow treats its two gas companies that itself says something about which one the state currently needs more from and which one it is willing to let keep more of its own revenue.

THE POLITICS OF A COMPANY THE STATE NEEDS TO BLEED

Gazprom’s relationship with its own government is not adversarial in the way sanctions politics is adversarial. It is closer to a landlord extracting rent from a tenant it also happens to own outright. The mineral extraction tax increases that drove the 2023 loss were not imposed by a hostile foreign power, they were imposed by the Russian Ministry of Finance, explicitly to help fund the same war effort that had already cost Gazprom its largest export market in the first place, a closed loop in which the company simultaneously supplies the state’s energy leverage abroad and gets taxed at home to underwrite the conflict that leverage is being used to fight. Deputy Finance Minister Sazanov’s own language, skimming windfall profits, treats Gazprom’s revenue as a national resource to be drawn down whenever the budget requires it, regardless of what that draw down does to the company’s own reported financial health.

The March 2026 strikes on Russkaya and Beregovaya sit inside a broader pattern of Ukrainian attacks specifically targeting the compression infrastructure that keeps gas moving toward whatever export markets remain, a campaign that treats Gazprom’s remaining pipeline capacity as a legitimate military target precisely because that capacity still generates hard currency and diplomatic leverage for Moscow. Purely as speculation rather than anything settled, Kirill Dmitriev, representing Russia’s sovereign wealth fund in periodic contact with American counterparts, has continued raising the possibility of restoring elements of the energy relationship between Washington and Moscow. Whether that speculation ever touches Gazprom specifically remains unclear, and the connection between Dmitriev’s public comments and Gazprom’s own future is not one the available evidence currently supports beyond noting that any broader resolution to the war would likely affect the company eventually.

WHAT THE TAPE IS SAYING NOW

Europe’s own diversification away from Russian gas, accelerated LNG imports from the United States and Qatar, expanded storage capacity, demand destruction from higher prices sustained since 2022, has done to Gazprom’s addressable market roughly what a determined new entrant does to an incumbent anywhere else, permanently shrinking the base the incumbent can ever fully recover, regardless of how the underlying war eventually resolves. China exports deflation into whatever industry it decides to scale, and the global LNG market is scaling hard through the back half of this decade, Qatar’s North Field expansion, the American Gulf coast build out, Mozambique’s eventual capacity, all arriving inside the same window Gazprom is trying to negotiate Power of Siberia Two into existence. Gazprom is not just negotiating against Chinese price resistance. It is negotiating against a global gas supply picture that gives Beijing less reason every year to accept Moscow’s price rather than wait for cheaper alternatives to reach the market instead.

STRESS TEST

China’s negotiating leverage over Power of Siberia Two is overwhelming rather than absolute, since Gazprom has far fewer alternative buyers than China has alternative suppliers, a dynamic that will keep pricing negotiations stalled for as long as China calculates that waiting costs it nothing.

Infrastructure risk is now a permanent operating condition rather than an occasional disruption. Compressor stations feeding Gazprom’s remaining export routes sit inside active strike range for the duration of the war, and every ruble spent on repair is a ruble unavailable for the capital program the company has already been forced to shrink twice.

Fiscal extraction risk never actually goes away once a government has demonstrated it will raise taxes on a state company whenever the budget needs it. The 2023 precedent means any future revenue recovery Gazprom manages to generate is immediately vulnerable to the same mechanism that produced the 2023 loss in the first place.

THE INSTITUTIONAL LABEL

Gazprom subsidizes. The company has moved through three distinct identities without ever changing its name. In the 1990s it operated as a commercial gas monopoly, Russia’s answer to what a state owned utility could become once the Soviet system dissolved around it. Through the 2000s and into the 2010s it became a geopolitical instrument, selling gas to Europe on terms that doubled as leverage over the continent’s own energy security, a role that made Gazprom as much a foreign policy tool as an energy company. In the 2020s it became something narrower and more transactional, a fiscal instrument financing the Russian state budget directly, taxed at a rate calibrated to whatever the war currently costs, treated by its own government as a reserve to be drawn down rather than a business to be protected. Rosneft absorbed sanctions imposed from outside the country. Gazprom absorbed a tax increase imposed from inside it, for the same underlying reason, and the distinction matters, because a foreign sanctions regime can theoretically be negotiated away in a peace settlement. A domestic tax precedent, once set, belongs to Moscow to reimpose whenever it likes, war or no war, for as long as Gazprom remains too strategically important for the state to ever fully let go of.

SOURCES

Sergey Tereshkin Publications, Gazprom RAS first half 2025 results analysis. Carnegie Endowment for International Peace, how Gazprom went from record losses to profits, coverage of 2023 and 2024 IFRS results. World Energy and OilPrice.com, Power of Siberia 2025 delivery volumes and Power of Siberia Two negotiation status, December 2025. TASS, Duma Committee on Budget and Taxes coverage of Gazprom’s 2025 loss forecast and mineral extraction tax increases, including reporting on the March 2026 Russkaya and Beregovaya compressor station strikes. Atlantic Council, effect of sanctions and windfall taxation on the Russian energy industry, including the Novatek mineral extraction tax exemption comparison. Bloomberg Tax, Russia’s 2022 proposed mineral extraction tax increases on Gazprom.

October 22 2025, hours after US markets closed. The Treasury Department adds Rosneft and Lukoil, Russia’s two largest oil companies, to its Specially Designated Nationals list,

the first Russia related sanctions the second Trump administration has imposed, arriving days after a planned Budapest summit between Trump and Putin collapsed before it happened. Brent jumped five percent by the next morning. Treasury Secretary Scott Bessent framed the decision around Putin’s refusal to end the war in Ukraine, adding that Washington stood ready to do more. The United Kingdom had already frozen both companies’ assets a week earlier. The European Union approved its nineteenth sanctions package the same day, banning imports of Russian liquefied natural gas outright. For the first time since the war began, all of Russia’s largest oil companies sat under direct blocking sanctions simultaneously, not the secondary, workaround riddled restrictions that had let Rosneft keep exporting for three and a half years. And Rosneft’s full year 2025 results, reported months later, still showed a company generating positive free cash flow for a twenty second consecutive quarter.

THE NUMBERS, WHERE OVERSUPPLY MET SANCTIONS AT THE SAME TIME

Rosneft’s full year 2025 IFRS results tell a story of a company absorbing multiple simultaneous shocks rather than a single clean collapse. Revenue fell eighteen point eight percent to eight point two three six trillion rubles. EBITDA dropped twenty eight point three percent to two point one seven three trillion rubles. Net income attributable to shareholders slumped seventy three percent to two hundred ninety three billion rubles, roughly three point six billion dollars, a headline number that reads catastrophic until measured against what the company still managed to hold onto underneath it. Adjusted free cash flow nearly halved to seven hundred billion rubles, and it still came in positive, marking twenty two straight quarters without a negative cash flow print, a streak that survived a war, an oil price collapse, and now direct sanctions all landing inside the same reporting period.

Production held remarkably steady through all of it. Rosneft produced a hundred twenty one point six million tonnes of oil equivalent in the first half of 2025 alone, eighty nine point three million tonnes of crude, close to three point six seven million barrels a day, plus thirty nine point three billion cubic metres of gas. The company reported six new field discoveries and a hundred twelve new hydrocarbon deposits found across the year, a reserve replacement pace that would be remarkable for any company operating under normal conditions and reads almost defiant for one operating under this many. Refining told a weaker story, throughput falling to seventy five point seven million tonnes for the year on maintenance, logistics bottlenecks, and what the company called price driven optimization, though the oil conversion rate actually improved to seventy seven point six percent, and Rosneft still supplied forty point three million tonnes of refined product to the domestic market, twelve point three million tonnes of gasoline and sixteen point four million tonnes of diesel, keeping Russia’s own fuel supply intact even as export economics deteriorated around it.

Capital expenditure fell five point seven percent to one point three six trillion rubles as the company tightened project screening, yet Vostok Oil, Rosneft’s flagship Arctic development, kept advancing regardless, seismic surveys, drilling campaigns, and major pipeline and port infrastructure work at Sever Bay continuing through the year, with pilot production now underway at the Payakhskoye and Ichemminskoye fields. A company watching its near term profitability get cut by more than two thirds is still pouring capital into a project that will not deliver meaningful volume for years, a bet that whatever sanctions regime exists today will look different by the time Vostok Oil actually needs an export market.

SECHIN’S OWN EXPLANATION, AND WHO HE BLAMES

Chief executive Igor Sechin has been unusually candid in attributing the damage, and unusually willing to criticize institutions closer to home than Washington. He pointed first at what he called a significant oversupply in the global oil market, driven largely by OPEC producers, warning as early as mid 2025 that the surplus could reach two point six million barrels a day by the fourth quarter and keep prices weak well into 2026. He also took direct aim at Russia’s own central bank, arguing that an elevated key interest rate, averaging above nineteen percent across 2025, artificially strengthens the ruble in a way that erodes export revenue and state income alike, an unusual public break between the head of Russia’s largest company and its own domestic monetary authority. Sechin described freight rates for shipping Russian oil from the Baltic to India as having topped twenty dollars a barrel, and summarized the year in a single phrase, an ideal storm, in which price spikes tied to the Iran war were offset almost immediately by rising costs elsewhere in the system.

SANCTIONS THAT FINALLY MEANT SOMETHING

For three and a half years, Rosneft had operated under sectoral sanctions that restricted specific activities, deepwater and Arctic offshore project financing, shale technology transfers, new equity and debt issuance, without ever fully blocking the company from the global financial system. The October 22 designation changed the category entirely. Rosneft and Lukoil moved to full blocking sanctions, meaning any US person is now prohibited from transacting with either company at all, and under the fifty percent rule, that prohibition automatically extends to every subsidiary either company owns a majority stake in, a list running into dozens of entities across multiple countries. OFAC issued a narrow set of wind down licenses, most expiring within thirty days, alongside a standing carve out for the Caspian Pipeline Consortium and Tengizchevroil projects specifically, since those ventures also involve Chevron and would have caused collateral damage to an American company had no exception existed.

The secondary sanctions threat is where this designation actually bites hardest. Any foreign financial institution found to have facilitated a significant transaction involving Rosneft or Lukoil now risks losing its own access to US correspondent banking, a threat serious enough that Indian refiners publicly signaled they would curtail Russian crude purchases within days of the announcement, on top of an existing fifty percent American tariff already targeting India specifically over its Russian oil imports. The UK went further than Washington in one respect, separately designating Shandong Yulong Petrochemical, one of China’s newest and largest refineries and a major buyer of Russian crude, along with several Chinese port operators servicing it, an attempt to reach past Moscow’s own borders into the specific infrastructure keeping Russian barrels moving through Asia.

