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In March 2026, ADES Holding suspended offshore rig operations for a portion of its

thirty three Gulf based units, a direct precaution against the regional conflict spreading across the Middle East, the same Iran war this project has already traced back to a February 28, 2026 start date in the Issue 66 political timeline piece. Two months later, the company reiterated full year EBITDA guidance of four point five to four point eight seven billion Saudi riyals, thirty three to forty four percent growth over 2025. A company that just took some of its own rigs offline for safety reasons raised no red flags about hitting a growth target most drilling contractors would consider aggressive in peacetime. The reason is not resilience in the abstract. It is a fleet that, eighteen months ago, did not exist in its current form.

ADES was a private, PIF backed regional driller as recently as 2021, when Saudi Arabia’s Public Investment Fund teamed up with Zamil Group Investment and ADES Investments to take the then London listed company private in a deal valuing it at roughly five hundred sixteen million dollars. Two years later, in September 2023, the same PIF backed vehicle brought ADES public again on the Saudi exchange, an initial public offering priced at the top of its range, thirteen point five riyals a share, valuing the company at fifteen point two billion riyals, four point zero six billion dollars, drawing institutional orders of seventy six point five billion dollars for a one point two billion dollar offering, sixty three times oversubscribed. The stock closed its first day up thirty percent, the maximum move Saudi exchange rules allow. A company the state valued at five hundred sixteen million dollars in 2021 was worth eight times that within twenty four months, without changing its underlying strategy at all, buy oil field service capacity across the Middle East and North Africa faster than competitors can defend their own share of it.

The strategy did not stop at the IPO. In August 2025, ADES agreed to acquire Shelf Drilling, a much larger international rig owner, in an all cash merger, revising its offer upward twenty eight percent to eighteen point five Norwegian kroner a share after pushback from Shelf Drilling’s own management, and closing the deal in November 2025. The combined company operates more than eighty offshore jackups, over forty five of them premium units, forty onshore rigs, across nineteen countries, up from thirteen before the merger, backed by a combined backlog exceeding nine billion dollars. ADES’s own guidance for fifty to sixty million dollars in annual cost synergies, plus more than thirty million dollars a year in day one interest savings from refinancing Shelf Drilling’s more expensive debt, is the arithmetic behind why a fleet that suddenly spans West Africa, the North Sea, and Southeast Asia can absorb a regional conflict in its home market without losing its growth guidance. A rig idled in the Gulf is a problem for a purely Gulf focused driller. It is a rounding error for a company that just added Nigeria, the Dutch sector of the North Sea, and Chevron’s Nigerian operations to its client list in the same eighteen months.

Understand what ADES actually operates, because the fleet is not just interchangeable jackup rigs. A meaningful share of the combined fleet are Mobile Offshore Production Units, MOPUs, platforms that do not drill at all but instead process oil and gas at the surface after a well is already flowing, functioning as a floating production facility a client leases rather than owns outright, distinct from the drilling and workover rigs that make up the rest of the business. Onshore, ADES runs both drilling rigs, which bore new wells, and workover rigs, smaller units that re enter existing wells to repair or stimulate them rather than drill new holes, a lower day rate but steadier revenue business that cushions the swings in offshore drilling demand. This dual exposure, drilling revenue that moves with exploration budgets and production or workover revenue that moves with keeping existing wells flowing, is the specific reason ADES’s own management can describe the company as naturally diversified even before counting the new geography Shelf Drilling brought in.

Here is the stress test. Ninety five percent of ADES’s original backlog, before the Shelf Drilling deal, traced back to three clients, Aramco, Kuwait Oil Company, and Qatar’s North Oil Company, all of them Gulf state entities exposed to the same regional conflict that just forced the March 2026 rig suspensions. The Shelf Drilling acquisition dilutes that concentration on paper, nineteen countries instead of thirteen, but the company’s own first quarter 2026 disclosure was explicit that the current regional environment and related temporary suspensions are expected to weigh more heavily on the second quarter than the first, since the first quarter only absorbed a handful of disrupted days. Revenue grew twenty four percent to seven point six billion riyals in the trailing period reported, and EBIT margins held stable, real evidence the integration is working operationally. But a company still drawing the bulk of its legacy backlog from three state buyers in the exact region a war just opened in has not yet proven its diversification will hold up through a full quarter of that war, only through a few days of it.

Label for this one: ADES multiplies. Not organically. Through a state backed vehicle that took a five hundred sixteen million dollar private company and turned it into a four billion dollar public one in two years, then used the public currency to buy a rig fleet nearly as large as its own, betting that scale purchased quickly is worth more than scale grown slowly, in a region where the case for moving quickly keeps getting made for it by events outside the company’s control.

Sources: ADES Holding Company first quarter 2026 earnings release, Offshore Energy and IndexBox reporting on ADES Nigeria and North Sea contract awards April through July 2026, Oil and Gas Middle East reporting on ADES Gulf rig suspensions March 2026, Offshore Technology and OE Digital reporting on the ADES and Shelf Drilling merger August through November 2025, Bloomberg and Gulf News reporting on the ADES Holding initial public offering September and October 2023.

Borr Drilling exists because Tor Olav Trøim looked at the jackup market during the 2016

downturn and saw yards and distressed owners sitting on modern rigs nobody could afford to keep. He founded the company in December 2016, raised roughly a hundred fifty five million dollars in an initial private placement, and within a year had bought fifteen jackup rigs off Transocean and Paragon Offshore for close to one point three five billion dollars, assembling one of the youngest fleets in the industry without paying for a single day of new construction. Ten years later, in January 2026, Borr did the same trade again, buying five premium jackup rigs from Noble Corporation for three hundred sixty million dollars, roughly seventy two million dollars a rig, against a modern newbuild cost this project has already documented at two hundred fifty to three hundred million dollars each. The company’s entire identity is one trade, repeated on a cycle, buy someone else’s rig for a fraction of what a shipyard would charge to build it fresh.

Understand the asset before the numbers, because a jackup rig is not interchangeable equipment the way a barrel of oil is. A jackup stands on three or four legs that lower to the seabed, jacking the hull clear of wave action, which is why the rig class only works in water shallow enough for the legs to reach bottom, typically up to three hundred fifty or four hundred feet. Age and specification inside that category matter enormously. A premium jackup built in the last decade carries a longer cantilever reach over an existing platform, a deeper variable deck load capacity, and harsh environment certification that an older unit from the 1990s or 2000s simply does not have, which is why premium rigs command day rates that can run two or three times what an older, lower specification unit earns even in the same basin. Buying operating premium rigs directly from Noble Corporation, already crewed, already contracted, already earning revenue, is a fundamentally different trade than the stranded newbuild purchase this project covered in the jackup construction economics issue, where Borr picked up an unfinished hull, Hull B378, for a hundred twenty two million dollars against an original order price near two hundred forty million. A stranded newbuild still needs completion capital and still carries delivery risk. An operating premium rig bought from a competitor starts earning the day it changes hands. Borr’s January 2026 purchase was the safer version of the same underlying arbitrage.

The company did not stop there. It also entered a fifty fifty joint venture to acquire five more premium jackups for two hundred eighty seven million dollars, taking the fleet from twenty nine rigs to thirty four in a single year, and it refinanced its entire high yield debt stack to fund the buying spree, tendering for its ten percent notes due 2028 and ten point three seven five percent notes due 2030, and pricing two point zero three five billion dollars of new senior secured notes, eight point seven five percent due 2032 and nine percent due 2034. Ninety three point eight four percent of noteholders tendered into the exchange, the deal closed June 10, 2026. Borr is still borrowing at close to nine percent. It is simply borrowing at slightly less than the ten percent and ten point three seven five percent coupons it carried before, and using the fresh capital to keep buying rigs at a discount to replacement cost rather than to shrink the balance sheet.

Here is the stress test, and the first quarter of 2026 already shows where the strain lands. Revenue of two hundred forty seven million dollars, down five percent from the fourth quarter. Adjusted EBITDA of eighty eight point five million dollars, down sixteen percent. A net loss of twenty nine million dollars, against a net loss of only one million dollars the prior quarter, driven by a late contract start on the Odin rig, which needed additional maintenance before beginning its Cantium contract, and an eight point four million dollar credit loss provision against a customer who is not paying on time. Technical utilization still ran at ninety nine point four percent and economic utilization at ninety seven percent, meaning the fleet itself is working almost every day it is available to work. The loss is not an operating problem. It is a timing and credit problem sitting on top of a balance sheet that just added roughly two billion dollars of fresh debt to fund a fleet expansion, with full year 2026 contract coverage at only seventy percent and second half coverage weaker than first half, sixty two percent against seventy eight percent, at an average day rate near a hundred thirty four thousand dollars. A company borrowing at nine percent needs day rates and coverage to hold. Sixty two percent second half coverage is not holding, it is exposure.

Trøim built this company once already on the theory that buying cheap during someone else’s distress beats building expensive during your own optimism, survived a 2020 restructuring when the same theory left Borr owing Keppel and PPL Shipyard in Singapore more than it could pay after the COVID oil crash, and is now running the identical playbook a decade later with better assets and a still expensive balance sheet. The rigs are premium. The utilization is real. The debt is still priced like a company the market does not fully trust to hold its coverage through the cycle it just bet on.

Label for this one: Borr Drilling arbitrages. Not oil. Not gas. The gap between what a shipyard charges to build a rig and what a distressed or consolidating owner will sell one for, a gap Trøim has now traded twice, a decade apart, with the same balance sheet risk both times.

Sources: Borr Drilling Limited first quarter 2026 results announcement, Borr Drilling Limited operational and contracting updates April 2026, Borr Drilling Limited notes tender and new senior secured notes offering announcements May and June 2026, Borr Drilling Limited second quarter 2026 earnings call invitation, company history summaries from Borr Drilling’s own investor relations site, Baird Maritime Offshore Accounts coverage of Borr’s 2020 and 2021 restructuring.

Subsea7 spent the last two months of its independent life the way it spent the previous

twenty five years, winning contracts on four continents. Angola in April, a subsea tie back for ExxonMobil’s Redevelopment 2.0 project run out of Paris, Luanda, Lisbon and Sutton offices simultaneously. Norway in May, a pipeline tie in for Vår Energi’s Goliat Gas Export Project run out of Stavanger. The US Gulf in June, a flowline for Murphy Exploration run out of Houston. Germany the same week, monopile installation for an offshore wind farm run through Seaway7, its renewables arm. This is a company at the absolute top of its operational game, and on July 22, 2026, tomorrow, the European Commission is expected to open a full scale Phase II antitrust investigation into whether that company should be allowed to keep existing at all.