THE WAR REACHING BACK INTO RUSSIA ITSELF

Ukraine’s own campaign against Russian energy infrastructure compounds everything sanctions are doing from outside the country. Drone strikes have taken an estimated seventeen percent of Russian refining capacity offline at various points through the year, triggering fuel rationing in some regions and pushing wholesale domestic gasoline prices up forty five percent even as global crude prices fell, a genuinely strange domestic inflation story in a country that exports oil for a living. Rosneft’s own refining throughput decline traces partly to this pressure alongside the maintenance and logistics explanations the company offers publicly, and the company’s continued ability to supply over forty million tonnes of fuel to its own domestic market despite the strikes says something real about redundancy built into Russian refining capacity, even as it says something equally real about how exposed that capacity remains to a war showing no sign of ending.

THE POLITICS OF A COMPANY THAT CANNOT AFFORD TO ADMIT WEAKNESS

Rosneft’s dividend policy through this entire period reads like a company determined to project stability regardless of what the underlying numbers say. The company paid five hundred forty two billion rubles in dividends for 2024, fifty one point one five rubles a share, and approved an interim payout of eleven point five six rubles a share for the first half of 2025 even as net income was already collapsing. Management noted the shareholder base grew by nearly a hundred seventy thousand people over the past year, a detail Sechin has used publicly to argue Rosneft maintains financial discipline that rivals fund through debt instead. Whether that framing holds up under continued sanctions pressure is a different question than whether it serves a domestic political purpose right now, reassuring a Russian investing public and a Kremlin leadership that the country’s largest company remains a going concern regardless of what Washington, London, and Brussels do to it in the same news cycle.

Trump’s own posture toward the sanctions leaves the entire arrangement conditional rather than settled. He has indicated willingness to remove the designations entirely if a deal to end the war in Ukraine materializes, meaning Rosneft’s current sanctioned status functions as much as a negotiating instrument aimed at Moscow as a permanent structural change to how the company operates. That conditionality is itself a form of political risk distinct from the sanctions themselves, since any company doing business around Rosneft today has to price in the possibility that the entire regime reverses on a timeline set by diplomacy rather than by markets.

WHAT THE TAPE IS SAYING NOW

Sechin’s own complaint about OPEC driven oversupply is, stripped of its framing, the same mechanism this newsletter keeps returning to under a different name. China exports deflation into whatever industry it decides to scale, and OPEC’s own excess capacity did the same thing to oil throughout 2025, a global supply glut flattening prices for every producer simultaneously regardless of that producer’s sanctions status, war exposure, or balance sheet discipline. Rosneft’s seventy three percent profit collapse happened inside a year when even fully sanctioned producers like Iran and Venezuela found buyers willing to absorb discounted barrels, proof that a determined buyer network, India and China chief among them for Russian crude specifically, can keep volume moving even when price realization gets crushed from every direction at once.

STRESS TEST

Secondary sanctions enforcement is the single largest unknown hanging over the next year. The October designation gave Washington the legal tools to punish any foreign bank or trader that continues facilitating Rosneft transactions, but enforcement intensity is a political choice, not an automatic mechanism, and how aggressively the Trump administration actually pursues violators will determine whether India and China’s buyer networks keep functioning at anything close to current volume.

Refining infrastructure remains exposed to a war Ukraine shows no sign of winding down, and seventeen percent capacity loss at various points through 2025 is not a ceiling, it is simply the level strikes reached so far.

Vostok Oil’s continued capital commitment is a multi year bet on a sanctions and geopolitical environment nobody can currently forecast with any confidence, and every ruble spent on Arctic infrastructure today is a ruble unavailable for near term balance sheet resilience if the current pressure intensifies rather than eases.

THE INSTITUTIONAL LABEL

Rosneft weathers. Sechin’s own word for 2025, an ideal storm, doubles as the company’s entire operating philosophy under both Putin and sanctions regimes stretching back over a decade, absorb whatever hits land, keep production flat, keep the dividend flowing, keep discovering new fields regardless of whether this year’s cash flow can fund next year’s growth. Direct blocking sanctions were supposed to be the mechanism that finally broke this pattern. Twenty two consecutive quarters of positive free cash flow, delivered straight through the worst year Rosneft has reported since the war began, says the pattern is not broken yet.

SOURCES

OilPrice.com, Rosneft first half 2025 results coverage, September 1 2025. Yahoo Finance via OilPrice.com, Rosneft full year 2025 IFRS results coverage, April 1 2026. Euromaidan Press, Rosneft 2025 profit collapse analysis, August 31 2025. The Moscow Times, Rosneft nine month 2025 results, December 1 2025. Steptoe, Covington and Burling, Sullivan and Cromwell, Morrison Foerster, Crowell and Moring, K2 Integrity, and Buchanan Ingersoll and Rooney, legal analysis of the October 22 2025 OFAC designation of Rosneft and Lukoil. Rosneft press release, Sechin remarks at the Doha Forum, December 2024.

July 2022, Fort McMurray. A worker dies at Suncor’s Base Plant mine, the second death that year, the twelfth since 2014.

Mark Little resigns as chief executive the following day. Elliott Investment Management, Paul Singer’s activist fund, had already gone public months earlier accusing Suncor of a broken safety culture and a lagging share price, and within days of Little’s exit Elliott struck a deal to place three directors on the board, two of whom then sat on the committee that hired his replacement. Alberta’s own Occupational Health and Safety division put the company under special monitoring, and Suncor collected thirty two safety violations between November and January, far more than any peer in the province. This is the company Rich Kruger walked into in April 2023, and this is the company that, less than three years later, posted the best operating year in its history while paying that same Rich Kruger thirty six point eight million dollars in a single twelve month stretch.

THE BUSINESS ITSELF, WHICH LOOKS NOTHING LIKE A NORMAL OIL COMPANY

Every issue this newsletter has run so far describes a company drilling a well and selling what comes out of it. Suncor runs a mining and industrial processing operation that happens to end in a barrel of oil, and the distinction changes almost everything about how the economics behave.

Oil sands bitumen does not flow. At room temperature it behaves closer to cold molasses than crude oil, too viscous to pump on its own, and getting it out of the ground splits into two completely different industrial processes depending on how deep the deposit sits. Where bitumen lies within about seventy five metres of the surface, roughly a fifth of Alberta’s total reserves, companies mine it outright. Suncor’s Base Plant runs two such mines, Millennium and North Steepbank, giant shovels loading the oil sand into trucks that haul it to crushers, where hot water gets added to create a slurry that can finally be pumped. That slurry then sits in separation vessels where bitumen froth rises off the top, still mixed with water and fine solids, leaving behind a tailings pond, the toxic containment ponds northern Alberta has become known for, an environmental liability that exists specifically because of the mining method and does not apply to the other four fifths of Alberta’s reserves sitting too deep to reach with a shovel.

That deeper eighty percent gets recovered through steam assisted gravity drainage, SAGD, the technology running Suncor’s Firebag and MacKay River assets. Two horizontal wells get drilled one above the other, steam gets injected continuously into the top well, and as the surrounding rock heats past two hundred degrees Celsius the bitumen thins enough to drain by gravity into the lower well, where it gets pumped to surface. No mining, no tailings pond, none of Base Plant’s truck and shovel footprint, but SAGD carries its own cost, since heating enough steam to melt an entire underground reservoir consumes enormous volumes of natural gas, and the steam to oil ratio, how much steam a well needs to produce one barrel, is the single number that decides whether a SAGD project makes money or loses it.

Either method leaves a company holding raw bitumen that still cannot go anywhere, since pipelines will not carry something this thick without help. Suncor answers this problem two different ways depending on the asset. At Base Plant, bitumen runs through Upgrader 1 and Upgrader 2, a combined capacity above three hundred fifty thousand barrels a day, where the molecule itself gets rebuilt, hydrogen added or carbon stripped out, turning heavy bitumen into synthetic crude oil that trades close to benchmark prices and can be sold to almost any refinery on the continent. Fort Hills takes the opposite route entirely, running its bitumen through a paraffinic froth treatment that strips out the heaviest components without ever touching an upgrader, producing a partially decarbonized product that needs less diluent and comes in, by Suncor’s own figures, forty percent lower in carbon intensity than Base Plant’s fully upgraded barrel and thirty percent lower than Firebag’s raw SAGD output, an inversion of the usual assumption that mining is dirtier than in situ production, true here only because Fort Hills skips the single most energy intensive step in the entire chain.

Whatever bitumen never gets upgraded instead gets blended with diluent, a light hydrocarbon condensate, thin enough that the resulting mixture, dilbit, can finally move down a pipeline. Dilbit still trades at a real discount to lighter crude, priced off Western Canadian Select at Hardisty rather than West Texas Intermediate, because most refineries, including nearly every one in Canada, lack the complexity to process something this heavy and sour, which is why roughly ninety five percent of Alberta’s dilbit historically ends up at the specific American refineries built with the residue conversion and sulphur removal capacity this crude actually requires. Owning upgraders is therefore not a technical footnote, it is a structural hedge against the WCS discount, since SCO prices close to the benchmarks the newsletter otherwise quotes for every conventional producer, while raw dilbit never fully escapes the discount no matter how efficiently it gets produced.

None of this behaves like the shale economics this newsletter covered. A Permian well can decline seventy percent in its first year alone, forcing constant reinvestment in new wells just to hold production flat. An oil sands mine or a mature SAGD pad declines barely at all once fully developed, the capital gets spent almost entirely upfront in the mine, the upgrader, or the well pads, and the entire subsequent economics reduce to running that fixed asset base as close to its physical ceiling as engineering allows. That is the actual reason a hundred nine percent upgrader utilization at Syncrude and a hundred three percent at Base Plant matter as much as they do in the numbers below. This is not a company finding new barrels the way a shale operator does. It is a company that already owns every barrel it will ever produce from a given asset and is being judged on how hard it can run the machine it already built.

THE TURNAROUND, MEASURED IN RECORDS

Suncor closed 2025 with upstream production averaging eight hundred sixty thousand barrels a day, thirty three thousand more than 2024 and a full company record, alongside record refining throughput of four hundred eighty thousand barrels a day and record refined product sales of six hundred twenty three thousand barrels a day. Fourth quarter upstream production alone hit nine hundred nine thousand barrels a day, synthetic crude oil production reaching a quarterly record five hundred fifty seven thousand barrels a day on upgrader utilization of a hundred nine percent at Syncrude and a hundred three percent at the Base Plant, both running above nameplate capacity simultaneously. Chief executive Kruger told analysts the production and refining teams have not just been breaking records, they have been shattering them at the high end of guidance for two straight years.

The cash generation matches the operational story. Full year adjusted funds from operations came to twelve point eight billion dollars, free funds flow six point nine billion, with roughly five point eight billion returned to shareholders through buybacks and dividends. Net debt fell to the company’s own eight billion dollar target a full year ahead of the schedule Kruger set at his first Investor Day in 2024, hit despite a fourth quarter where adjusted operating earnings actually declined, from one point five six six billion dollars to one point three two five billion, purely on weaker upstream price realizations, since a global supply glut has kept crude prices soft even as Suncor’s own output climbed to records. Net earnings for the quarter still rose sharply regardless, one point four seven six billion dollars against eight hundred eighteen million a year earlier, a gap wide enough that the difference between adjusted operating earnings and reported net earnings has become its own small lesson in why the two numbers exist separately, one measuring the underlying business, the other capturing everything else moving through the balance sheet in a single quarter.

THE ARITHMETIC OF THE TURNAROUND ITSELF

Kruger’s method has been blunt and consistent since his first week. Cut the organization down to what actually generates revenue, sell what does not fit, and hold the rest to a standard he calls best in class. Suncor cut fifteen hundred jobs in 2024 alone as part of a push targeting four hundred fifty million dollars in annual savings, divested oil and gas assets in the United Kingdom and Norway, exited its renewable energy portfolio entirely, and seriously considered selling the Petro Canada retail network before concluding the business would not fetch the premium the company wanted, keeping it instead. Every one of these moves happened inside the same eighteen month window that also delivered the safety turnaround Elliott had originally demanded, and inside the same window Kruger himself collected a first year compensation package worth thirty six point eight million dollars, including twenty three point one million in restricted stock explicitly structured to replace pension benefits he gave up by coming out of retirement to take the job.

There is a real tension sitting inside those two facts sitting next to each other, a company that just cut fifteen hundred jobs in the name of organizational discipline paying its own chief executive more in one year than most of those fifteen hundred workers would earn across their entire careers combined. Kruger’s own framing of the job has been unapologetic about this from the start. He told investors early on that Suncor exists to make money, as much of it as possible, and that everybody starting with himself needs to understand how their role contributes to that goal. The market has rewarded exactly this framing, and Alberta’s own government has increasingly organized its own energy policy around companies that think the same way.

THE POLITICS EVERY CALGARY READER ALREADY LIVES INSIDE

Danielle Smith’s government has spent the better part of a year rebuilding Alberta’s relationship with Ottawa around a single trade, carbon policy flexibility in exchange for pipeline cooperation, and Suncor sits inside both halves of that trade simultaneously. In November 2025, Prime Minister Mark Carney and Smith signed a memorandum committing both governments to work toward a new bitumen pipeline running from Alberta to British Columbia’s coast, capable of carrying more than a million barrels a day to Asian markets. In May 2026 the two governments signed an implementation agreement locking Alberta’s industrial carbon price on a path to a hundred thirty dollars a tonne by 2040, well below the hundred seventy dollar by 2030 trajectory Ottawa had previously set nationally, in exchange for Alberta submitting a formal pipeline proposal to the federal Major Projects Office by July 1 2026, with Ottawa committing to decide by October 1 whether to fast track it as a project of national interest.

Suncor is not a bystander in this negotiation. The company is a member of the Oil Sands Alliance, formerly known as Pathways, the industry consortium alongside Canadian Natural Resources, Cenovus, Imperial Oil, and ConocoPhillips Canada building a multi billion dollar carbon capture and storage network designed to cut oil sands emissions by sixteen million tonnes annually by 2045. The federal government has made completion of that project’s first phase an explicit precondition for the pipeline moving forward at all, which means Suncor’s own emissions infrastructure spending is now load bearing for whether Alberta gets the export capacity its entire industry says it needs.

None of this is settled. No private company has yet stepped forward to actually build the pipeline, forcing Alberta’s own government to act as proponent, spending fourteen million dollars of public money on technical planning specifically to give private capital enough confidence to eventually take over. Federal legislation Smith has spent a year lobbying to remove, the tanker ban on British Columbia’s northern coast and the broader emissions cap critics still call the no pipelines act, both remain in place even as the pipeline proposal itself moves forward, meaning Alberta could conceivably build the line and still lack legal clearance to load a tanker at the other end of it. The earliest realistic date for shovels in the ground sits at September 2027, itself described by Alberta’s own government as a best case scenario rather than a commitment.

WHAT THE TAPE IS SAYING NOW

Suncor’s own results carry the same signature this newsletter has tracked all year in other producers, record output landing inside a market too oversupplied to reward it fully in price. China exports deflation into whatever industry it decides to scale, and 2025’s global oil market ran the same play through supply rather than manufacturing, enough barrels from enough producers that even a company setting production records every single quarter still watched its price realizations fall quarter over quarter. Kruger’s entire operating philosophy, radical cost discipline paired with maximum utilization, is essentially a bet that a company can win a low price environment through volume and efficiency rather than waiting for prices to recover on their own, the same logic Aramco applies at a sovereign scale and the same logic this newsletter’s Halliburton coverage showed can fail badly when a company has no efficiency lever left to pull.

STRESS TEST

Political risk is not hypothetical here, it is contractual. The pipeline Alberta needs to justify further production growth is explicitly conditioned on the Pathways carbon capture project reaching completion, meaning Suncor’s own capital spending on emissions infrastructure has become a precondition for its own future export capacity, a dependency neither governor fully controls.

Safety culture risk never fully disappears once a company has been through what Suncor went through. Kruger’s efficiency first mandate delivered the operational turnaround Elliott demanded, but a culture built around cutting fifteen hundred jobs and maximizing utilization above a hundred percent at every upgrader simultaneously carries an inherent tension with the safety discipline that got the company into this position in the first place, a tension the company’s own record will only fully answer over a longer stretch than two good years.

Commodity oversupply remains entirely outside Suncor’s control regardless of how well the company executes. Record production met with falling price realizations in the same quarter is a company doing everything right inside a market doing the opposite, and no amount of internal discipline changes the global supply picture Suncor’s own results are currently swimming against.

THE INSTITUTIONAL LABEL

Suncor tightens. A company that spent a decade losing workers and losing credibility, until an activist investor and a board reshuffle forced in a chief executive whose entire operating philosophy is subtraction, fewer jobs, fewer distractions, fewer excuses, more barrels out of the same assets running harder than anyone thought they could. It worked, by every operational measure this newsletter can find. Whether it worked in the way Elliott originally demanded, a genuinely safer company rather than merely a more profitable one, is the one number Suncor has not yet had to report back on over enough years to know for certain.

SOURCES

Suncor Energy fourth quarter and full year 2025 results, news release and quarterly report, February 3 2026. The Globe and Mail, Suncor record 2025 results coverage, February 4 2026. EnergyNow, Bloomberg, CBC News, and Mining.com, Rich Kruger appointment and Elliott Investment Management campaign coverage, February through May 2023. The Globe and Mail, Suncor CEO compensation disclosure, March 26 2024. Global News, CBC News, the Prime Minister of Canada’s office, EnergyNow, and the Fraser Institute, Alberta and federal government pipeline and carbon policy negotiations, October 2025 through July 2026.

July 2022, Fort McMurray. A worker dies at Suncor’s Base Plant mine, the second death that year, the twelfth since 2014.

Mark Little resigns as chief executive the following day. Elliott Investment Management, Paul Singer’s activist fund, had already gone public months earlier accusing Suncor of a broken safety culture and a lagging share price, and within days of Little’s exit Elliott struck a deal to place three directors on the board, two of whom then sat on the committee that hired his replacement. Alberta’s own Occupational Health and Safety division put the company under special monitoring, and Suncor collected thirty two safety violations between November and January, far more than any peer in the province. This is the company Rich Kruger walked into in April 2023, and this is the company that, less than three years later, posted the best operating year in its history while paying that same Rich Kruger thirty six point eight million dollars in a single twelve month stretch.

THE BUSINESS ITSELF, WHICH LOOKS NOTHING LIKE A NORMAL OIL COMPANY

Every issue this newsletter has run so far describes a company drilling a well and selling what comes out of it. Suncor runs a mining and industrial processing operation that happens to end in a barrel of oil, and the distinction changes almost everything about how the economics behave.

Oil sands bitumen does not flow. At room temperature it behaves closer to cold molasses than crude oil, too viscous to pump on its own, and getting it out of the ground splits into two completely different industrial processes depending on how deep the deposit sits. Where bitumen lies within about seventy five metres of the surface, roughly a fifth of Alberta’s total reserves, companies mine it outright. Suncor’s Base Plant runs two such mines, Millennium and North Steepbank, giant shovels loading the oil sand into trucks that haul it to crushers, where hot water gets added to create a slurry that can finally be pumped. That slurry then sits in separation vessels where bitumen froth rises off the top, still mixed with water and fine solids, leaving behind a tailings pond, the toxic containment ponds northern Alberta has become known for, an environmental liability that exists specifically because of the mining method and does not apply to the other four fifths of Alberta’s reserves sitting too deep to reach with a shovel.

That deeper eighty percent gets recovered through steam assisted gravity drainage, SAGD, the technology running Suncor’s Firebag and MacKay River assets. Two horizontal wells get drilled one above the other, steam gets injected continuously into the top well, and as the surrounding rock heats past two hundred degrees Celsius the bitumen thins enough to drain by gravity into the lower well, where it gets pumped to surface. No mining, no tailings pond, none of Base Plant’s truck and shovel footprint, but SAGD carries its own cost, since heating enough steam to melt an entire underground reservoir consumes enormous volumes of natural gas, and the steam to oil ratio, how much steam a well needs to produce one barrel, is the single number that decides whether a SAGD project makes money or loses it.

Either method leaves a company holding raw bitumen that still cannot go anywhere, since pipelines will not carry something this thick without help. Suncor answers this problem two different ways depending on the asset. At Base Plant, bitumen runs through Upgrader 1 and Upgrader 2, a combined capacity above three hundred fifty thousand barrels a day, where the molecule itself gets rebuilt, hydrogen added or carbon stripped out, turning heavy bitumen into synthetic crude oil that trades close to benchmark prices and can be sold to almost any refinery on the continent. Fort Hills takes the opposite route entirely, running its bitumen through a paraffinic froth treatment that strips out the heaviest components without ever touching an upgrader, producing a partially decarbonized product that needs less diluent and comes in, by Suncor’s own figures, forty percent lower in carbon intensity than Base Plant’s fully upgraded barrel and thirty percent lower than Firebag’s raw SAGD output, an inversion of the usual assumption that mining is dirtier than in situ production, true here only because Fort Hills skips the single most energy intensive step in the entire chain.