The deal under investigation is the merger with Saipem, first proposed in February 2025, terms finalized that July, and structured as a true merger of equals on paper. Subsea7 shareholders will receive six point six eight eight Saipem shares for every share they hold, plus an extraordinary dividend of four hundred fifty million euros, plus a further hundred five million euros tied to an ongoing divestment, before the deal closes. Each side ends up owning half of the combined company. But the combined company will be called Saipem7, not Subsea7Saipem or any name that survives Subsea7’s own brand at all. It will be incorporated in Italy. It will be headquartered in Milan. Eni and CDP Equity, Saipem’s reference shareholders and both tied directly to the Italian state, CDP Equity being the investment arm of Italy’s own treasury, signed a shareholders agreement committing their votes in favor before the ink on the merger terms was even dry. Siem Industries, Subsea7’s largest shareholder and the vehicle of Kristian Siem, the man who has chaired this company and its predecessors since 2002, signed the same commitment. A Norwegian shipping family that built an offshore contractor out of a 1954 predecessor company is handing the keys, the name, and the domicile to Rome, even though the numbers say Subsea7 is currently the better business.

Understand what Subsea7 actually builds before the merger numbers make sense, because EPCI is not a marketing term, it is the whole job in four letters. Engineering, procurement, construction, installation, meaning the same company that designs the flowline also buys the steel, fabricates it, and puts it on the seabed, rather than handing each stage to a different contractor. The Murphy contract in the Gulf runs to water depths of eighteen hundred fifty metres, deep enough that a diver cannot be sent down at all, everything has to be handled by remotely operated vehicles working off a specialised construction vessel, while the Vår Energi pipeline in the Barents Sea, twelve point seven kilometres of ten inch uninsulated carbon steel line, sits in far shallower water where diving support is still viable and the engineering problem shifts from pressure and umbilical control to cold weather material selection. Pipelay itself comes in three methods and the choice is not cosmetic. S-lay, the pipe leaving the vessel in a shallow curve, works in moderate depths and is the cheapest per kilometre. J-lay, the pipe leaving near vertical off a tower on the vessel, handles the deepwater tension loads S-lay cannot. Reel-lay, the entire pipeline spooled onto a giant reel onshore and unspooled at sea, is fastest for smaller diameter lines like the flowline tie backs that make up most of Subsea7’s recent contract wins. A company that can deploy all three methods out of the same fleet, rather than chartering in specialist tonnage project by project, is the actual competitive moat behind the word SURF, subsea umbilicals, risers and flowlines, that shows up in every one of Subsea7’s own press releases. That fleet, and the engineering judgment to deploy it correctly, is the asset Saipem is paying for. It does not show up as a line item anywhere in the merger terms.

Those numbers, reported in the first quarter of 2026 as a standalone company for what may be one of its last times, are worth sitting with. Revenue of one point eight billion dollars, up seventeen percent year on year. Adjusted EBITDA of three hundred eighty five million dollars, up sixty three percent, pushing the margin from fifteen percent to twenty one percent in a single year, with the Subsea and Conventional segment running a twenty four percent margin and Renewables at twelve percent. Net income of ninety seven million dollars against sixteen million dollars a year earlier, a sixfold increase. Backlog of thirteen point five billion dollars, five and a half billion of it already scheduled for execution this year, and five billion scheduled for 2027, up seventeen percent since the start of the year. Net cash, including lease liabilities, of a hundred ninety eight million dollars, up from twenty one million dollars at the end of 2025. Full year guidance was raised to revenue between seven point four and seven point eight billion dollars at roughly a twenty three percent EBITDA margin. This is not a company that needed rescuing into a merger. This is a company whose stock returned a hundred twenty percent over the prior year, and it is still the junior partner in naming rights.

Here is the stress test, and it runs on two tracks that have nothing to do with either company’s operating performance. Brazil cleared the merger unconditionally. Australian competition authorities have already opened an in depth review, and the European Commission is set to follow tomorrow with a full scale Phase II investigation, both worried the combined entity, a diversified fleet of more than sixty construction vessels, projects in over sixty countries, a combined backlog of forty three billion euros, concentrates too much of the world’s subsea installation capacity in one company. No divestiture remedies have been offered yet. If either regulator forces asset sales or delays completion past the second half of 2026 target, the four hundred million euros in annual synergies both companies are counting on by year three slips further out, and Subsea7’s own shareholders, who approved a deal built around Saipem’s name and Saipem’s domicile in exchange for slightly more than half the economics, are left holding a longer runway to a payoff that was already built on ceding almost everything except the number on the balance sheet.

There is a version of this story where regulators are simply doing their job, checking that one company does not end up controlling too much of a market that only has a handful of credible players left in it after a decade of consolidation, Transocean and Valaris, McDermott circling its own third refinancing, Halliburton automating its own labor model away. There is another version where the real story already happened in February 2025, when two boards decided the winner of a merger of equals would be determined not by which company reported better margins but by which shareholders had a state investment vehicle willing to fight for the name plate. Subsea7 built the better quarter. Italy is getting the headquarters.

Label for this one: Subsea7 vanishes. Not the vessels, not the backlog, not the thirty four countries of operations that made this company worth merging with in the first place. The name. The one thing a fifty fifty merger of equals was never actually going to split evenly.

Sources: Subsea 7 S.A. first quarter 2026 results announcement, Subsea7 company news releases April through June 2026, Saipem and Subsea7 merger agreement announcement and investor presentation July 2025, Offshore Magazine reporting on EU and Australian regulatory review July 2026, Subsea7 company history archive, Investing.com earnings call summary May 2026.

Once more today’s topic is our beloved ONGC. We will come to it soon but first some

background. On June 8, 2026 the Reserve Bank of India quietly reopened a window it had not touched since September 2013. I caught the mechanics of this on Squawk Box before the ink on the RBI circular was even dry, a two minute segment buried between an earnings call and a Fed preview. The rupee had just touched close to ninety seven to the dollar in May, the RBI had already burned through sixty billion dollars of reserves defending it, and Brent had spent April averaging around a hundred fourteen dollars a barrel after a Persian Gulf war more than doubled India’s oil import bill from January’s sixty two to sixty four dollar range. Mint Street reached for the same tool it used in 2013 because the same disease had come back.

That reopening is one data point in a longer story. India has now run three different plays to defend its dollar position over the last decade, and only looking at all three side by side tells you which one is actually sound.

FCNR: a bet the RBI can walk away from

The mechanics are simple. Banks bring in fresh FCNR dollar deposits, sell the dollars to the RBI at today’s rate, and buy them back at the same rate when the deposit matures. The RBI carries the currency risk for a fixed window, banks pass depositors better rates without eating a hedging cost, and when the window closes the exposure closes with it. That is what happened in 2013, twenty six billion dollars in three months. As of mid July 2026 the reopened window has pulled in roughly nine billion dollars against analyst forecasts of thirty to fifty five billion, with the facility open until September 30.

Samir Arora of Helios Capital has made the case that this trade pays for itself, if India can pull in forty to fifty billion dollars the inflow alone strengthens the rupee enough that the savings on the oil import bill outweigh whatever subsidy the RBI is eating on the hedge. It is a bet that becomes true by being believed, get enough dollars in and the currency effect does the rest of the work. Ananth Narayan has pushed back on exactly this point, calling it a version of economic whack a mole, the dollars are borrowed rather than earned and every one of them walks back out in three to five years. Both are right about different things. The trade is self reinforcing if it hits scale, and it still leaves India facing the same current account gap the day the window closes. But note what it is not. It is not a promise the government has to redeem in an asset whose price it does not control. The clock runs out and the RBI’s exposure runs out with it.

SGB: the government took a naked position and called it a savings scheme

Now put the Sovereign Gold Bond scheme next to that. Launched in November 2015, the pitch was the same instinct as FCNR, get Indians to hold a paper claim on gold’s price instead of shipping physical gold across a border, and the dollar outflow shrinks. Over sixty seven tranches through February 2023, the scheme raised seventy two thousand two hundred seventy four crore, about seven hundred sixty one million dollars.

Here is the part that never got said plainly enough at the time. Every SGB the government sold was the government selling itself short on gold, and it never bought a hedge against its own position. That is not a savings scheme, that is a trader running a naked short with no stop loss, except the trader is a sovereign and the position sits open for eight years. Gold went from roughly twenty six thousand three hundred rupees per ten grams at launch to over one lakh rupees per ten grams by 2025. The outstanding liability on the government’s book ballooned to roughly one lakh twelve thousand crore, about one point one eight billion dollars, against a hundred thirty two tonnes of gold it now owed back in bond form. The government tried one more lever in the July 2024 budget, cutting the customs duty on gold from fifteen percent to six percent, which cracked the domestic gold price by close to eight percent within days and briefly made SGBs look even less attractive next to cheaper physical metal. It did not save the scheme, and it did not even achieve the original goal, gold imports jumped over a hundred percent year on year by that August and more than tripled by November, because a duty cut makes gold cheaper to buy, not less desirable. The government killed new SGB issuance after February 2024 and formally closed the scheme in the 2025 budget. The Economic Affairs Secretary said outright that it had become an expensive way to borrow money.

The comparison that matters is not FCNR versus SGB as instruments. It is who held the open position and for how long. FCNR leaves the risk with the RBI for a bounded window it chooses. SGB left the risk with the exchequer for eight years against a price it could not hedge or control. One is a trade with a stop loss. The other was a trade without one, dressed up as thrift.

What OVL and ONGC should take from this, in the right order

A cash acquisition abroad is India spending down the same finite pool of dollars both schemes above were built to defend. A share swap, once ONGC’s stock is a credible instrument, spends none of it. But the sequence matters more than the idea, and getting the sequence backward would repeat the SGB mistake in a different currency.

Merge OVL into ONGC first. Right now a global investor pricing ONGC has to look past a domestic production number and hunt several pages into the annual report for a wholly owned overseas subsidiary to understand what the company actually is. One balance sheet, one reserve number, ends that.

Rerate second, and rerate on the right number. The pitch to the market has to be ONGC as a global E&P company, and that means putting its upstream production and reserves next to a peer that made the same journey from national oil company to international operator, a company like Equinor, which built its international book the same way OVL is trying to. That comparison only works if it is upstream to upstream. ONGC’s consolidated group revenue includes downstream and refining subsidiaries with their own separate business entirely, and blending that number against a pure E&P peer’s revenue is the kind of comparison that falls apart the moment an analyst asks a second question. Isolate the E&P number, compare it to the E&P peer, let that comparison do the rerating.

List the ADR third, once the rerated multiple exists to lock in and extend to a global investor base. And only then does the swap become live. A rerated stock is real currency. A stock still carrying the old PSU discount is not, and swapping it away for an asset means giving up more ownership than the asset is worth, which is not saving foreign exchange, it is destroying shareholder value to look like you saved foreign exchange. That is the one place a badly sequenced version of this idea turns into SGB with extra steps, a bet nobody hedged, just wearing an equity wrapper instead of a gold one.