Whatever bitumen never gets upgraded instead gets blended with diluent, a light hydrocarbon condensate, thin enough that the resulting mixture, dilbit, can finally move down a pipeline. Dilbit still trades at a real discount to lighter crude, priced off Western Canadian Select at Hardisty rather than West Texas Intermediate, because most refineries, including nearly every one in Canada, lack the complexity to process something this heavy and sour, which is why roughly ninety five percent of Alberta’s dilbit historically ends up at the specific American refineries built with the residue conversion and sulphur removal capacity this crude actually requires. Owning upgraders is therefore not a technical footnote, it is a structural hedge against the WCS discount, since SCO prices close to the benchmarks the newsletter otherwise quotes for every conventional producer, while raw dilbit never fully escapes the discount no matter how efficiently it gets produced.

None of this behaves like the shale economics this newsletter covered. A Permian well can decline seventy percent in its first year alone, forcing constant reinvestment in new wells just to hold production flat. An oil sands mine or a mature SAGD pad declines barely at all once fully developed, the capital gets spent almost entirely upfront in the mine, the upgrader, or the well pads, and the entire subsequent economics reduce to running that fixed asset base as close to its physical ceiling as engineering allows. That is the actual reason a hundred nine percent upgrader utilization at Syncrude and a hundred three percent at Base Plant matter as much as they do in the numbers below. This is not a company finding new barrels the way a shale operator does. It is a company that already owns every barrel it will ever produce from a given asset and is being judged on how hard it can run the machine it already built.

THE TURNAROUND, MEASURED IN RECORDS

Suncor closed 2025 with upstream production averaging eight hundred sixty thousand barrels a day, thirty three thousand more than 2024 and a full company record, alongside record refining throughput of four hundred eighty thousand barrels a day and record refined product sales of six hundred twenty three thousand barrels a day. Fourth quarter upstream production alone hit nine hundred nine thousand barrels a day, synthetic crude oil production reaching a quarterly record five hundred fifty seven thousand barrels a day on upgrader utilization of a hundred nine percent at Syncrude and a hundred three percent at the Base Plant, both running above nameplate capacity simultaneously. Chief executive Kruger told analysts the production and refining teams have not just been breaking records, they have been shattering them at the high end of guidance for two straight years.

The cash generation matches the operational story. Full year adjusted funds from operations came to twelve point eight billion dollars, free funds flow six point nine billion, with roughly five point eight billion returned to shareholders through buybacks and dividends. Net debt fell to the company’s own eight billion dollar target a full year ahead of the schedule Kruger set at his first Investor Day in 2024, hit despite a fourth quarter where adjusted operating earnings actually declined, from one point five six six billion dollars to one point three two five billion, purely on weaker upstream price realizations, since a global supply glut has kept crude prices soft even as Suncor’s own output climbed to records. Net earnings for the quarter still rose sharply regardless, one point four seven six billion dollars against eight hundred eighteen million a year earlier, a gap wide enough that the difference between adjusted operating earnings and reported net earnings has become its own small lesson in why the two numbers exist separately, one measuring the underlying business, the other capturing everything else moving through the balance sheet in a single quarter.

THE ARITHMETIC OF THE TURNAROUND ITSELF

Kruger’s method has been blunt and consistent since his first week. Cut the organization down to what actually generates revenue, sell what does not fit, and hold the rest to a standard he calls best in class. Suncor cut fifteen hundred jobs in 2024 alone as part of a push targeting four hundred fifty million dollars in annual savings, divested oil and gas assets in the United Kingdom and Norway, exited its renewable energy portfolio entirely, and seriously considered selling the Petro Canada retail network before concluding the business would not fetch the premium the company wanted, keeping it instead. Every one of these moves happened inside the same eighteen month window that also delivered the safety turnaround Elliott had originally demanded, and inside the same window Kruger himself collected a first year compensation package worth thirty six point eight million dollars, including twenty three point one million in restricted stock explicitly structured to replace pension benefits he gave up by coming out of retirement to take the job.

There is a real tension sitting inside those two facts sitting next to each other, a company that just cut fifteen hundred jobs in the name of organizational discipline paying its own chief executive more in one year than most of those fifteen hundred workers would earn across their entire careers combined. Kruger’s own framing of the job has been unapologetic about this from the start. He told investors early on that Suncor exists to make money, as much of it as possible, and that everybody starting with himself needs to understand how their role contributes to that goal. The market has rewarded exactly this framing, and Alberta’s own government has increasingly organized its own energy policy around companies that think the same way.

THE POLITICS EVERY CALGARY READER ALREADY LIVES INSIDE

Danielle Smith’s government has spent the better part of a year rebuilding Alberta’s relationship with Ottawa around a single trade, carbon policy flexibility in exchange for pipeline cooperation, and Suncor sits inside both halves of that trade simultaneously. In November 2025, Prime Minister Mark Carney and Smith signed a memorandum committing both governments to work toward a new bitumen pipeline running from Alberta to British Columbia’s coast, capable of carrying more than a million barrels a day to Asian markets. In May 2026 the two governments signed an implementation agreement locking Alberta’s industrial carbon price on a path to a hundred thirty dollars a tonne by 2040, well below the hundred seventy dollar by 2030 trajectory Ottawa had previously set nationally, in exchange for Alberta submitting a formal pipeline proposal to the federal Major Projects Office by July 1 2026, with Ottawa committing to decide by October 1 whether to fast track it as a project of national interest.

Suncor is not a bystander in this negotiation. The company is a member of the Oil Sands Alliance, formerly known as Pathways, the industry consortium alongside Canadian Natural Resources, Cenovus, Imperial Oil, and ConocoPhillips Canada building a multi billion dollar carbon capture and storage network designed to cut oil sands emissions by sixteen million tonnes annually by 2045. The federal government has made completion of that project’s first phase an explicit precondition for the pipeline moving forward at all, which means Suncor’s own emissions infrastructure spending is now load bearing for whether Alberta gets the export capacity its entire industry says it needs.

None of this is settled. No private company has yet stepped forward to actually build the pipeline, forcing Alberta’s own government to act as proponent, spending fourteen million dollars of public money on technical planning specifically to give private capital enough confidence to eventually take over. Federal legislation Smith has spent a year lobbying to remove, the tanker ban on British Columbia’s northern coast and the broader emissions cap critics still call the no pipelines act, both remain in place even as the pipeline proposal itself moves forward, meaning Alberta could conceivably build the line and still lack legal clearance to load a tanker at the other end of it. The earliest realistic date for shovels in the ground sits at September 2027, itself described by Alberta’s own government as a best case scenario rather than a commitment.

WHAT THE TAPE IS SAYING NOW

Suncor’s own results carry the same signature this newsletter has tracked all year in other producers, record output landing inside a market too oversupplied to reward it fully in price. China exports deflation into whatever industry it decides to scale, and 2025’s global oil market ran the same play through supply rather than manufacturing, enough barrels from enough producers that even a company setting production records every single quarter still watched its price realizations fall quarter over quarter. Kruger’s entire operating philosophy, radical cost discipline paired with maximum utilization, is essentially a bet that a company can win a low price environment through volume and efficiency rather than waiting for prices to recover on their own, the same logic Aramco applies at a sovereign scale and the same logic this newsletter’s Halliburton coverage showed can fail badly when a company has no efficiency lever left to pull.

STRESS TEST

Political risk is not hypothetical here, it is contractual. The pipeline Alberta needs to justify further production growth is explicitly conditioned on the Pathways carbon capture project reaching completion, meaning Suncor’s own capital spending on emissions infrastructure has become a precondition for its own future export capacity, a dependency neither governor fully controls.

Safety culture risk never fully disappears once a company has been through what Suncor went through. Kruger’s efficiency first mandate delivered the operational turnaround Elliott demanded, but a culture built around cutting fifteen hundred jobs and maximizing utilization above a hundred percent at every upgrader simultaneously carries an inherent tension with the safety discipline that got the company into this position in the first place, a tension the company’s own record will only fully answer over a longer stretch than two good years.

Commodity oversupply remains entirely outside Suncor’s control regardless of how well the company executes. Record production met with falling price realizations in the same quarter is a company doing everything right inside a market doing the opposite, and no amount of internal discipline changes the global supply picture Suncor’s own results are currently swimming against.

THE INSTITUTIONAL LABEL

Suncor tightens. A company that spent a decade losing workers and losing credibility, until an activist investor and a board reshuffle forced in a chief executive whose entire operating philosophy is subtraction, fewer jobs, fewer distractions, fewer excuses, more barrels out of the same assets running harder than anyone thought they could. It worked, by every operational measure this newsletter can find. Whether it worked in the way Elliott originally demanded, a genuinely safer company rather than merely a more profitable one, is the one number Suncor has not yet had to report back on over enough years to know for certain.

SOURCES

Suncor Energy fourth quarter and full year 2025 results, news release and quarterly report, February 3 2026. The Globe and Mail, Suncor record 2025 results coverage, February 4 2026. EnergyNow, Bloomberg, CBC News, and Mining.com, Rich Kruger appointment and Elliott Investment Management campaign coverage, February through May 2023. The Globe and Mail, Suncor CEO compensation disclosure, March 26 2024. Global News, CBC News, the Prime Minister of Canada’s office, EnergyNow, and the Fraser Institute, Alberta and federal government pipeline and carbon policy negotiations, October 2025 through July 2026.

Gustavo Petro built his presidency on a promise to wean Colombia off hydrocarbons, banning new coal, gas, and oil exploration contracts the moment he took office, folding the whole program into something his government calls the Just Energy Transition. In April 2023 he installed Ricardo Roa, the man who had managed his own 2022 campaign, as president of Ecopetrol, the state oil company that generates roughly a third of Colombia’s fiscal revenue and forty percent of its exports. Two years later Roa stood on an earnings call and told investors exploration is what gives an oil company long term stability, that Ecopetrol has not stopped signing new search contracts, and that he hoped the debate over the ban would continue. The president’s own handpicked loyalist became the loudest institutional voice against the president’s own signature energy policy, and neither man has backed down since.

That contradiction alone would carry an issue. Colombia gave this newsletter a second one for free. Roa is currently facing criminal charges for violating campaign spending limits during the same 2022 campaign he ran, plus a separate influence peddling indictment tied to a liquefied natural gas contract at Ecopetrol subsidiary Hocol, plus scrutiny over a luxury apartment purchase, plus a surveillance scandal in which the company paid an American law firm to analyze the private data of seventy employees, including his own. On April 7 2026, Ecopetrol’s board finally forced him out, not through resignation, but through a procedural maneuver, assigning him early vacation followed by unpaid leave running until after Colombia’s presidential election. Petro is still defending him publicly. The stock, in the meantime, went up.

THE NUMBERS, WHERE PETRO’S OWN POLICY COLLIDED WITH THE BALANCE SHEET

Ecopetrol closed 2025 with EBITDA of forty six point seven trillion pesos, a thirty nine percent margin, and net income of nine trillion pesos, down thirty nine point five percent from fourteen point nine trillion the year before. The decline traces directly to a Brent price that fell nearly fifteen percent across the year, a macro headwind no amount of internal efficiency could fully offset. What the efficiency program did offset was significant. Reserve replacement reached a hundred twenty one percent, the highest level in four years, meaning Ecopetrol added more proven reserves than it produced, an unusual accomplishment for a company operating inside a country whose own president has spent three years actively discouraging new exploration. The company beat its 2025 drilling target by sixty percent, completing sixteen wells against plan, and posted a three year exploration success rate forty four percent above the industry average. Average daily production held at seven hundred forty five thousand barrels, transportation volumes surpassed one point one million barrels a day, and refining throughput reached four hundred seventeen thousand barrels daily. The company’s crude differential against Brent improved to four dollars sixty cents a barrel, the best result in four years, driven by market diversification and trading desk coordination out of Houston and Singapore. Total contribution to the Colombian state, dividends, taxes, and royalties combined, came to thirty four point six trillion pesos for the year, on top of eight point eight trillion pesos in dividends paid mid year alone, a ten percent yield.

None of these numbers describe a company being managed toward extinction. They describe a company that spent 2025 doing the opposite of what its own president’s public rhetoric would predict, expanding its reserve base, beating its own drilling targets, and improving its trading economics, while paying the Colombian treasury more than a third of its entire EBITDA in the same year Petro’s Just Energy Transition supposedly aimed to shrink the company’s relevance to the national budget.

THE PERMIAN QUESTION PETRO WANTS ANSWERED THE OPPOSITE WAY

Here the contradiction sharpens into something closer to absurdity. A meaningful share of Ecopetrol’s 2025 production growth came from Permian Basin assets in the United States, alongside Colombia’s own Caño Sur field and a forty five percent stake acquired in block CPO 09. Petro, in the middle of the Roa corruption crisis, publicly called on Ecopetrol to sell its American fracking operations entirely, redirecting the proceeds into clean energy generation, artificial intelligence infrastructure, and submarine fiber optic cable, framing hydrocarbons as inconvenient everywhere in the world regardless of where they are extracted.

The demand arrives at the exact moment the Permian position is helping carry the company’s production numbers through a year Colombian output alone could not have sustained on its own. Selling the American shale assets Petro wants gone would remove one of the few genuine growth levers Ecopetrol has left inside a domestic policy environment explicitly designed to prevent new growth from Colombian soil. The president who will not let Ecopetrol drill new exploration wells at home is simultaneously demanding the company abandon the wells abroad that have been quietly compensating for that restriction. Colombia’s Senate already passed a permanent fracking ban in April 2025 under Petro’s own Pacto Historico coalition, a bill still awaiting House confirmation, meaning the domestic door and the foreign door could both close within the same political term if Petro gets everything he has publicly asked for.

ROA, THE MAN WHO BROKE FROM THE MANDATE THAT MADE HIM

Roa’s break from Petro’s own exploration ban was not a quiet policy disagreement handled in private. It happened in public, on an earnings call, from the man Petro had personally installed specifically because of his loyalty. The irony compounds from there. Colombia’s National Electoral Council found Roa responsible for exceeding legal campaign spending limits by more than five point three billion pesos while running Petro’s second round campaign in 2022, an unprecedented ruling against a sitting state company president. Prosecutors separately charged him with influence peddling, alleging he pressured Hocol’s then president to steer a Chuchupa Ballena LNG regasification contract toward a company tied to a specific businessman ally. A parallel investigation into how Roa purchased a luxury Bogota apartment led to a formal accusation of trafficking in influence over that transaction as well, with a trial now scheduled. Underneath all of it sits the surveillance scandal, a five million dollar contract with Covington and Burling to analyze data from seventy employees, ostensibly for cybersecurity reasons, that both Ecopetrol’s own compliance leadership and Petro himself have since distanced themselves from.

Petro’s response to all of this has been full throated defense rather than distance. He has accused business groups aligned with former president Alvaro Uribe of orchestrating the entire campaign against Roa specifically to seize control of twenty trillion pesos in oil and gas contracts set to expire within a month of the accusations peaking, framing the corruption case as a corporate takeover attempt dressed up as a legal process. He has pointed to Ecopetrol’s rising share price as proof the market does not believe the crisis is real, attributing the rally instead to international oil prices and stable domestic production. He has publicly recounted a February 2026 meeting with Donald Trump, describing what he called a trap embedded in an official White House photograph, while insisting he has never heard a single hostile word from anyone in the American government about Ecopetrol specifically. None of this reads like a president preparing to let his own appointee go quietly. It reads like a president who understands that Roa’s fall implicates his own campaign’s financing at the exact moment Colombia heads into a presidential election.

THE POLITICS OF A COMPANY CAUGHT BETWEEN TWO ELECTIONS

Ecopetrol’s board scheduled Roa’s forced leave to run specifically until after Colombia’s presidential election, an unmistakable signal that the company’s own governance has become inseparable from the country’s electoral calendar. The Union Sindical Obrera, representing a meaningful share of Ecopetrol’s eighty seven thousand employees and contractors, has demanded Roa’s outright resignation and threatened mobilization affecting roughly twenty five thousand workers if the board fails to act, pressure that ultimately contributed to the April removal even as Petro’s allies on the board tried to hold the line. Minority shareholders, exposed to Ecopetrol’s dual listing on the Colombian exchange and the New York Stock Exchange, wrote directly to Petro and the board warning that Roa’s continued leadership was actively devaluing the shares regardless of the presumption of innocence Petro kept invoking on his behalf.

The deeper political fight is about who gets to decide what a state oil company is for. Petro has argued explicitly that hydrocarbons are inconvenient everywhere in the world and that every barrel extracted only accelerates a well’s own exhaustion, a philosophical position most Colombian oil executives, including his own appointee, do not share. Roa has argued the opposite, that exploration is the only mechanism that gives a hydrocarbon company long term stability, and that Colombia’s fiscal dependence on hydrocarbon revenue, more than twenty percent of public revenue and more than half of exports according to independent estimates, cannot responsibly be unwound overnight regardless of the ideological commitment behind the effort. Both men are describing the same company. Neither is wrong about the numbers they are citing. They are simply optimizing for different clocks, Petro for a multi decade energy transition he may not be in office to see through, Roa for a company that has to report quarterly results to shareholders in two countries regardless of which transition timeline eventually wins.

WHAT THE TAPE IS SAYING NOW

Petro’s own defense of Roa leaned on the fact that Ecopetrol’s shares rose even as the corruption scandal peaked, crediting rising international oil prices and stable domestic production. He is not wrong about the mechanism, only about what it proves. Brent’s climb during the 2026 Iran war lifted every producer’s revenue regardless of that producer’s internal governance quality, the same tide that carried Aramco, Petrobras, and Pemex through their own respective crises earlier in this newsletter’s coverage. China exports deflation into whatever industry it decides to scale, and oil prices during a supply shock export the opposite, a rising tide that flatters management teams and corrupt ones in exactly the same proportion, for exactly as long as the shock lasts. A share price rally driven by a war seven thousand miles away says nothing about whether Ecopetrol’s own governance crisis has actually been resolved, and everything about how easily external tailwinds can be mistaken for internal vindication.

STRESS TEST

Governance risk is the whole story here, not a footnote to it. A state company with three separate criminal proceedings circling its chief executive, a board split between operational stability and reputational risk, and a workforce publicly threatening mobilization, is not a company operating with a clear hand at the wheel, regardless of how strong the underlying production numbers look on paper.

Policy whiplash risk sits directly beneath the governance risk. Colombia’s presidential election could install a government that either accelerates the exploration ban Roa has been quietly ignoring or abandons it entirely, and Ecopetrol’s own five year capital plan cannot be built with confidence until that outcome is known, a timing problem no efficiency program can engineer around.

The Permian question remains unresolved and consequential either way. Selling the American shale assets Petro wants gone would remove a genuine growth lever precisely when domestic exploration remains politically constrained. Keeping them defies the president’s own stated energy philosophy indefinitely, a contradiction the company has so far managed by simply not choosing, an option that will not remain available forever.

THE INSTITUTIONAL LABEL

Ecopetrol defies. Installed with a mandate to help shrink Colombia’s hydrocarbon dependence, run by a man who spent his tenure arguing the opposite in public, propped up through a corruption crisis by a war on the other side of the planet, and still generating more cash for the Colombian treasury than almost any policy debate in Bogota seems willing to acknowledge. The company was built to be an instrument of the president’s own energy transition. Instead it became the loudest institutional argument against it, run by the one man who owed Petro everything and used that position to say no anyway.

SOURCES

Ecopetrol fourth quarter and full year 2025 results, SEC Form 6-K filings, and PRNewswire coverage, first through fourth quarter 2025. IndexBox, Ecopetrol 2025 financial results summary, March 2026. Portafolio, El Colombiano, Infobae, RTVC Noticias, and ColombiaOne, coverage of the Ricardo Roa corruption case and board removal, February through April 2026. Bloomberg, Ecopetrol CEO charges reporting, February 9 2026. S&P Global Commodity Insights, Roa’s public break from Petro’s exploration ban, May 2023. Latin America Reports, Ecopetrol surveillance scandal and Petro’s call to sell US fracking assets, June 2025.

Gustavo Petro built his presidency on a promise to wean Colombia off hydrocarbons, banning new coal, gas, and oil exploration contracts the moment he took office, folding the whole program into something his government calls the Just Energy Transition. In April 2023 he installed Ricardo Roa, the man who had managed his own 2022 campaign, as president of Ecopetrol, the state oil company that generates roughly a third of Colombia’s fiscal revenue and forty percent of its exports. Two years later Roa stood on an earnings call and told investors exploration is what gives an oil company long term stability, that Ecopetrol has not stopped signing new search contracts, and that he hoped the debate over the ban would continue. The president’s own handpicked loyalist became the loudest institutional voice against the president’s own signature energy policy, and neither man has backed down since.

That contradiction alone would carry an issue. Colombia gave this newsletter a second one for free. Roa is currently facing criminal charges for violating campaign spending limits during the same 2022 campaign he ran, plus a separate influence peddling indictment tied to a liquefied natural gas contract at Ecopetrol subsidiary Hocol, plus scrutiny over a luxury apartment purchase, plus a surveillance scandal in which the company paid an American law firm to analyze the private data of seventy employees, including his own. On April 7 2026, Ecopetrol’s board finally forced him out, not through resignation, but through a procedural maneuver, assigning him early vacation followed by unpaid leave running until after Colombia’s presidential election. Petro is still defending him publicly. The stock, in the meantime, went up.