What the swap could actually buy

ONGC is so glad that BP as TSP arrested production decline in western offshore. They also do JVs abroad through OVL route where there are proven reserves. These JVs are done in cash using reserve currency. Now take a hypothetical scenario the way any credible pitch to Strategy needs one, labelled as illustrative, not a live deal. A billion barrels of proven reserves in a Permian style basin, offered at a sub forty dollar per barrel all in cost, paid for entirely in ONGC shares once the stock trades at a real multiple. If the average realised price across the field’s development life runs around sixty five dollars a barrel over a ten year recovery window, the margin per barrel is roughly twenty five dollars, and against a billion barrels that is on the order of twenty five billion dollars of gross margin over the life of the asset, funded without a single dollar leaving India’s reserves. The precision of that number matters less than the shape of it. It is the kind of return only available to a buyer with cheap, credible equity currency in hand at the exact moment sellers are distressed enough to price a billion barrels that low, which is a moment cash buyers usually cannot afford and share swap buyers can.

Stress test

None of this survives a stock that has not actually rerated. It also runs into a ministry that owns close to fifty nine percent of ONGC and has to sign off on the disclosure load a real ADR listing requires, the same disclosure load that quietly killed the 2019 OVL listing proposal. And some sellers, particularly state counterparties in the Gulf or Africa, will simply prefer cash regardless of what paper is on offer. The idea has a narrower door than FCNR ever did. It has no door at all if the sequence gets run out of order.

The inversion

FCNR works because the RBI’s exposure has an expiry date it chose. SGB failed because the government’s exposure had no expiry date and no hedge, an open position nobody marked to market until gold had already quadrupled against it. A share swap, sequenced correctly, is neither. Nobody has to redeem anything, and nothing is naked, because the price was set once, on the day of the deal, by a market that had already done the rerating first. The forex tool that finally works is the one where India stops taking positions it cannot close.

Business model label: ONGC dilutes.

Reporting on the June 2026 FCNR(B) swap window and the 2013 precedent from The Daily Brief by Zerodha, Business Standard, and the Kotak Mahindra Bank NRI advisory, including figures on reserve drawdown, oil price spike, and mobilisation totals as of mid July 2026. Samir Arora’s self funding argument and Ananth Narayan’s whack a mole counterpoint as reported in The Daily Brief by Zerodha, July 17, 2026. Sovereign Gold Bond scheme history, outstanding liability, and 2025 discontinuation from GKToday, GoldenPi, and Moatinvesting. July 2024 Union Budget customs duty cut on gold and its price and import volume impact from Business Standard and A2Z Taxcorp.

#CrudeTruth #ONGC #ForeignExchange #RBI #OilAndGas #EnergyFinance #IndianEconomy #CapitalAllocation #UpstreamOil #SovereignGoldBond #FCNR #ADRListing #OVL #EnergyStrategy #IndiaMarkets #InvestmentLiteracy

A company files Chapter 11 once and calls it a lesson learned. McDermott International filed

once in 2020, wiped out four point six billion dollars of debt, walked out with a fresh board and five hundred forty four million dollars of funded debt against two point four billion dollars of letter of credit capacity, and called it a new foundation. Four years later it was back in court, this time three courts at once, a UK Restructuring Plan and two Dutch WHOA proceedings running in parallel, recognized simultaneously by a US Chapter 15 filing so the whole compromise would bind creditors on three continents at the same time. That closed in March 2024. It is now July 2026, and McDermott just priced five hundred fifty million dollars of new bonds at ten and a half percent interest and opened a five hundred million dollar equity rights offering backstopped by its own largest shareholders. Three trips to the capital structure in six years, on a company that reported ten billion dollars of revenue last year and beat its own guidance doing it.

Start with where the debt came from, because it did not arrive by accident. In 2018 McDermott combined with Chicago Bridge and Iron for a purchase price near four point six billion dollars, and CB&I brought a set of fixed price LNG and refinery projects that had already gone wrong before the ink dried. Two of them, the Cameron LNG export facility in Louisiana and the Freeport LNG facility in Texas, burned cash for years after the merger closed. A third piece of the CB&I legacy, the Cartagena refinery expansion built for Colombia’s Reficar, had blown through its original four billion dollar budget by roughly double before McDermott ever inherited the liability, and the dispute over what Reficar was owed followed McDermott into both restructurings, forcing English and Dutch courts to argue over what fraction of a nineteen point nine percent equity stake a wronged Colombian counterparty deserved for an arbitration award that predated the merger entirely. McDermott’s own regulator found, years later, that CB&I project managers had overridden their own cost engineers’ loss forecasts on that same Cameron project by hundreds of millions of dollars to keep the numbers looking survivable. The debt McDermott carried into 2020 was not McDermott’s mistake. It was CB&I’s mistake, worn by the company that acquired it.

Now look at what the operating business actually does, because this is where the story gets interesting instead of just sad. First quarter 2026 revenue came in at two point four billion dollars against a planned one point nine billion, adjusted EBITDA at a hundred seventeen million against a planned ninety nine million, backlog at seventeen point six billion dollars, built on one point four billion dollars of new awards in the quarter alone. Full year 2025 revenue reached ten billion dollars, adjusted EBITDA four hundred twenty eight million, trailing twelve month EBITDA four hundred eighty nine million, and the company finished the year with eighteen point two billion dollars of backlog including first LNG achieved on Train 1 of the Golden Pass export facility in Texas, the same project class that once nearly sank it. McDermott is winning work. Aramco selected it for a long term project management consultancy agreement in June. Qatar handed it a landmark decommissioning engineering contract for the country’s first major offshore decommissioning project. The operating engine runs.

Here is the stress test, and it is a simple one. Four hundred twenty eight million dollars of adjusted EBITDA on ten billion dollars of revenue is a margin of roughly four percent. That is the entire cushion an engineering and construction contractor has to absorb a bad quarter, a delayed milestone payment, or a war disrupting a project site, which is not hypothetical, McDermott’s own first quarter filing named Middle East conflict disruption as a direct cost item running into the millions of dollars, on top of first quarter cash flow that was used, not generated, to the tune of a hundred twenty six million dollars even as revenue beat plan. Layer the new financing onto that margin. Five hundred fifty million dollars of bonds at ten and a half percent costs roughly fifty eight million dollars a year in interest alone, close to twelve percent of trailing twelve month EBITDA, before a single dollar of the older term debt or letter of credit facility is serviced. A four percent margin business does not have twelve percent of its EBITDA to spare on one bond coupon. It has that money because its own largest shareholders backstopped a rights offering to make sure it did, the same category of investor that took ninety four percent of reorganized equity in 2020 and absorbed the compromise again in 2024, writing a third check because the alternative was watching the first two checks go to zero.

That is the actual business model here, and it deserves its own name separate from the engineering work. McDermott refinances. Not once, as a company might if a single acquisition went wrong. Structurally, on a clock that keeps landing somewhere between three and six years, because a fixed price contracting business with a four percent margin has almost no room to absorb the debt load that a single bad merger, a single war zone disruption, or a single blown project estimate leaves behind. The engineering keeps getting done. The projects keep getting delivered, Golden Pass Train 1 is real LNG flowing today. But the capital structure underneath that engineering has never once been built to survive the industry it operates in without coming back to the same shareholders and the same courts to be rebuilt again.

Sources: McDermott International first quarter 2026 and fourth quarter and full year 2025 results, McDermott 2026 Annual General Meeting results, Norton Rose Fulbright and Kirkland and Ellis analysis of the 2024 UK Restructuring Plan and Dutch WHOA proceedings, Davis Polk summary of the 2020 Chapter 11 plan of reorganization, McDermott Nordic bond offering and equity rights offering press release July 2026, US Securities and Exchange Commission administrative order on CB&I project accounting.

I stood in a dry dock in front of three hundred and fifty tonnes of steel legs and a hull the

size of a football field, and the number that kept running through my head was not the water depth rating or the drilling package specs. It was two hundred and fifty million dollars. That is the low end of what it costs today to build a modern jackup rated for four hundred feet. The high end is three hundred million. Delivery, if the yard is honest with you, runs up to two and a half years.

In 2007, a Singapore yard would have quoted you the same rig class for a hundred eighty to a hundred ninety million dollars. Run the math and that is roughly a sixty percent increase in less than two decades, on a piece of equipment whose job has not changed since the day it was invented. It still stands on three legs in shallow water and drills a hole. The physics is identical. The price is not.

I want to walk you through why, because the answer is not inflation in the way most people use that word. It is a cost stack, and every layer of that stack tells you something different about who controls offshore construction today.

Louisiana State University’s Center for Energy Studies built a benchmark for a three hundred seventy five foot rig, published through Oil and Gas Journal, and it breaks the rig into six pieces. The rig kit, the structural package that becomes the actual platform, runs twenty five to forty five million dollars. The drilling equipment, the top drive, the mud system, the blowout preventer stack, runs twenty to fifty million. Steel for the hull and legs runs fourteen to thirty seven million. Power and electrical systems run three to six million. The remaining materials, everything from paint to piping to accommodation modules, run thirty three to forty one million. The yard keeps a profit margin of five to ten percent on top of all of it.

Then there is labour, and labour is where the story stops being about steel and starts being about geography. Shipyard labour on that same benchmark rig runs fifty one to sixty nine million dollars, and at a United States yard that labour line alone eats roughly thirty percent of total cost. At a Chinese yard, the same labour line eats roughly ten percent. Add the six pieces together and the LSU benchmark rig totals a hundred sixty four million dollars. Compare that to what a rig actually costs to build today, two hundred fifty to three hundred million, and the gap is not explained by steel prices or drilling equipment. It is explained by where the yard sits on the map and how few yards are left standing.

That scarcity is not theoretical. Borr Drilling picked up a stranded newbuild, Hull B378, for a hundred twenty two million dollars. The original order price on that same hull was close to two hundred forty million. Somebody walked away from that contract, the yard was left holding a half finished asset, and a disciplined buyer picked it up at roughly half of replacement cost. That is the entire jackup market compressed into one transaction. New construction at full price is a bet on a tight yard market holding tight for two and a half more years. A stranded newbuild at half price is a bet that someone else already took the risk and paid for your discount.

Here is the stress test. Assume day rates soften over the delivery window, which is not a hypothetical, it is the base case every operator plans around. A rig ordered today at two hundred seventy five million dollars needs years of elevated day rates just to clear its own construction cost before it earns a return. A rig like Hull B378, picked up at a hundred twenty two million, clears that same hurdle at less than half the day rate, for less than half the time. The newbuild buyer is underwriting two and a half years of yard risk, currency risk, and market risk on top of the equipment itself. The distressed buyer is underwriting none of that. They are buying a finished asset from someone else’s mistake.