THE NUMBERS, WHERE PETRO’S OWN POLICY COLLIDED WITH THE BALANCE SHEET

Ecopetrol closed 2025 with EBITDA of forty six point seven trillion pesos, a thirty nine percent margin, and net income of nine trillion pesos, down thirty nine point five percent from fourteen point nine trillion the year before. The decline traces directly to a Brent price that fell nearly fifteen percent across the year, a macro headwind no amount of internal efficiency could fully offset. What the efficiency program did offset was significant. Reserve replacement reached a hundred twenty one percent, the highest level in four years, meaning Ecopetrol added more proven reserves than it produced, an unusual accomplishment for a company operating inside a country whose own president has spent three years actively discouraging new exploration. The company beat its 2025 drilling target by sixty percent, completing sixteen wells against plan, and posted a three year exploration success rate forty four percent above the industry average. Average daily production held at seven hundred forty five thousand barrels, transportation volumes surpassed one point one million barrels a day, and refining throughput reached four hundred seventeen thousand barrels daily. The company’s crude differential against Brent improved to four dollars sixty cents a barrel, the best result in four years, driven by market diversification and trading desk coordination out of Houston and Singapore. Total contribution to the Colombian state, dividends, taxes, and royalties combined, came to thirty four point six trillion pesos for the year, on top of eight point eight trillion pesos in dividends paid mid year alone, a ten percent yield.

None of these numbers describe a company being managed toward extinction. They describe a company that spent 2025 doing the opposite of what its own president’s public rhetoric would predict, expanding its reserve base, beating its own drilling targets, and improving its trading economics, while paying the Colombian treasury more than a third of its entire EBITDA in the same year Petro’s Just Energy Transition supposedly aimed to shrink the company’s relevance to the national budget.

THE PERMIAN QUESTION PETRO WANTS ANSWERED THE OPPOSITE WAY

Here the contradiction sharpens into something closer to absurdity. A meaningful share of Ecopetrol’s 2025 production growth came from Permian Basin assets in the United States, alongside Colombia’s own Caño Sur field and a forty five percent stake acquired in block CPO 09. Petro, in the middle of the Roa corruption crisis, publicly called on Ecopetrol to sell its American fracking operations entirely, redirecting the proceeds into clean energy generation, artificial intelligence infrastructure, and submarine fiber optic cable, framing hydrocarbons as inconvenient everywhere in the world regardless of where they are extracted.

The demand arrives at the exact moment the Permian position is helping carry the company’s production numbers through a year Colombian output alone could not have sustained on its own. Selling the American shale assets Petro wants gone would remove one of the few genuine growth levers Ecopetrol has left inside a domestic policy environment explicitly designed to prevent new growth from Colombian soil. The president who will not let Ecopetrol drill new exploration wells at home is simultaneously demanding the company abandon the wells abroad that have been quietly compensating for that restriction. Colombia’s Senate already passed a permanent fracking ban in April 2025 under Petro’s own Pacto Historico coalition, a bill still awaiting House confirmation, meaning the domestic door and the foreign door could both close within the same political term if Petro gets everything he has publicly asked for.

ROA, THE MAN WHO BROKE FROM THE MANDATE THAT MADE HIM

Roa’s break from Petro’s own exploration ban was not a quiet policy disagreement handled in private. It happened in public, on an earnings call, from the man Petro had personally installed specifically because of his loyalty. The irony compounds from there. Colombia’s National Electoral Council found Roa responsible for exceeding legal campaign spending limits by more than five point three billion pesos while running Petro’s second round campaign in 2022, an unprecedented ruling against a sitting state company president. Prosecutors separately charged him with influence peddling, alleging he pressured Hocol’s then president to steer a Chuchupa Ballena LNG regasification contract toward a company tied to a specific businessman ally. A parallel investigation into how Roa purchased a luxury Bogota apartment led to a formal accusation of trafficking in influence over that transaction as well, with a trial now scheduled. Underneath all of it sits the surveillance scandal, a five million dollar contract with Covington and Burling to analyze data from seventy employees, ostensibly for cybersecurity reasons, that both Ecopetrol’s own compliance leadership and Petro himself have since distanced themselves from.

Petro’s response to all of this has been full throated defense rather than distance. He has accused business groups aligned with former president Alvaro Uribe of orchestrating the entire campaign against Roa specifically to seize control of twenty trillion pesos in oil and gas contracts set to expire within a month of the accusations peaking, framing the corruption case as a corporate takeover attempt dressed up as a legal process. He has pointed to Ecopetrol’s rising share price as proof the market does not believe the crisis is real, attributing the rally instead to international oil prices and stable domestic production. He has publicly recounted a February 2026 meeting with Donald Trump, describing what he called a trap embedded in an official White House photograph, while insisting he has never heard a single hostile word from anyone in the American government about Ecopetrol specifically. None of this reads like a president preparing to let his own appointee go quietly. It reads like a president who understands that Roa’s fall implicates his own campaign’s financing at the exact moment Colombia heads into a presidential election.

THE POLITICS OF A COMPANY CAUGHT BETWEEN TWO ELECTIONS

Ecopetrol’s board scheduled Roa’s forced leave to run specifically until after Colombia’s presidential election, an unmistakable signal that the company’s own governance has become inseparable from the country’s electoral calendar. The Union Sindical Obrera, representing a meaningful share of Ecopetrol’s eighty seven thousand employees and contractors, has demanded Roa’s outright resignation and threatened mobilization affecting roughly twenty five thousand workers if the board fails to act, pressure that ultimately contributed to the April removal even as Petro’s allies on the board tried to hold the line. Minority shareholders, exposed to Ecopetrol’s dual listing on the Colombian exchange and the New York Stock Exchange, wrote directly to Petro and the board warning that Roa’s continued leadership was actively devaluing the shares regardless of the presumption of innocence Petro kept invoking on his behalf.

The deeper political fight is about who gets to decide what a state oil company is for. Petro has argued explicitly that hydrocarbons are inconvenient everywhere in the world and that every barrel extracted only accelerates a well’s own exhaustion, a philosophical position most Colombian oil executives, including his own appointee, do not share. Roa has argued the opposite, that exploration is the only mechanism that gives a hydrocarbon company long term stability, and that Colombia’s fiscal dependence on hydrocarbon revenue, more than twenty percent of public revenue and more than half of exports according to independent estimates, cannot responsibly be unwound overnight regardless of the ideological commitment behind the effort. Both men are describing the same company. Neither is wrong about the numbers they are citing. They are simply optimizing for different clocks, Petro for a multi decade energy transition he may not be in office to see through, Roa for a company that has to report quarterly results to shareholders in two countries regardless of which transition timeline eventually wins.

WHAT THE TAPE IS SAYING NOW

Petro’s own defense of Roa leaned on the fact that Ecopetrol’s shares rose even as the corruption scandal peaked, crediting rising international oil prices and stable domestic production. He is not wrong about the mechanism, only about what it proves. Brent’s climb during the 2026 Iran war lifted every producer’s revenue regardless of that producer’s internal governance quality, the same tide that carried Aramco, Petrobras, and Pemex through their own respective crises earlier in this newsletter’s coverage. China exports deflation into whatever industry it decides to scale, and oil prices during a supply shock export the opposite, a rising tide that flatters management teams and corrupt ones in exactly the same proportion, for exactly as long as the shock lasts. A share price rally driven by a war seven thousand miles away says nothing about whether Ecopetrol’s own governance crisis has actually been resolved, and everything about how easily external tailwinds can be mistaken for internal vindication.

STRESS TEST

Governance risk is the whole story here, not a footnote to it. A state company with three separate criminal proceedings circling its chief executive, a board split between operational stability and reputational risk, and a workforce publicly threatening mobilization, is not a company operating with a clear hand at the wheel, regardless of how strong the underlying production numbers look on paper.

Policy whiplash risk sits directly beneath the governance risk. Colombia’s presidential election could install a government that either accelerates the exploration ban Roa has been quietly ignoring or abandons it entirely, and Ecopetrol’s own five year capital plan cannot be built with confidence until that outcome is known, a timing problem no efficiency program can engineer around.

The Permian question remains unresolved and consequential either way. Selling the American shale assets Petro wants gone would remove a genuine growth lever precisely when domestic exploration remains politically constrained. Keeping them defies the president’s own stated energy philosophy indefinitely, a contradiction the company has so far managed by simply not choosing, an option that will not remain available forever.

THE INSTITUTIONAL LABEL

Ecopetrol defies. Installed with a mandate to help shrink Colombia’s hydrocarbon dependence, run by a man who spent his tenure arguing the opposite in public, propped up through a corruption crisis by a war on the other side of the planet, and still generating more cash for the Colombian treasury than almost any policy debate in Bogota seems willing to acknowledge. The company was built to be an instrument of the president’s own energy transition. Instead it became the loudest institutional argument against it, run by the one man who owed Petro everything and used that position to say no anyway.

SOURCES

Ecopetrol fourth quarter and full year 2025 results, SEC Form 6-K filings, and PRNewswire coverage, first through fourth quarter 2025. IndexBox, Ecopetrol 2025 financial results summary, March 2026. Portafolio, El Colombiano, Infobae, RTVC Noticias, and ColombiaOne, coverage of the Ricardo Roa corruption case and board removal, February through April 2026. Bloomberg, Ecopetrol CEO charges reporting, February 9 2026. S&P Global Commodity Insights, Roa’s public break from Petro’s exploration ban, May 2023. Latin America Reports, Ecopetrol surveillance scandal and Petro’s call to sell US fracking assets, June 2025.

November 25 2025, Wilmington, Delaware. Judge Leonard Stark signs off on a five point nine billion dollar sale of PDV Holding, the American parent company that owns Citgo, to Amber Energy, an affiliate of Paul Singer’s Elliott Investment Management. Citgo is not a foreign asset PDVSA merely invested in. It is PDVSA’s own subsidiary, a hundred fifteen year old refining network with three plants in Louisiana, Texas, and Illinois refining eight hundred thousand barrels a day, the single most valuable thing Venezuela’s state oil company owns anywhere in the world. An American court just ordered it sold to satisfy debts Caracas has been defaulting on since 2017. Three weeks later, on January 3 2026, American forces captured the president of the country that owns PDVSA and flew him to New York to face trial. Read those two sentences back to back and the company at the center of this issue stops looking like an oil producer and starts looking like an estate being liquidated in installments, one American courtroom and one American military operation at a time.

THE COLLAPSE THAT MADE THIS POSSIBLE

Venezuela sits on the largest proven oil reserves on earth, more than three hundred billion barrels, and PDVSA has managed to turn that abundance into a national emergency. Production peaked near three million barrels a day in 2009. By October 2025 it had fallen to nine hundred fifty six thousand barrels a day, according to Bloomberg reporting, a collapse driven by years of sanctions, chronic underinvestment, and infrastructure that has been left to decay past the point where routine maintenance can fix it. PDVSA’s domestic refining capacity is now mostly non operational, meaning a country holding the world’s largest reserves cannot reliably refine its own crude into fuel for its own citizens. Analysts estimate restoring production to two point five million barrels a day would require fifteen to twenty billion dollars of investment sustained over a decade, capital PDVSA has had no ability to raise on its own since the 2017 default cut Venezuela off from international capital markets entirely.