This is why the jackup market has not seen a real construction wave since the last cycle collapsed. Every operator with capital discipline is doing the same math I just did, and the math says wait for the next stranded hull before you sign a newbuild order. The yards know this too, which is exactly why so few of them are still building jackups at all. Singapore’s fleet of active offshore yards is a fraction of what it was in 2007. China has absorbed most of what remains, and China’s labour cost advantage is now structural, not cyclical.

Label for this one, in the tradition of every other company I have put a name to in this newsletter: new construction compounds. Not the rig. The cost of building it, every year the yard base keeps shrinking and the labour arbitrage keeps widening.

I have stood next to enough of these rigs over thirteen years to know what a hundred sixty four million dollars of steel and equipment looks like in real life. What I was standing next to this time cost the yard almost double that to build, and the operator who ordered it is betting the market will pay for the difference. Sometimes that bet works. Sometimes you end up as Hull B378, sold at half price to a buyer who did the arithmetic I just did for you.

Sources: Westwood Global Energy Group RigLogix, S&P Global Commodity Insights, Louisiana State University Center for Energy Studies cost model published through Oil and Gas Journal.

February 9 2026. Transocean and Valaris announce a definitive agreement to combine, an all stock transaction valuing Valaris at

roughly five point eight billion dollars, creating a combined company with a pro forma enterprise value near seventeen billion dollars and, once regulators sign off, control over the largest concentration of ultra deepwater and harsh environment drilling capacity on earth. Transocean shareholders will own fifty three percent of the combined entity, Valaris shareholders forty seven, and the new board will seat nine Transocean directors against two from Valaris, a structure that leaves little ambiguity about which company absorbed which. This is the same Transocean that owned and operated the Deepwater Horizon, the rig at the center of the worst offshore oil spill in American history, a company found thirty percent liable for a disaster it has spent the years since paying to move past, now consolidating its way toward something close to market dominance over the exact business line that disaster was supposed to have permanently scarred.

THE HUNDRED YEAR MACHINE, BUILT ALMOST ENTIRELY THROUGH MERGERS

Transocean’s roots run back to 1926, when a draftsman and landman named T.S. Stoneman bought his first drilling rig with a personal check while working for the Danciger Oil and Refining Company in Fort Worth, Texas, a detail the company itself treats seriously enough to mark 2026 as its centennial year despite the modern corporate entity bearing little resemblance to anything Stoneman would have recognized. The more direct lineage starts in 1953, when Southern Natural Gas Company created The Offshore Company specifically to solve a gap in mobile offshore drilling capacity for the Gulf of Mexico, launching Rig 51 the following year as the world’s first mobile jackup drilling rig, a genuine industry first that established the company’s identity as a technology pioneer rather than a mere operator from its earliest days.

What followed for the next seven decades is less a single company’s growth story than a running tally of consolidation. Sonat Offshore Drilling merged with the Norwegian firm Transocean ASA in 1996 for one point five billion dollars, adopting the Transocean name. A three point two billion dollar merger with Sedco Forex followed in 1999, itself the product of an earlier merger between the Southeastern Drilling Company and the French firm Forages et Exploitations Petrolieres. In 2000 came the acquisition that would define the company’s future liability as much as its future fleet, seventeen point seven billion dollars for R&B Falcon Corporation and its hundred fifteen drilling rigs, a deal that made Transocean the world’s largest offshore drilling operation overnight and brought with it, almost as an afterthought inside such a large transaction, a single semisubmersible rig named Deepwater Horizon. The 2007 merger with GlobalSantaFe Corporation, valued at fifty three billion dollars, cemented Transocean’s position as the industry’s dominant player, and the following year the company moved its place of incorporation from the Cayman Islands to Switzerland, a decision significant enough to trigger removal from the S&P 500 index, since the index’s rules did not accommodate the new domicile.

Two years after that move, on April 20 2010, a blowout at BP’s Macondo well triggered an explosion aboard the Deepwater Horizon that killed eleven crew members and led, two days later, to the rig’s collapse and the start of an oil spill that would run for eighty seven days before the well was finally capped, the largest marine oil spill in history. Transocean was found responsible for thirty percent of the total liability, and a Transocean subsidiary agreed in January 2013 to plead guilty to a single misdemeanor violation of the Clean Water Act, paying four hundred million dollars in criminal fines and penalties alongside a separate one billion dollar civil settlement, one point four billion dollars total, the second largest environmental crime recovery in American history behind only BP’s own four billion dollar criminal settlement for the same disaster. Transocean was sentenced to five years of federal probation, the maximum term the law allowed, and agreed to a consent decree requiring measurable improvements to its drilling safety and emergency response practices.

The company kept consolidating regardless. Aker Drilling’s harsh environment Norwegian fleet came aboard for two point two billion dollars in 2011. Songa Offshore’s completion closed in January 2018, and Ocean Rig followed the same year for two point seven billion dollars. The Valaris combination, announced this February, is simply the latest and largest chapter in a strategy Transocean has run continuously since the 1990s, buying scale and capability rather than building it, a pattern the company’s own centennial framing quietly acknowledges by celebrating a hundred years of a business that has spent most of those years being assembled out of other companies’ fleets rather than growing organically from within a single one.

THE BUSINESS MODEL, A DAY RATE BET ON A RIG THAT ALREADY EXISTS

Transocean’s business runs on a fundamentally different mechanism than any of the three oilfield services companies this newsletter has already profiled. Halliburton, Baker Hughes, and Weatherford sell expertise, equipment, and labor against a customer’s decision to spend this specific quarter. Transocean sells the rig itself, a mobile offshore drilling unit already built, staffed, and maintained, leased to an oil company at a negotiated day rate for a contract that can run months or years, with premium ultra deepwater rigs currently commanding day rates above six hundred thousand dollars. This structure gives Transocean something none of the pure services companies carry, a backlog, the total value of contracted future work already signed and locked in, which stood at roughly six point one billion dollars as of February 2026, providing multi year revenue visibility no quarter to quarter services business can match. The tradeoff is capital intensity on a scale services companies never face. A single ultra deepwater drillship can cost hundreds of millions of dollars to build and tens of millions annually to maintain, whether or not a customer is currently paying to use it, meaning Transocean’s entire economic model depends on keeping an enormously expensive fleet as close to fully utilized as physically possible.

The fleet itself splits into two broad categories, floaters, semisubmersibles and drillships capable of operating in deep and ultra deep water without a fixed connection to the seabed, and jackups, rigs that extend legs down to the seafloor for shallower water work. Transocean has spent the past decade deliberately narrowing its focus toward the highest specification end of the floater market, ultra deepwater and harsh environment rigs capable of commanding premium day rates precisely because so few competitors can build or operate equipment to the same standard, a scarcity based strategy distinct from the volume based competition defining the pure services segment this newsletter has already documented running thin margins for Halliburton and Weatherford alike.

THE NUMBERS, WHERE OPERATIONAL STRENGTH AND A HEADLINE LOSS COEXIST

Full year 2025 contract drilling revenue reached three point nine six five billion dollars, up thirteen percent from 2024, with adjusted EBITDA climbing nineteen percent to one point three seven billion dollars and revenue efficiency, the percentage of available rig time actually billed, reaching ninety six point five percent, a genuinely strong operational year by every metric management directly controls. Cash flow from operations jumped sixty eight percent to seven hundred forty nine million dollars, free cash flow reached six hundred twenty six million dollars, and the company cut total debt by one point two five eight billion dollars to five point six eight six billion, while adding eight hundred thirty nine million dollars of new contract backlog at a weighted average day rate of four hundred fifty three thousand dollars.

Against all of that operational strength, Transocean reported a full year net loss attributable to controlling interest of two point nine one five billion dollars, three dollars and four cents per diluted share, a number that reads as a genuine crisis until its actual source becomes clear. Three billion thirty six million dollars of asset impairment charges, recognized as the company wrote down the value of aging rigs it determined were worth less than their carrying value, including the ultra deepwater floaters Deepwater Nautilus, Development Driller III, and Discoverer Inspiration once those units were classified as held for sale, drove essentially the entire loss. Strip out the impairments and a ninety nine million dollar loss on a debt conversion, and Transocean actually generated thirty seven million dollars of adjusted net income for the year. This is the recurring pattern investors following this stock have learned to read past, strong and improving operational metrics sitting underneath large, non cash impairment charges as the company continuously prunes its oldest, least competitive rigs from an otherwise increasingly premium fleet, a bookkeeping reality that punishes the headline number specifically because Transocean is doing the fleet discipline work a capital intensive business is supposed to do.

THE VALARIS MERGER, CONSOLIDATION AT A SCALE THE INDUSTRY HAS NOT SEEN

The Business Combination Agreement signed February 9 2026 structures the deal as a court sanctioned scheme of arrangement under Bermuda law, Valaris being a Bermuda incorporated company, with each Valaris share converting into fifteen point two three five Transocean shares, implying a value of roughly eighty two dollars twelve cents per Valaris share at signing, a thirty one point six percent premium to Valaris’ prior closing price. The deal followed a competitive process, Transocean having pursued and then walked away from a different unnamed target, referred to in filings only as Transocean Party A, before returning with what regulatory filings describe as its best and final offer for Valaris on February 6. Both boards approved the agreement unanimously, and major shareholders on both sides, including Perestroika AS, a Cyprus based entity affiliated with a Transocean director that holds roughly nine percent of Transocean’s own shares, along with Famatown Finance and Oak Hill Advisors holding a combined eighteen percent of Valaris, signed support agreements backing the transaction. The combination is expected to close in the second half of 2026, subject to shareholder votes on both sides, court sanction in Bermuda, and regulatory approval.

The competitive implications are the part worth sitting with longest. Transocean and Valaris are, between them, two of the three or four companies capable of building and operating the highest specification ultra deepwater rigs on earth. Combining them does not just create scale, it materially reduces the number of independent bidders an oil major or national oil company can play against each other when negotiating a day rate for the kind of rig only a handful of companies in the world can actually supply. Every prior Transocean merger this issue has documented followed the same logic, more scale, fewer genuine competitors at the premium end of the fleet, and the Valaris combination simply completes that decades long pattern at a scale the offshore drilling industry has not previously seen concentrated inside a single company.

THE DISASTER THAT NEVER FULLY LEAVES THE STORY

This newsletter’s Halliburton issue already documented that company’s one point one billion dollar Deepwater Horizon settlement, its role limited to the cementing work performed on the Macondo well. Transocean’s exposure ran deeper, since Transocean owned and operated the rig itself, including the blowout preventer and riser that failed to stop the disaster once it began. Assistant Attorney General Lanny Breuer’s own language framing the 2013 settlement placed direct blame on Transocean’s rig crew for accepting BP’s direction to proceed in the face of clear danger signs, a characterization a Transocean subsidiary accepted when it pleaded guilty on behalf of the broader Transocean group. Three different companies, BP, Transocean, and Halliburton, ultimately paid out a combined total exceeding six billion dollars in criminal and civil penalties tied to a single well, a reminder that a catastrophic failure in this industry rarely traces to one company’s negligence alone, and that the companies this newsletter covers individually are, more often than readers might assume, entangled in the same disasters from different angles of the same well.