Exports tell the same story in a different currency. PDVSA and its joint ventures averaged seven hundred seventy two thousand barrels a day of exports in 2024, the highest level since 2019, with China remaining the primary buyer. American imports of Venezuelan crude rose sixty four percent to two hundred twenty two thousand barrels a day the same year, and European buyers including Eni, Repsol, and Maurel et Prom nearly tripled their combined intake to seventy five thousand barrels a day. Then came the Trump administration’s late 2025 crackdown, a blockade of sanctioned tankers and a campaign against Venezuela’s so called dark fleet, the shadow shipping network the country had built to route around sanctions. Exports fell to seven hundred two thousand barrels a day in December 2025, down from nine hundred thousand in the third quarter, proof that even a company running a workaround sophisticated enough to keep barrels moving under sanctions for years can still be strangled further whenever Washington decides to tighten the specific mechanism it has been tolerating.

PDVSA’s last full published financial disclosure, for year end 2023, listed consolidated financial debt of thirty four point seven billion dollars, a figure that is itself years out of date, since the company has not published comprehensive annual figures since 2016. Widen the lens to Venezuela’s total external debt, sovereign bonds, PDVSA obligations, bilateral loans from China and Russia, and international arbitration awards, and analysts place the number between a hundred fifty and a hundred seventy billion dollars against an economy the IMF estimates at only eighty two point eight billion dollars in nominal GDP for 2025, a debt to GDP ratio between a hundred eighty and two hundred percent. This is the balance sheet Delcy Rodriguez inherited the moment she was sworn in as interim president, a company and a country so deeply underwater that even a full sanctions relief package would take a decade of disciplined investment just to rebuild the production base sanctions helped destroy in the first place.

THE LICENSE THAT TURNED ON AND OFF LIKE A SWITCH

Chevron’s relationship with PDVSA became the clearest single indicator of how tightly Washington could throttle the company without firing a shot. Chevron operated joint ventures with PDVSA across fields including Petroboscan, Petropiar, and Petroindependencia under General License 41, then 41A, a wind down authorization, before the license was terminated outright as License 41B on May 29 2025. Rodriguez, then still vice president and hydrocarbon minister, stood in front of cameras the same day and insisted PDVSA’s fields remained in full production regardless, workers maintaining the plan despite what she called unilateral coercive measures against both PDVSA and its foreign partners. The insistence mattered because it was not entirely bluster. Venezuela had been building sanctions workarounds for years by that point. But insistence is not the same as capacity, and the license termination still cut off Chevron’s ability to lift and export the crude those joint ventures produced, regardless of whether the wells kept pumping.

Then the political ground shifted entirely. Following Maduro’s capture in January 2026, Chevron’s relationship with Venezuela resumed, the company confirming by April 2026 that it had consolidated its Venezuelan heavy oil position through an asset swap, continuing to engage with both the American and Venezuelan governments toward what Chevron’s own language calls shared energy goals. Chevron chief executive Mike Wirth has been explicit that the company sees itself as part of Venezuela’s history stretching back more than a century, a framing that reads as patient corporate diplomacy right up until you remember the same license Chevron operates under today was fully revoked eight months earlier and could be revoked again the next time Washington’s calculus shifts.

CITGO, THE SUBSIDIARY SOLD TO PAY FOR SINS COMMITTED TWO DECADES AGO

The Citgo case began with Crystallex, a Canadian mining company that had gold mining assets expropriated by Hugo Chavez’s government in the 2000s. In 2017, Crystallex won an alter ego ruling in American courts, meaning the courts agreed PDVSA and the Venezuelan state were legally inseparable enough that PDVSA’s own American assets could be seized to satisfy a debt the government, not PDVSA itself, actually owed. That ruling opened the floodgates. Fifteen creditors eventually joined the case, chasing nearly nineteen billion dollars combined, ConocoPhillips owed one point three billion dollars for its own 2007 Venezuelan expropriation, Tidewater owed eighty million, O I Glass owed seven hundred million, Crystallex itself owed a billion. A Delaware court launched a formal auction of PDV Holding’s shares in 2022, and what followed was one of the strangest corporate sales in modern history, a five year, multi round bidding war conducted entirely because the actual owner, the Venezuelan state, had no legal standing left to stop it.

The auction itself became a case study in how contested value gets discovered under duress. Gold Reserve, a Bermuda based mining company backed by a consortium including Koch Minerals and JPMorgan, won an early round in mid 2025 with a seven point four billion dollar bid. That result did not hold. Amber Energy, backed by Elliott, returned with a revised offer, and on November 25 2025, Judge Stark approved Amber’s five point nine billion dollar bid, lower in headline terms than Gold Reserve’s number but structured to include a separate two point one billion dollar payment to holders of a defaulted PDVSA bond originally secured by Citgo equity, a payment the court concluded removed a bigger legal obstacle to closing than a marginally higher price would have. Evercore, advising the court, valued Citgo at roughly thirteen billion dollars during the process. Venezuela itself argued the real number exceeded eighteen billion. Both valuations describe the same three refineries. Neither valuation mattered, because the seller had no vote.

Gold Reserve’s own experience during the process adds a darker footnote most coverage of the financial mechanics leaves out. The company’s lawyer inside Venezuela, Jose Ignacio Moreno Suarez, has been detained for more than two years, with Gold Reserve describing his treatment as including intense torture and deprivation. A dispute over refinery ownership playing out in a Delaware courtroom, filed in tidy legal briefs with EBITDA multiples and priority waterfalls, sits on top of a country where the same dispute has produced an actual political prisoner.

THE POLITICS OF WHO OWNS WHAT ANYMORE

Venezuela’s bonds returned roughly ninety five percent in 2025, a rally driven entirely by speculation that political change was coming and would eventually unlock some form of debt restructuring. That speculation was validated in January when Maduro was captured, but validation is not resolution. Venezuela has not engaged with the IMF in nearly two decades and remains locked out of the fund’s financing entirely, meaning any formal restructuring needs an anchor institution the country has spent twenty years avoiding. Citigroup analysts estimate a principal haircut of at least fifty percent would be needed just to restore debt sustainability, with recovery values for existing bondholders ranging from twenty five cents on the dollar in pessimistic scenarios to the mid forties in Citi’s own base case, assuming new bonds structured with long dated coupons and oil price linked warrants.

Rodriguez’s government inherited this debt alongside the presidency itself, installed within forty eight hours of Maduro’s capture and immediately dependent on Rwandan security forces to maintain control, a government whose own recognition status with Washington remains unsettled months into its tenure. Trump has said publicly that the United States will run Venezuela’s oil sector during this transition, and Energy Secretary Chris Wright’s February visit to Caracas, the first cabinet level American energy visit to the country in nearly three decades, confirmed that proceeds from Venezuelan oil sales flow first through accounts Washington itself controls before any money reaches Caracas. PDVSA, in other words, no longer fully controls its own company’s cash. It controls the wells. Washington controls the money the wells generate, at least until a government Washington formally recognizes stands up, a bar Rodriguez’s administration has not yet cleared.

WHAT THE TAPE IS SAYING NOW

China exports deflation into whatever industry it decides to scale, and China has been Venezuela’s single largest crude buyer throughout the sanctions years specifically because Chinese refiners could absorb heavy, discounted Venezuelan crude that sanctions kept out of reach for buyers less willing to navigate the compliance risk. That relationship gives Beijing quiet leverage over how any post Maduro settlement gets structured, since China holds a meaningful share of Venezuela’s bilateral debt alongside Russia and has spent years accepting oil as a de facto repayment mechanism the way no Western institution has been willing to. Whatever restructuring Washington eventually blesses will need to account for a creditor it does not control, sitting on the other side of a country it currently does control the cash flow of.

STRESS TEST

Citgo’s sale remains subject to OFAC approval and pending appeals from both the Venezuelan government and Gold Reserve, meaning the single largest asset recovery in this entire saga could still be delayed or reopened even after a Delaware judge has already signed the order.

Production recovery is a decade long capital project disguised as a political event. Sanctions relief alone does not rebuild refining infrastructure that has been left to decay for years, and the fifteen to twenty billion dollar investment analysts say is needed will not arrive until investors trust that today’s license regime survives the next change in Washington’s political weather.

Recognition risk sits underneath everything else. A government whose own diplomatic status remains unsettled cannot credibly negotiate a debt restructuring, sign new long term joint ventures, or guarantee any investor that today’s terms survive a change in administration on either side of the relationship.

THE INSTITUTIONAL LABEL

PDVSA collateralizes. A company that spent two decades pledging its own most valuable subsidiary against debt it could not otherwise service, until pledging turned into losing, in a courtroom four thousand miles from the fields that actually produce the oil. Citgo was supposed to be Venezuela’s insurance policy against exactly this outcome, a stable, cash generating American asset shielded from the volatility of the home country’s politics. Instead it became the collateral, then the collateral got called, and PDVSA is left holding the wells while an American hedge fund’s affiliate holds the refineries that used to turn those wells into cash Caracas could actually spend.

SOURCES

Bloomberg via AInvest, Venezuela oil production and export decline, December 2025. MatrixBCG, PDVSA financial and production data, 2023 through 2025 projections. Reuters via CNBC, Modern Diplomacy, IDNFinancials, and Nation Thailand, Venezuela sovereign and PDVSA debt analysis, January 2026. Energy Analytics Institute, Delcy Rodriguez statement on Chevron license termination, May 29 2025. OFAC, General License 41A text. Chevron Form 8-K first quarter 2026 results and April 2026 Venezuela asset swap announcement. OK Energy Today, PGJ Online, Bloomberg, Fortune, RBN Energy, and Venezuelanalysis, Citgo and PDV Holding auction coverage, July 2025 through January 2026.

November 25 2025, Wilmington, Delaware. Judge Leonard Stark signs off on a five point nine billion dollar sale of PDV Holding, the American parent company that owns Citgo, to Amber Energy, an affiliate of Paul Singer’s Elliott Investment Management. Citgo is not a foreign asset PDVSA merely invested in. It is PDVSA’s own subsidiary, a hundred fifteen year old refining network with three plants in Louisiana, Texas, and Illinois refining eight hundred thousand barrels a day, the single most valuable thing Venezuela’s state oil company owns anywhere in the world. An American court just ordered it sold to satisfy debts Caracas has been defaulting on since 2017. Three weeks later, on January 3 2026, American forces captured the president of the country that owns PDVSA and flew him to New York to face trial. Read those two sentences back to back and the company at the center of this issue stops looking like an oil producer and starts looking like an estate being liquidated in installments, one American courtroom and one American military operation at a time.