INDIA, A RECORD SET RATHER THAN A RELATIONSHIP BUILT

Transocean’s most notable India connection is a technical record rather than an ongoing commercial partnership on the scale this newsletter has documented for Baker Hughes or even Halliburton. The Dhirubhai Deepwater KG2, a Transocean rig, set a world water depth drilling record of ten thousand one hundred ninety four feet while working for Reliance Industries off India’s coast, a genuine engineering milestone that put Indian deepwater exploration on the map for the global offshore industry at the time. Beyond that specific achievement, Transocean’s current India footprint appears considerably thinner than its Middle East, North Sea, and Latin American presence, worth noting honestly rather than stretched into a relationship the available evidence does not support at the depth this newsletter found for other companies in this sector.

WHETHER THE WAR ACTUALLY REACHES THIS BUSINESS MODEL

Transocean’s exposure to the 2026 Iran war looks structurally different from every services company this newsletter has covered, precisely because of the backlog mechanism underlying its business model. A war disrupting this quarter’s activity barely touches revenue already locked into a multi year day rate contract signed before the conflict began, the same insulation this newsletter documented running through Baker Hughes’ Industrial and Energy Technology backlog. Where the war actually matters for Transocean is at the point of new contracting, whether oil majors and national oil companies currently negotiating day rates for 2027 and beyond adjust their offshore capital spending plans in response to sustained regional instability, a slower moving and less immediately visible risk than the direct quarterly revenue hits this newsletter documented at Halliburton and Weatherford.

WHAT THE TAPE IS SAYING NOW

China has repeatedly exported cost deflation into industries where it has built overwhelming manufacturing scale, and premium offshore drilling capacity is currently running in the opposite direction entirely, the same scarcity dynamic this newsletter documented driving Baker Hughes’ turbine pricing power. Years of depressed day rates following the 2014 and 2020 downturns pushed the entire industry to scrap older rigs and build almost nothing new, leaving a genuinely constrained supply of high specification floaters just as offshore project economics have improved enough to justify new deepwater final investment decisions. Rystad Energy’s own research shows annual greenfield offshore capital expenditure broke the hundred billion dollar threshold in both 2022 and 2023 for the first time in a decade, with more than two hundred billion dollars of new offshore project investment lined up across those two years alone, and Rystad’s most recent industry outlook projects capacity constraints across subsea vessels, deepwater rigs, and floating production equipment building through 2026 and intensifying further in 2027 as a new wave of deepwater and LNG linked final investment decisions reaches completion. Transocean’s own newbuild program, anchored by the Deepwater Titan, the first drillship rated for twenty thousand psi operations and capable of unlocking Paleogene reservoirs in the Gulf of Mexico previously out of reach for lower rated equipment, positions the company at the exact scarce, high specification end of a market where the Valaris combination will only concentrate pricing power further.

STRESS TEST

Continued impairment charges are close to a structural certainty rather than a one time event, since Transocean’s strategy explicitly involves scrapping its oldest rigs as they age out of competitiveness, meaning future headline net losses driven by non cash writedowns should be read in the same context as 2025’s rather than treated as a fresh crisis each time they recur.

The Valaris merger carries real integration and regulatory risk, still subject to shareholder votes on both sides, Bermuda court sanction, and antitrust review in a combination material enough to meaningfully concentrate the ultra deepwater rig market, any of which could delay or complicate the transaction before its targeted second half 2026 close.

Day rate cyclicality has not disappeared simply because the current environment favors premium rig owners. A sustained oil price decline serious enough to push oil majors toward deferring offshore final investment decisions would hit Transocean’s backlog renewal rate directly, the same vulnerability that produced the depressed day rate years the company’s current scarcity advantage is a direct reaction against.

THE INSTITUTIONAL LABEL

Transocean consolidates. A hundred years removed from a landman’s personal check for a single drilling rig, the company has built its entire modern identity through acquisition after acquisition, Sonat, Sedco Forex, R&B Falcon, GlobalSantaFe, Aker, Songa, Ocean Rig, and now Valaris, each deal adding scale and, more quietly, reducing the number of genuine competitors capable of matching Transocean’s premium fleet. The Deepwater Horizon disaster interrupted that pattern for exactly as long as the legal and financial consequences took to resolve, and not one day longer. Sixteen years after a rig this company owned killed eleven people and triggered the worst oil spill in American history, that same company is finishing the largest consolidation of offshore drilling capacity the industry has ever seen, and the market has, by and large, decided the disaster is a settled cost rather than a permanent ceiling.

SOURCES

Transocean Ltd. fourth quarter and full year 2025 results, Form 8-K, February 19 2026. Transocean Ltd. and Valaris Limited joint Business Combination Agreement and press release, Form 8-K and DEFA14A, February 9 2026. Transocean and Valaris preliminary merger proxy statement, Form PREM14A, May 19 2026. Wikipedia, Transocean corporate history and Deepwater Horizon incident. Deepwater.com, Transocean official company history and centennial timeline. StockTitan and TipRanks, Transocean fourth quarter and full year 2025 results analysis, February 20 2026. US Department of Justice, Environmental Protection Agency, and NOLA.com, Transocean Deepwater Horizon Clean Water Act guilty plea and one point four billion dollar settlement, January 2013. Transocean Ltd. Form 10-Q, third quarter 2025, rig impairment disclosures. PortersFiveForce.com and MatrixBCG.com, Transocean fleet composition and newbuild program, including the Deepwater Titan twenty thousand psi drillship.

Windhoek, January 30, 2026. Patrick Pouyanné flies in from Paris. Paula Amorim

flies in from Lisbon. Both sit across from Netumbo Nandi Ndaitwah, Namibia’s first woman president, in a country of three million people that pumped zero barrels of oil a decade ago. Cameras that week were pointed elsewhere, fixed on the Strait of Hormuz, Squawk Box guests arguing whether Brent retests one hundred dollars while Trump talks blockade and toll. Windhoek got none of that attention. Windhoek is where the real capital decision of the year got made.

Galp Energia is a Lisbon listed energy company with a market capitalisation most global investors could not name a decade ago. It refines fuel in Portugal, sells solar power in Iberia, and holds legacy production in Brazil’s pre salt basins. Then in 2023, drilling in the deep water off Namibia’s coast, Galp hit oil in what became the Mopane field. Water depth runs one to three kilometres. Wood Mackenzie named Mopane its discovery of the year for 2025. Galp itself has floated a resource estimate as high as ten billion barrels of oil equivalent, a number that would rank among the largest finds of the decade anywhere on earth.

Here is the layer most readers stop at: big discovery, stock goes up. It did. Galp’s market capitalisation stood near ten point six billion euros in January 2026, roughly double what it was before Mopane. Shares moved from fourteen euros to above twenty. A small Toronto listed junior with an indirect sliver of the field, Sintana Energy, rode the same wave on its own exchange.

Stop there and you miss the actual mechanics. Galp held an eighty percent working interest in the license carrying Mopane, alongside Namibia’s state company Namcor at ten percent. Eighty percent of a ten billion barrel field, at water depths that need floating production vessels costing billions of dollars apiece, is not a position Galp’s balance sheet could carry alone. Developing Venus, the neighbouring TotalEnergies discovery, is already pegged near eleven billion dollars for a single production vessel. Mopane sits in the same cost universe.

So Galp did what it had to do. In December 2025 it handed forty percent of its Mopane stake to TotalEnergies, along with operatorship. In exchange it picked up a ten percent interest in TotalEnergies’ Venus license and a nine point four percent interest in a third block, PEL91. TotalEnergies also agreed to carry fifty percent of Galp’s capital spending on exploration, appraisal, and the first phase of development at Mopane. That carry gets repaid later, out of fifty percent of Galp’s future cash flow from the project once it produces. Galp gave up scale and operating control. It kept exposure and removed near term capital risk from its own books.

Watch what that trade actually does to Galp’s economics. A resource company with a ten billion barrel discovery and a market cap of ten point six billion euros looks, on paper, absurdly cheap per barrel. Cut the working interest to forty percent and layer in a repayable carry, and the true net present value Galp can book today shrinks hard. The market already re rated the stock on headline resource size. The unit economics say a chunk of that resource now belongs, functionally, to TotalEnergies’ balance sheet until the carry clears.

Galp prospects.

That is the label, and it is not new. Eni ran this exact playbook for two decades. Explore aggressively with a large working interest, absorb the geological risk yourself, then once the discovery is proven, sell down a slice to a major or a national partner who brings the balance sheet and the operating muscle a deep water buildout demands. Ghana. Mozambique. Egypt’s Zohr field. Eni’s whole reputation as the company that securitises its discoveries was built on this sequence, farm down after the drill bit does its work, not before. Galp just ran the identical trade at Mopane, at a scale that made a mid cap Portuguese company suddenly relevant to every major oil desk in London and Houston.

Stress test it. The carry sounds like free money. It is deferred money. Galp still owes fifty percent of that capital back out of its own future cash flow, which means the project has to actually produce, on schedule, before Galp sees the full economic benefit of the discovery it made. Three appraisal wells are scheduled for 2026 to firm up the resource number Galp has been quoting. Reservoir quality at Mopane has so far avoided the permeability problems that hit Shell’s nearby Graff field and forced a four hundred million dollar writedown, and separately been flagged as a concern at TotalEnergies’ own Venus field. If Mopane’s rock behaves worse under appraisal than under exploration drilling, the ten billion barrel number gets trimmed, and Galp’s negotiated slice of a smaller pie looks a lot less generous.

Then there is Namibia itself. A government running its first ever oil boom, with a brand new president, is going to want more from these licenses over time, not less, on local content, on jobs, on fiscal terms once the country has proven reserves in the ground rather than exploration promises on paper. Every farm down deal signed in 2025 gets renegotiated in spirit, if not in law, once first oil is closer and the government’s leverage rises. Watch how a small state with limited institutional experience in managing a resource this large chooses to wield that leverage.

Zoom out further and the same instinct that made this discovery valuable is running into a world that has stopped rewarding new barrels the way it used to. China’s refined product exports keep growing, undercutting refining margins across Asia and Europe, a quiet deflationary force running underneath every headline about Middle East supply risk. The IEA now expects global oil demand to fall this year for the first time since 2020. A giant discovery in 2026 is being valued in a market that is simultaneously worried about too much oil, not too little. Galp found ten billion barrels in a world that increasingly wonders what to do with the barrels it already has.

The ground gave Galp an empire. The balance sheet made Galp give half of it away before a single barrel reached a tanker.