THE COLLAPSE THAT MADE THIS POSSIBLE

Venezuela sits on the largest proven oil reserves on earth, more than three hundred billion barrels, and PDVSA has managed to turn that abundance into a national emergency. Production peaked near three million barrels a day in 2009. By October 2025 it had fallen to nine hundred fifty six thousand barrels a day, according to Bloomberg reporting, a collapse driven by years of sanctions, chronic underinvestment, and infrastructure that has been left to decay past the point where routine maintenance can fix it. PDVSA’s domestic refining capacity is now mostly non operational, meaning a country holding the world’s largest reserves cannot reliably refine its own crude into fuel for its own citizens. Analysts estimate restoring production to two point five million barrels a day would require fifteen to twenty billion dollars of investment sustained over a decade, capital PDVSA has had no ability to raise on its own since the 2017 default cut Venezuela off from international capital markets entirely.

Exports tell the same story in a different currency. PDVSA and its joint ventures averaged seven hundred seventy two thousand barrels a day of exports in 2024, the highest level since 2019, with China remaining the primary buyer. American imports of Venezuelan crude rose sixty four percent to two hundred twenty two thousand barrels a day the same year, and European buyers including Eni, Repsol, and Maurel et Prom nearly tripled their combined intake to seventy five thousand barrels a day. Then came the Trump administration’s late 2025 crackdown, a blockade of sanctioned tankers and a campaign against Venezuela’s so called dark fleet, the shadow shipping network the country had built to route around sanctions. Exports fell to seven hundred two thousand barrels a day in December 2025, down from nine hundred thousand in the third quarter, proof that even a company running a workaround sophisticated enough to keep barrels moving under sanctions for years can still be strangled further whenever Washington decides to tighten the specific mechanism it has been tolerating.

PDVSA’s last full published financial disclosure, for year end 2023, listed consolidated financial debt of thirty four point seven billion dollars, a figure that is itself years out of date, since the company has not published comprehensive annual figures since 2016. Widen the lens to Venezuela’s total external debt, sovereign bonds, PDVSA obligations, bilateral loans from China and Russia, and international arbitration awards, and analysts place the number between a hundred fifty and a hundred seventy billion dollars against an economy the IMF estimates at only eighty two point eight billion dollars in nominal GDP for 2025, a debt to GDP ratio between a hundred eighty and two hundred percent. This is the balance sheet Delcy Rodriguez inherited the moment she was sworn in as interim president, a company and a country so deeply underwater that even a full sanctions relief package would take a decade of disciplined investment just to rebuild the production base sanctions helped destroy in the first place.

THE LICENSE THAT TURNED ON AND OFF LIKE A SWITCH

Chevron’s relationship with PDVSA became the clearest single indicator of how tightly Washington could throttle the company without firing a shot. Chevron operated joint ventures with PDVSA across fields including Petroboscan, Petropiar, and Petroindependencia under General License 41, then 41A, a wind down authorization, before the license was terminated outright as License 41B on May 29 2025. Rodriguez, then still vice president and hydrocarbon minister, stood in front of cameras the same day and insisted PDVSA’s fields remained in full production regardless, workers maintaining the plan despite what she called unilateral coercive measures against both PDVSA and its foreign partners. The insistence mattered because it was not entirely bluster. Venezuela had been building sanctions workarounds for years by that point. But insistence is not the same as capacity, and the license termination still cut off Chevron’s ability to lift and export the crude those joint ventures produced, regardless of whether the wells kept pumping.

Then the political ground shifted entirely. Following Maduro’s capture in January 2026, Chevron’s relationship with Venezuela resumed, the company confirming by April 2026 that it had consolidated its Venezuelan heavy oil position through an asset swap, continuing to engage with both the American and Venezuelan governments toward what Chevron’s own language calls shared energy goals. Chevron chief executive Mike Wirth has been explicit that the company sees itself as part of Venezuela’s history stretching back more than a century, a framing that reads as patient corporate diplomacy right up until you remember the same license Chevron operates under today was fully revoked eight months earlier and could be revoked again the next time Washington’s calculus shifts.

CITGO, THE SUBSIDIARY SOLD TO PAY FOR SINS COMMITTED TWO DECADES AGO

The Citgo case began with Crystallex, a Canadian mining company that had gold mining assets expropriated by Hugo Chavez’s government in the 2000s. In 2017, Crystallex won an alter ego ruling in American courts, meaning the courts agreed PDVSA and the Venezuelan state were legally inseparable enough that PDVSA’s own American assets could be seized to satisfy a debt the government, not PDVSA itself, actually owed. That ruling opened the floodgates. Fifteen creditors eventually joined the case, chasing nearly nineteen billion dollars combined, ConocoPhillips owed one point three billion dollars for its own 2007 Venezuelan expropriation, Tidewater owed eighty million, O I Glass owed seven hundred million, Crystallex itself owed a billion. A Delaware court launched a formal auction of PDV Holding’s shares in 2022, and what followed was one of the strangest corporate sales in modern history, a five year, multi round bidding war conducted entirely because the actual owner, the Venezuelan state, had no legal standing left to stop it.

The auction itself became a case study in how contested value gets discovered under duress. Gold Reserve, a Bermuda based mining company backed by a consortium including Koch Minerals and JPMorgan, won an early round in mid 2025 with a seven point four billion dollar bid. That result did not hold. Amber Energy, backed by Elliott, returned with a revised offer, and on November 25 2025, Judge Stark approved Amber’s five point nine billion dollar bid, lower in headline terms than Gold Reserve’s number but structured to include a separate two point one billion dollar payment to holders of a defaulted PDVSA bond originally secured by Citgo equity, a payment the court concluded removed a bigger legal obstacle to closing than a marginally higher price would have. Evercore, advising the court, valued Citgo at roughly thirteen billion dollars during the process. Venezuela itself argued the real number exceeded eighteen billion. Both valuations describe the same three refineries. Neither valuation mattered, because the seller had no vote.

Gold Reserve’s own experience during the process adds a darker footnote most coverage of the financial mechanics leaves out. The company’s lawyer inside Venezuela, Jose Ignacio Moreno Suarez, has been detained for more than two years, with Gold Reserve describing his treatment as including intense torture and deprivation. A dispute over refinery ownership playing out in a Delaware courtroom, filed in tidy legal briefs with EBITDA multiples and priority waterfalls, sits on top of a country where the same dispute has produced an actual political prisoner.

THE POLITICS OF WHO OWNS WHAT ANYMORE

Venezuela’s bonds returned roughly ninety five percent in 2025, a rally driven entirely by speculation that political change was coming and would eventually unlock some form of debt restructuring. That speculation was validated in January when Maduro was captured, but validation is not resolution. Venezuela has not engaged with the IMF in nearly two decades and remains locked out of the fund’s financing entirely, meaning any formal restructuring needs an anchor institution the country has spent twenty years avoiding. Citigroup analysts estimate a principal haircut of at least fifty percent would be needed just to restore debt sustainability, with recovery values for existing bondholders ranging from twenty five cents on the dollar in pessimistic scenarios to the mid forties in Citi’s own base case, assuming new bonds structured with long dated coupons and oil price linked warrants.

Rodriguez’s government inherited this debt alongside the presidency itself, installed within forty eight hours of Maduro’s capture and immediately dependent on Rwandan security forces to maintain control, a government whose own recognition status with Washington remains unsettled months into its tenure. Trump has said publicly that the United States will run Venezuela’s oil sector during this transition, and Energy Secretary Chris Wright’s February visit to Caracas, the first cabinet level American energy visit to the country in nearly three decades, confirmed that proceeds from Venezuelan oil sales flow first through accounts Washington itself controls before any money reaches Caracas. PDVSA, in other words, no longer fully controls its own company’s cash. It controls the wells. Washington controls the money the wells generate, at least until a government Washington formally recognizes stands up, a bar Rodriguez’s administration has not yet cleared.

WHAT THE TAPE IS SAYING NOW

China exports deflation into whatever industry it decides to scale, and China has been Venezuela’s single largest crude buyer throughout the sanctions years specifically because Chinese refiners could absorb heavy, discounted Venezuelan crude that sanctions kept out of reach for buyers less willing to navigate the compliance risk. That relationship gives Beijing quiet leverage over how any post Maduro settlement gets structured, since China holds a meaningful share of Venezuela’s bilateral debt alongside Russia and has spent years accepting oil as a de facto repayment mechanism the way no Western institution has been willing to. Whatever restructuring Washington eventually blesses will need to account for a creditor it does not control, sitting on the other side of a country it currently does control the cash flow of.

STRESS TEST

Citgo’s sale remains subject to OFAC approval and pending appeals from both the Venezuelan government and Gold Reserve, meaning the single largest asset recovery in this entire saga could still be delayed or reopened even after a Delaware judge has already signed the order.

Production recovery is a decade long capital project disguised as a political event. Sanctions relief alone does not rebuild refining infrastructure that has been left to decay for years, and the fifteen to twenty billion dollar investment analysts say is needed will not arrive until investors trust that today’s license regime survives the next change in Washington’s political weather.

Recognition risk sits underneath everything else. A government whose own diplomatic status remains unsettled cannot credibly negotiate a debt restructuring, sign new long term joint ventures, or guarantee any investor that today’s terms survive a change in administration on either side of the relationship.

THE INSTITUTIONAL LABEL

PDVSA collateralizes. A company that spent two decades pledging its own most valuable subsidiary against debt it could not otherwise service, until pledging turned into losing, in a courtroom four thousand miles from the fields that actually produce the oil. Citgo was supposed to be Venezuela’s insurance policy against exactly this outcome, a stable, cash generating American asset shielded from the volatility of the home country’s politics. Instead it became the collateral, then the collateral got called, and PDVSA is left holding the wells while an American hedge fund’s affiliate holds the refineries that used to turn those wells into cash Caracas could actually spend.

SOURCES

Bloomberg via AInvest, Venezuela oil production and export decline, December 2025. MatrixBCG, PDVSA financial and production data, 2023 through 2025 projections. Reuters via CNBC, Modern Diplomacy, IDNFinancials, and Nation Thailand, Venezuela sovereign and PDVSA debt analysis, January 2026. Energy Analytics Institute, Delcy Rodriguez statement on Chevron license termination, May 29 2025. OFAC, General License 41A text. Chevron Form 8-K first quarter 2026 results and April 2026 Venezuela asset swap announcement. OK Energy Today, PGJ Online, Bloomberg, Fortune, RBN Energy, and Venezuelanalysis, Citgo and PDV Holding auction coverage, July 2025 through January 2026.