In 2026, Weatherford International announced a redomestication,

moving its legal home from Ireland to Texas, a transition the company expects to complete in the third quarter of the year pending shareholder approval. Texas is not a new address for this company. It is the original one. Weatherford International traces its roots to 1941, when Jesse E. Hall Senior founded the Weatherford Spring Company in the town of Weatherford, Texas, the actual place the entire company is named after. Between that founding and this year’s announcement, the company spent decades incorporating in Bermuda, then Switzerland, then Ireland, chasing tax efficiency across three different jurisdictions before a bankruptcy, an accounting fraud scandal, and a near total collapse forced a level of self examination that apparently ended with the conclusion that home was the better address after all.

THE EIGHTY FIVE YEAR MACHINE, INTERRUPTED TWICE

Jesse Hall’s spring company had nothing to do with oil at first, but Texas oilfields needed the kind of mechanical parts a spring manufacturer could produce, and the business gradually reoriented itself toward the industry surrounding it. The company that became modern Weatherford traces its more direct corporate lineage to 1972, when Energy Ventures was created as an exploration and production company, trading over the counter with a market capitalization of roughly fifteen million dollars. In 1987, Energy Ventures hired Bernard J. Duroc-Danner to start up an oilfield service and equipment business inside the company, and Duroc-Danner spent the next three decades building it through what would eventually total more than three hundred separate acquisitions. The company renamed itself EVI in 1990, then Weatherford International in 1998, following its own acquisition of the original Weatherford Enterra oilfield services business, and between 1999 and 2008 it grew aggressively by focusing specifically on mature field development, a deliberate departure from the industry’s prevailing focus on new exploration at the time.

Duroc-Danner’s growth strategy eventually collided with the same pressure every fast growing company built through hundreds of bolt on acquisitions eventually faces, the absence of a single unified operating and accounting system underneath all that growth. Between 2007 and 2012, Weatherford issued false financial statements that inflated earnings by more than nine hundred million dollars, achieved by fraudulently lowering the company’s year end income tax provision by roughly a hundred million to a hundred fifty four million dollars annually, adjustments made specifically to align reported results with analyst expectations Weatherford itself had set. Weatherford had spent years touting its favorable effective tax rate to investors as a genuine competitive advantage, and the fraud existed largely to protect that specific narrative once the underlying numbers stopped supporting it on their own. The company was forced to restate its financial statements three separate times across 2011 and 2012. The Securities and Exchange Commission’s Andrew Ceresney summarized the scheme plainly, describing a company that denied investors accurate financial reporting by allowing two executives to manufacture numbers whenever actual results fell short of what had already been promised. Weatherford agreed to pay a hundred forty million dollars to settle the charges in September 2016, with two former tax executives separately charged over their direct role in the scheme. Duroc-Danner, who had run the company for twenty nine years, stepped down as chief executive that same November, replaced on an interim basis by Krishna Shivram before Mark McCollum took over permanently in March 2017.

None of that leadership change repaired the balance sheet fast enough. By 2019, after more than four years without a profitable quarter, Weatherford entered a restructuring support agreement with its creditors and filed a prepackaged Chapter 11 bankruptcy on July 1 2019 in the Southern District of Texas, alongside parallel examinership proceedings in Ireland reflecting the company’s legal domicile at the time. The filing eliminated approximately six point two billion dollars of outstanding debt, and Weatherford emerged from bankruptcy on December 13 2019 with two point six billion dollars in new exit financing facilities and over nine hundred million dollars of liquidity, unsecured noteholders exchanging roughly seven point four billion dollars of senior notes for ninety nine percent of the reorganized company’s equity. The company’s shares had been suspended from New York Stock Exchange trading in May 2019 before the filing, traded briefly on the OTC Pink marketplace afterward, and eventually relisted on the Nasdaq under the ticker WFRD. Girish Saligram was named president and chief executive in September 2020, inheriting a company that had been rebuilt from close to nothing twice in less than a decade, once through fraud that had to be unwound, once through a bankruptcy that reset the capital structure entirely.

THE BUSINESS MODEL, SPREAD ACROSS MORE FLAGS THAN ITS RIVALS

Weatherford organizes its operations into three segments. Drilling and Evaluation covers wireline services, drilling services, and managed pressure drilling, the tools and expertise deployed while a well is actively being drilled. Well Construction and Completions covers cementation products, liner hangers, and completion systems, the work that finishes a well once drilling is done. Production and Intervention covers artificial lift, well intervention, and the equipment that keeps an already producing well flowing efficiently over its lifetime. All three segments share the same short cycle exposure this newsletter has now documented running through every pure services company it has covered, revenue that depends directly on a customer’s decision to spend this quarter rather than next.

What distinguishes Weatherford from Halliburton specifically is geography rather than segment structure. Full year 2025 international revenue came to three point nine three five billion dollars against total revenue of four point nine one eight billion, meaning roughly eighty percent of Weatherford’s business runs outside North America, a materially higher international weighting than Halliburton carries, spread across national oil companies and international majors in the Middle East, Latin America, Europe, Sub-Sahara Africa, Russia, and Asia rather than concentrated in a single dominant basin. The company’s own quarterly contract announcements read almost like a world tour, Kuwait Oil Company, ADNOC, PDO Oman, Eni Oman, Petrobras, YPF, Petronas Indonesia, Pertamina, bp Azerbaijan, all inside a single recent quarter’s operational highlights, a genuinely diversified customer base that gives Weatherford less single country concentration risk than a company leaning more heavily on any one region, even as it means the company has no equivalent to a single dominant home market the way Halliburton has North American shale.

THE NUMBERS, A SMALLER COMPANY RECOVERING IN REAL TIME

Full year 2025 revenue came to four point nine one eight billion dollars, down eleven percent from 2024, with operating income falling nineteen percent to seven hundred fifty six million dollars and net income declining fifteen percent to four hundred thirty one million dollars, an eight point eight percent net margin. The fourth quarter showed real sequential improvement even against a softer year over year comparison, revenue of one point two eight nine billion dollars, down four percent year over year but up five percent sequentially, and net income of a hundred thirty eight million dollars, up a striking seventy percent from the third quarter alone, evidence of a business finding its footing quarter over quarter even as the full year comparison against a stronger 2024 still reads as a decline.

The first quarter of 2026 complicates that recovery narrative directly. Revenue came to one point one five two billion dollars, down three percent year over year and down eleven percent sequentially, operating income fell thirteen percent to a hundred twenty three million dollars, and net income actually rose to a hundred eight million dollars, up forty two percent year over year on a nine point four percent margin, aided by lower tax expense and financing costs even as the underlying operating trend softened. Diluted earnings per share reached one dollar forty nine cents, up forty four percent year over year, a genuinely strong headline number sitting on top of an operating environment management itself described as under real pressure. Weatherford’s own first quarter filing names the cause without euphemism, stating plainly that conflict in Iran and trade and tariff uncertainty disrupted Middle East operations and logistics, producing near term pressure that management expects to potentially recover in the second half of the year. Segment detail confirms the geography of the damage, Drilling and Evaluation revenue fell eight percent year over year specifically on lower activity in Latin America, the Middle East, North Africa, and Asia, partially offset by a seventeen percent year over year increase in Europe, Sub-Sahara Africa, and Russia revenue, the one region where Weatherford’s business actually grew through the same quarter the Middle East was contracting.

THE WAR, NAMED DIRECTLY RATHER THAN IMPLIED

Every services company this newsletter has profiled so far has described the 2026 Iran war’s impact through some version of careful corporate language, disruptions, headwinds, activity softness. Weatherford’s own first quarter 2026 disclosure is the most direct of the three, naming the conflict in Iran specifically as a cause of disrupted Middle East operations and logistics, language that leaves considerably less room for alternative explanation than the general capital discipline framing this newsletter has used to describe North American shale softness elsewhere. Given how heavily Weatherford’s revenue mix leans international relative to Halliburton and Baker Hughes, and given that a meaningful share of that international revenue runs directly through the Middle East, Kuwait, the UAE, Oman, Qatar, Saudi Arabia, all appearing repeatedly in the company’s own recent contract disclosures, the war’s impact on Weatherford is close to a direct read through from regional disruption to reported revenue, without the layer of North American capital discipline complicating the picture the way it does for its larger rivals.

THE INDIA RELATIONSHIP, SMALLER AND DIFFERENTLY SHAPED

Weatherford’s presence in India runs through a different door than the ONGC centered relationships this newsletter has documented for both Baker Hughes and Halliburton. In 2025, Cairn Oil and Gas, the Vedanta owned operator running Rajasthan’s Barmer basin, awarded Weatherford a letter of award covering completions, liner hanger, and whipstock systems alongside managed pressure drilling services for a high temperature, ultra high temperature drilling and rigless project in Barmer specifically, a technically demanding well environment that rewards exactly the kind of completions expertise Weatherford’s Well Construction and Completions segment specializes in. This is a smaller, more specific relationship than the two decade, multi basin ONGC partnership Baker Hughes has built or the broader if more fraught Halliburton ONGC history this newsletter has already covered, evidence that Weatherford’s India strategy runs more through India’s private and semi private operators than through the state owned giant that dominates the country’s upstream sector, a genuinely different entry point into the same country.

WHETHER A SMALLER COMPANY CAN AFFORD TO DIGITIZE ITS WAY FORWARD

Weatherford’s own recent technology investments show a company betting on digital efficiency rather than the kind of structural business model pivot Baker Hughes made through its GE merger and Chart acquisition. The Victus intelligent managed pressure drilling system, deployed for Kuwait Oil Company specifically to improve operational efficiency and accelerate well delivery timelines, and the Real Time Decision Centers Weatherford now operates onshore in Kuwait, both represent a bet that data and automation can extract more value from Weatherford’s existing service lines rather than replace them with an entirely new business line the way Baker Hughes’ turbine business has. The company’s November 2024 acquisition of Datagration, a data and analytics platform for exploration and production operations, points the same direction, adding software capability rather than the kind of long cycle industrial equipment manufacturing Baker Hughes acquired through Chart. Weatherford also signed a strategic training partnership with Maersk Training in February 2026, a smaller but telling signal that even as automation advances, the company still sees enough of a future for human operators in its own service lines to invest in training them better rather than only in replacing them.

The honest read on Weatherford’s replaceability sits closer to Halliburton’s position than to Baker Hughes’. Both remain fundamentally service intensive businesses exposed to short cycle activity decisions, and neither has built anything resembling IET’s long cycle backlog to soften the transition if automation and digitalization eventually do shrink the labor intensity this entire industry has depended on for a century. Weatherford’s smaller size relative to its two larger rivals cuts both ways here, giving the company less capital available to build an equivalent hedge, while its genuinely diversified international customer base gives it less single market concentration risk than Halliburton’s North American weighting carries.

THE POLITICS OF A COMPANY WILLING TO GO WHERE OTHERS WON’T

Weatherford announced its return to operations in Libya in September 2025, reentering a market that has spent more than a decade cycling through civil conflict, competing governments, and periods of near total foreign operator withdrawal. That willingness to reenter genuinely difficult jurisdictions runs through the rest of Weatherford’s current contract book as well, Iraq, Kazakhstan, Turkmenistan, Angola, markets that carry real political risk premiums most of the larger integrated majors this newsletter covers manage more cautiously through joint ventures and phased commitments than a pure services company managing its own direct contract exposure typically can.

The redomestication itself carries its own political logic. Moving from Ireland to Texas simplifies the company’s corporate and tax structure, reduces compliance costs tied to operating a foreign domicile, and, in the company’s own stated reasoning, provides access to a larger pool of American shareholders and lenders while enabling more agile management of global tax considerations, language that reads as a polite way of saying the offshore domicile strategy Duroc-Danner era leadership once pursued for tax efficiency no longer clears the cost benefit bar it once did, now that the company is smaller, more scrutinized, and less able to absorb the administrative overhead multiple international jurisdictions require.

WHAT THE TAPE IS SAYING NOW

China exports deflation into whatever industry it decides to scale, and Weatherford’s own contract book, spread thin across dozens of national oil companies and international operators rather than concentrated in a single scarce resource the way Baker Hughes’ turbine business currently is, sits fully exposed to that mechanism. Every contract this newsletter has cited from Weatherford’s own recent disclosures, three year extensions, five year frame agreements, one year renewals, describes a company competing quarter after quarter, region after region, against Halliburton, SLB, and a long tail of smaller regional players for the same finite pool of global drilling and completion spending. There is no scarcity premium anywhere in this business model. There is only competitive execution, contract by contract, in exactly the kind of oversupplied services market this newsletter has now documented squeezing every pure services company it has examined.

STRESS TEST

The Middle East war’s direct, company acknowledged impact on operations and logistics remains unresolved, and management’s own stated expectation of a second half 2026 recovery is a forecast, not a certainty, in a conflict this newsletter has already documented running longer and less predictably than most participants initially expected.

The redomestication carries real execution risk of its own, still subject to shareholder approval and other customary conditions as of this writing, a corporate transition layered on top of an already volatile operating environment.

Weatherford’s smaller scale relative to Halliburton and Baker Hughes leaves less room for absorbing a second shock, whether from the war, from a renewed North American slowdown, or from losing any single one of the many national oil company relationships the company’s diversified but individually smaller contract book depends on.

The company’s history of fraud and near collapse is not ancient, well within the working memory of investors and customers who lived through both the restatement scandal and the bankruptcy, a reputational overhang that likely still costs Weatherford some pricing power and contract trust relative to rivals who never had to rebuild from zero the way this company has, twice, in less than fifteen years.

THE INSTITUTIONAL LABEL

Weatherford recovers. Named after a Texas town it spent decades legally fleeing for tax reasons, run through a fraud scheme that inflated earnings by nine hundred million dollars, forced through a bankruptcy that wiped out ninety nine percent of the equity value the fraud years had built, and now, finally, coming home, both literally, with the Texas redomestication, and figuratively, with a business that has spent the years since 2019 rebuilding one three year contract at a time rather than one accounting adjustment at a time. Halliburton grinds against a concentrated North American shale cycle. Baker Hughes reinvents itself into an entirely new industrial identity. Weatherford simply recovers, slower, smaller, and more cautiously than either of its larger rivals, from a fall that was almost entirely self inflicted.

SOURCES

Weatherford International fourth quarter and full year 2025 results, Form 8-K, February 3 2026. Weatherford International first quarter 2026 results, Form 8-K and Form 10-Q, April 21 2026. Wikipedia, Weatherford International corporate history. SEC press release and Whistleblower News, Weatherford accounting fraud settlement, September 27 2016. Financier Worldwide, JPT SPE, and Rigzone, Weatherford Chapter 11 bankruptcy filing and emergence, July through December 2019. Empor.top, Weatherford International complete company history and accounting scandal analysis. GlobeNewswire, The Globe and Mail, Nasdaq, and Energy Digital, Weatherford first quarter 2026 results and redomestication announcement, April 21 2026. TradingView, Weatherford first quarter 2026 10-Q analysis including Iran conflict and tariff impact commentary. StockTitan, Weatherford and Noble Corporation managed pressure drilling and aftermarket agreement, May 5 2026. Weatherford International Form 8-K operational and commercial highlights, first through third quarter 2025, including the Cairn Oil and Gas Barmer, India contract award and the Libya return to operations announcement. KeyFactsEnergy, Weatherford press release index, 2024 through 2026.

March 16 2026. Halliburton, working alongside ExxonMobil, Sekal, Noble, and the Wells

Alliance team in Guyana, completes what the companies describe as the industry’s first fully automated geological well placement, a well drilled and steered to its target without a human hand directly on the controls at the critical moments that decision used to require. A hundred seven years earlier, in Duncan, Oklahoma, a young engineer named Erle P. Halliburton built a wooden mixing box, borrowed a wagon and a team of mules, and started cementing oil wells by hand because no company existed yet to do it for him. The distance between those two facts, a mule drawn cement wagon and a fully automated well, is the entire story of what Halliburton has become, and it is also the story of exactly how much of that distance the company still has left to cover before automation finishes the job it started on its own labor model.

THE HUNDRED SEVEN YEAR MACHINE

Erle Halliburton founded the New Method Oil Well Cementing Company in 1919 in Burkburnett, Texas, following that town’s 1918 oil discovery, applying cementing techniques he had learned working in California’s oilfields to a problem the entire industry needed solved, how to seal a well properly so it would produce safely rather than collapse or flood. He patented the jet mixer, a truck mounted device that combined water and cement mechanically instead of by hand, and the measuring line, which brought precision to a process that had previously relied on guesswork, and across his lifetime he patented thirty eight separate oilfield inventions. In 1920 the company renamed itself Halliburton Oil Well Cementing Company, HOWCO, and set up headquarters in Duncan, Oklahoma, where it incorporated in Delaware in 1924 with fifty six employees on the payroll. By 1926 the company had already gone international, selling cementing units to an English company operating in Burma and establishing early operations in India, while Halliburton’s own brothers expanded the business into Alberta, Canada. When Erle Halliburton died in 1957, the company operated two hundred one offices across twenty two states and twenty countries, a global footprint built inside less than four decades from a single wooden mixing box.

The company’s next major transformation arrived in 1962, when it acquired Brown and Root, an engineering and construction firm founded by brothers George and Herman Brown alongside their brother in law Dan Root, following Herman Brown’s death. Brown and Root, later merged with the M.W. Kellogg engineering firm to form Kellogg Brown and Root, KBR, gave Halliburton a second identity entirely separate from oilfield cementing, large scale infrastructure and engineering work that would eventually include extensive United States military contracting. That second identity became politically explosive decades later. Dick Cheney took over as Halliburton’s chairman and chief executive in 1995, five years before becoming Vice President under George W. Bush, and used his tenure to push aggressive international expansion, most consequentially the 1998 acquisition of Dresser Industries, a former competitor whose earlier asbestos related business exposed Halliburton to liability that would eventually cost the company billions. Under Cheney, Halliburton also faced accusations of overcharging the United States government on contracts and running operations through overseas subsidiaries structured to route around American sanctions on Iran, allegations that followed Cheney directly into the vice presidency and became a defining talking point during the Iraq War years that followed, when KBR received an estimated thirty nine point five billion dollars in Iraq related contracts, much of it awarded without competitive bidding.

The asbestos liability inherited through Dresser eventually forced Halliburton into a four billion dollar settlement, finalized in January 2005, that allowed KBR to exit Chapter 11 bankruptcy and returned the parent company to quarterly profitability. Halliburton spun KBR off as an independent public company on April 5 2007, formally separating the oilfield services business from the government contracting and engineering business that had generated so much of the political controversy trailing the company through the 2000s. The spinoff did not end Halliburton’s exposure to catastrophic liability. Three years later, on April 20 2010, the Deepwater Horizon rig exploded in the Gulf of Mexico, killing eleven workers and triggering the largest offshore oil spill in American history. Halliburton was BP’s cement contractor on the well, responsible for placing the centralizers that stabilize a well bore during cementing, and BP later pursued fraud and negligence claims against Halliburton directly, alleging misrepresentation about the stability testing performed on the foamed cement used at the Macondo well, while Halliburton countered publicly that BP’s own decision to use only six centralizers instead of the recommended number, made to save time and money, bore real responsibility for the blowout. Halliburton ultimately agreed to pay approximately one point one billion dollars to settle a substantial portion of the resulting claims, a settlement finalized in stages between 2014 and 2016 that allowed the company to close the chapter without admitting the fraud allegations BP had leveled against it.

THE BUSINESS MODEL, ONE CLOCK RUNNING EVERYWHERE

Halliburton organizes itself around two segments, and unlike the divergent structure this newsletter documented running through Baker Hughes, both of Halliburton’s segments run on essentially the same clock. Completion and Production covers stimulation, cementing, completion tools, and production enhancement, the services a producer buys once a well is drilled and needs to be finished and brought online. Drilling and Evaluation covers wireline logging, drilling services, project management, and formation evaluation, the services a producer buys while a well is actually being drilled. Both segments get paid when a producer decides to drill or complete a well this quarter, and neither segment carries anything resembling Baker Hughes’ Industrial and Energy Technology business, a long cycle equipment backlog insulated from any single quarter’s drilling decisions. This is the structural fact that explains almost everything else in this issue. Halliburton is, more purely than almost any other major services company this newsletter has profiled, a direct bet on how many wells the world decides to drill in any given ninety day window.

THE NUMBERS, INCLUDING THE QUARTER THAT NEARLY VANISHED

Full year 2025 revenue came to twenty two point two billion dollars, down from twenty two point nine billion in 2024, with operating income falling from three point eight billion dollars to two point three billion across the same period. Buried inside that full year figure sits a single quarter worth examining on its own, since the third quarter of 2025 produced net income of just eighteen million dollars, two cents a share, the closest this newsletter has found any major public oilfield company come to genuinely vanishing profitability in a single reporting period without posting an outright loss. Adjusted net income for that quarter, excluding impairments and other charges, came to four hundred ninety six million dollars, a meaningfully different number that shows how much of the headline collapse traced to one time charges rather than the underlying business itself, but the raw two cent figure is the one that reached headlines, and it is the number that best captures how thin the margin for error runs inside a pure services model exposed directly to a single quarter’s activity level.

The fourth quarter recovered sharply, net income of five hundred eighty nine million dollars, seventy cents a share, adjusted operating margin of fifteen percent, and the company closed the year having returned one point six billion dollars to shareholders, close to eighty five percent of full year free cash flow, through dividends and one billion dollars of share repurchases. The first quarter of 2026 continued that recovery, net income of four hundred sixty one million dollars, fifty five cents a share, more than double the two hundred four million dollars, twenty four cents a share, Halliburton reported in the first quarter of 2025. Revenue held flat at five point four billion dollars, but the composition underneath that flat number tells the real story. Completion and Production revenue fell three percent to three billion dollars, operating income down seventeen percent to four hundred thirty nine million, driven by lower North American stimulation activity and reduced pressure pumping and completion tool sales specifically in the Middle East. Drilling and Evaluation revenue rose four percent to two point four billion dollars on stronger Latin American project management work and increased European drilling services, even as Middle Eastern activity dragged the same segment down elsewhere. Chief executive Jeff Miller’s own framing of the quarter names both dynamics directly, telling investors he sees clear signs of an early recovery in North America while international performance outpaced disruptions from the Middle East conflict, an unusually candid acknowledgment that the war this newsletter has tracked since Issue Sixty Six registered as a direct drag on Halliburton’s own international segment.

THE WAR, MEASURED IN A SPECIFIC REGIONAL LINE ITEM

Halliburton’s own first quarter 2026 filing puts a number on the war’s impact that this newsletter has not been able to isolate this precisely for any other services company covered so far. Middle East and Asia revenue for the first quarter of 2026 came to one point three billion dollars, down thirteen percent year over year, a decline the company attributes specifically to lower activity across multiple product lines in Saudi Arabia and decreased drilling related services in Qatar. Both of Halliburton’s operating segments explicitly cite the geopolitical conflict in the Middle East as a negative factor in the same quarter, language distinct from the more general capital discipline explanation this newsletter used to describe Halliburton’s 2025 struggles in the earlier comparative issue against Baker Hughes. The war did not simply fail to help Halliburton the way it failed to meaningfully move Permian drilling activity. In the specific region where the war was actually happening, it directly reduced the volume of work international oil companies and national operators were willing to commission, a more direct and traceable form of damage than the general capital discipline story running through Halliburton’s North American numbers over the same period.

THE INDIA RELATIONSHIP, A MORE COMPLICATED STORY THAN IT FIRST APPEARS

Halliburton’s history in India runs back further than most of its current relationships, a five year memorandum of understanding signed with ONGC in 2005 covering broad services and support opportunities, described at the time by ONGC’s own chairman as providing easy access to Halliburton’s technology and management practices. That relationship deepened in December 2016, when Halliburton and Schlumberger separately signed statements of intention with ONGC to enhance production from mature fields, Halliburton taking on Kalol field in Gujarat under a fifteen year Production Enhancement Contract structured to pay Halliburton in dollars per incremental barrel produced above an agreed baseline, signed with sufficient ceremony that India’s oil minister and several other cabinet ministers attended the Petrotech conference where the agreement was formalized.

The story did not end cleanly. In July 2017, India’s oil ministry objected to both the Halliburton and Schlumberger agreements on the grounds that ONGC had awarded them on a nomination basis, without competitive bidding, and ONGC rescinded both pacts under that pressure. It is a genuinely useful data point sitting against Baker Hughes’ comparatively frictionless twenty year India narrative this newsletter documented in the previous issue, since it shows the same country’s procurement politics can derail a headline signing ceremony just as easily as it can sustain a two decade partnership, depending entirely on how carefully the underlying contract structure was built before the cameras arrived. Halliburton has continued operating in India in the years since, jointly winning a hundred twenty five million dollar logging, perforating, testing, and memory slickline services contract from ONGC’s Mumbai Regional Business Centre alongside Schlumberger, evidence the relationship survived the 2017 setback even if it never fully recovered the momentum that December 2016 signing ceremony implied.

WHETHER THIS BUSINESS SURVIVES ITS OWN INNOVATIONS

Halliburton’s own recent technology announcements read almost like a company documenting the slow automation of its own labor force in real time. The StreamStar wired drill pipe interface system delivers real time, high speed data and continuous downhole power specifically to enable faster automated decisions and what the company calls orchestrated closed loop automation, explicitly designed to minimize reliance on downhole generators and lithium batteries that previously required more manual intervention to manage. The Remote Operated Controls System, ROCS, replaces conventional hydraulic setups with an umbilical less control system that reduces surface pressure risk and, in the company’s own words, minimizes personnel exposure, having set a global benchmark installing a tubing hanger at eight thousand four hundred fifty eight feet, the deepest umbilical less operation on record. And the March 2026 Guyana well, drilled and geologically steered without direct human control at the moments that decision used to require, is not a research demonstration. It is a commercial well, drilled for ExxonMobil, using tools Halliburton intends to sell as a repeatable service rather than a one time showcase.

Each of these innovations makes Halliburton’s own services more valuable to a customer in the near term, faster wells, safer operations, fewer people needed on site. Each of them also reduces the labor intensity that has historically justified Halliburton’s headcount and, over a long enough horizon, its pricing power in a business built on selling expertise and manpower as much as equipment. Halliburton has answered this tension the same way Baker Hughes did, by reaching toward a long cycle, equipment driven business line that looks less like traditional oilfield services and more like power infrastructure. In the fourth quarter of 2025, Halliburton and VoltaGrid, a distributed power and energy solutions provider, signed a strategic collaboration to deliver distributed power generation for data centers globally, securing manufacturing capacity for four hundred megawatts of modular natural gas power systems for delivery in 2028, with an initial rollout targeted at the Middle East specifically. Four hundred megawatts is a genuinely small commitment next to the roughly one gigawatt Baker Hughes just secured from a single Kodiak Gas Services agreement, and it arrives years after Baker Hughes inherited its own power generation capability wholesale through the 2017 GE merger. Halliburton is chasing the same data center power opportunity its larger rival has already spent a decade building toward, starting from a smaller base, later, and without an equivalent acquisition like Chart Industries behind it yet.

THE POLITICS OF A COMPANY THAT PRODUCED A VICE PRESIDENT

No company this newsletter has covered carries a more direct pipeline between its own executive suite and the highest levels of American government than Halliburton’s own history with Dick Cheney, a chief executive who left the company in 2000 to become Vice President and spent the following eight years defending decisions, KBR’s Iraq contracts, the company’s sanctions adjacent Iranian subsidiary, foremost among them, that traced directly back to his own tenure running the company. That history sits in the background of every subsequent Halliburton controversy this newsletter has documented, a permanent reminder that the line between this specific company and American state power has, at least once, been as direct as one person walking from one office into the other.

More immediately, Halliburton absorbed the same tariff costs on imported steel and equipment this newsletter documented in the earlier comparative issue against Baker Hughes, an estimated two to three cents a share hit each quarter through 2025, concentrated in the completions and production business, before the Supreme Court’s February 2026 ruling struck down the underlying emergency powers tariff authority months later. The VoltaGrid data center push carries its own political dimension too, an initial rollout deliberately targeted at the Middle East, the exact region where Halliburton’s own first quarter 2026 results show the war has been actively suppressing traditional drilling activity, a company betting its next growth market on the same region currently punishing its existing one.

WHAT THE TAPE IS SAYING NOW

China exports deflation into whatever industry it decides to scale, and Halliburton’s core services business sits on the wrong side of that mechanism in a way Baker Hughes’ turbine business currently does not. Gas turbines are supply constrained worldwide, effectively sold out for years across every major manufacturer, giving Baker Hughes’ Industrial and Energy Technology segment genuine pricing power. Oilfield stimulation and completion services face the opposite condition entirely, a competitive field of established players, Halliburton, SLB, Weatherford, and others, all chasing the same finite pool of North American drilling activity, meaning any capacity glut in that specific market gets priced away almost immediately rather than sustained the way turbine scarcity has been. Halliburton’s third quarter 2025 collapse to two cents a share is what happens when a company sits fully exposed to a short cycle, competitively saturated services market at the exact moment that market’s underlying activity level drops, with no long cycle equipment backlog anywhere in the business to soften the landing.

STRESS TEST

North American shale activity remains the single largest variable Halliburton cannot control and has no meaningful hedge against, and the company’s own results show almost no room for a second demand shock, given how close the business already came to a lost quarter in the third quarter of 2025 alone.

The Middle East war’s direct suppression of Saudi and Qatari activity is a distinct and separately traceable risk from the general North American capital discipline story, and any escalation or prolongation of that conflict threatens further declines in a segment already down thirteen percent year over year.

Automation is a genuine long term threat to the labor intensive service model this company has run for over a century, and while StreamStar, ROCS, and the Guyana automated well all generate near term commercial value, none of them yet answer the harder question of what happens to Halliburton’s headcount and pricing power once fully automated wells become the industry norm rather than a headline making first.

The VoltaGrid data center bet remains small and early relative to Baker Hughes’ equivalent push, and Halliburton has not yet demonstrated it can scale a long cycle power business the way its larger rival did through a full decade of GE inherited infrastructure and, more recently, a thirteen point six billion dollar acquisition Halliburton has no equivalent counterpart to.

THE INSTITUTIONAL LABEL

Halliburton grinds. Thin margins, direct activity exposure, a business that lives or dies by how many wells North America and the Middle East decide to drill this quarter, with almost nowhere to hide when the answer is fewer, as the third quarter of 2025 proved in the starkest terms this newsletter has documented for any major company covered so far. The same company that once cemented its wells by hand from a wooden mixing box is now automating that same process into obsolescence, and the same innovations making Halliburton more valuable to its customers today are quietly eroding the labor intensive foundation the company has stood on for a hundred seven years, with no equivalent to Baker Hughes’ long cycle equipment business built large enough yet to catch the company if that foundation gives way.

SOURCES

Halliburton fourth quarter and full year 2025 results, Form 8-K, January 21 2026. Halliburton first quarter 2026 results, Form 8-K, April 21 2026, and Form 10-Q, first quarter 2026, SEC filings. Halliburton 2026 Proxy Statement, Form DEF 14A, March 31 2026. Britannica Money, Halliburton corporate history. HistoryOasis and HistoryTools, Halliburton CEO history, Erle Halliburton through Dick Cheney. Zippia and FundingUniverse, Halliburton founding timeline and milestones. Wikipedia and SourceWatch, Halliburton and KBR corporate history, including Iraq contracting and asbestos litigation. Business and Human Rights Resource Centre and Motley Rice, Halliburton Deepwater Horizon settlement coverage, 2014 through 2016. Oilit.com, Halliburton and ONGC memorandum of understanding, 2005. India.com and ONGC India, Kalol field Production Enhancement Contract signing and rescission, December 2016 and July 2017. PETROWATCH, Halliburton and Schlumberger joint ONGC Mumbai contract. Halliburton press releases and Form 8-K technology disclosures, VoltaGrid data center collaboration, StreamStar and ROCS technology, fourth quarter 2025 and first quarter 2026. Halliburton, ExxonMobil, and Wells Alliance Guyana joint announcement, automated well placement, March 16 2026.