Company history

INPEX's older half was created by statute. In September 1941, under the Teikoku Oil Company Act, the government and private industry each put up half of ¥100 million to found Teikoku Oil — a national-policy company built on a small exploration venture set up the year before by Nippon Oil, Nippon Mining and five others. Its purpose was to break Japan's dependence on foreign oil, and it did so by consolidation rather than discovery: in 1942 the oil-mining divisions of four companies were folded in at the government's urging, and wartime mergers through 1945 left Teikoku Oil holding most of the domestic fields. In return for a guaranteed 4% dividend, guaranteed bond payments and ten years' tax exemption, it accepted state supervision of its business. The guarantees ended with the 1946 law restricting government financial aid, and in June 1950, its founding statute repealed, Teikoku Oil re-emerged as an ordinary commercial company.

What it inherited was a business with a hard ceiling. Output bottomed at some 165,000 kilolitres in fiscal 1948, then recovered to a record 353,000 by fiscal 1951 as new pay zones were found at the Yabase field in Akita; Teikoku Oil produced over 97% of Japan's domestic crude and sold nearly all of it to three refiners on the Japan Sea coast. But the price collapsed underneath it — ¥10,091 per kilolitre in 1951 fell to ¥6,615 by 1970, about a third gone in twenty years — while headcount dropped from roughly 6,200 to 2,030 and the payroll rose from ¥1.45 billion to ¥3.48 billion, a 7.3-fold increase per head. Cash ran out in February 1964; a vice-president seconded from Nippon Mining took the presidency, and with banks unwilling, the company financed itself by pushing natural gas at Kubiki in Niigata, whose quick receipts turned over faster than oil.

The other half of the future company began in 1966, when the government set up North Sumatra Offshore Petroleum Development — later Inpex — with the state petroleum corporation taking a majority and public money carrying the exploration risk. Japanese firms had gone abroad only in the 1960s and were outmatched by the majors on negotiating power, concessions, capital and technology alike: of more than sixty producing overseas projects with Japanese participation, fewer than ten were operated by a Japanese company, and Inpex's own operatorships came to two small blocks in Egypt and Venezuela. Teikoku Oil's ventures fared no better — three wells drilled off Tawau in Sabah in 1970 found oil-bearing beds but nothing commercial. Exploration was assumed to fail: roughly eight in ten test wells came up dry, and ¥1.6–1.7 billion was written off every year as a matter of course.

Inpex built its position in Indonesia, and mostly as a passenger. By 2005 it held nineteen blocks — ten in Indonesia, nine in Australia — but the important ones were minority participations in ventures run by others: 50% of the Mahakam offshore and Attaka fields alongside Total and Unocal, 35% of South Natuna Sea B, 16.3% of Tangguh. The state petroleum corporation that funded it had spread its money across refiners, explorers and trading houses and dissipated its resources in the process; Inpex was one of its few clear successes, and after the corporation was wound up the government treated Inpex and Teikoku Oil as the two flagships of Japanese upstream. Inpex listed its shares in 2004 as part of that disposal, with the state retaining 29%. One asset stood apart from the pattern: the Masela block in eastern Indonesia, held 100%, which would later become Abadi.

Becoming an operator rather than an investor was a deliberate, expensive project. Inpex spent heavily on three Indonesian blocks in the 1980s and found nothing worth developing, then widened its search to Australia's North West Shelf from 1986. In 1998 it took WA-285-P — 600 square kilometres off Western Australia — outright, at 100%. Drilling from 2000 confirmed gas, and three rounds of exploration over eight years mapped the field, named Ichthys in 2002: about 13 trillion cubic feet of gas and more than 500 million barrels of condensate, roughly 1.2 billion barrels of oil equivalent. On its own it would multiply the company's equity production 1.7-fold. It was also unaffordable and beyond its competence — liquefaction alone would cost at least ¥600 billion, LNG needed long-term buyers signed before a spade went in the ground, and the work ran from offshore processing and a floating storage vessel to a subsea pipeline and an onshore plant.

Meanwhile the state pushed Inpex toward a different prize. After Prime Minister Mori's 2000 meeting with President Khatami, Japan won priority negotiating rights over Iran's Azadegan field — an estimated 26 billion barrels, in the class of Saudi Arabia's Ghawar — and the trade ministry, having just lost the Khafji concession, pressed hard. Inpex signed in February 2004 for about $2 billion with Japan carrying 75%. The terms were thin: a buyback contract under which the crude stayed Iranian and Japan recovered costs plus a set margin over six and a half years, on heavy oil, in old Iran–Iraq war minefields, on a project Shell had already walked away from. On 5 November 2005, Inpex and Teikoku Oil announced they would combine under a joint holding company — 1.805 billion barrels of proved reserves between them, more than Unocal — despite a market-capitalisation gap of more than four to one.

Inpex Holdings was created by joint share transfer in April 2006 with ¥30 billion of capital and listed on the first section of the Tokyo Stock Exchange. The trade minister took a single golden share carrying a veto, and the state still held about 19% of the equity a decade later; the chairman and president both came from the old MITI. In its first year the group turned over ¥969.7 billion with ordinary profit of ¥586.3 billion — no comparable Japanese upstream company existed. The arithmetic of the merger was contested: Nippon Oil, Teikoku's largest shareholder, called the exchange ratio unfair, bought its stake above 20%, and said publicly that Inpex looked overvalued. In October 2008 the holding company absorbed both subsidiaries and took the name Inpex Corporation. By then Azadegan was gone — US pressure over Iran's nuclear programme led Inpex to cut its 75% interest to 10% in October 2006, and the Japanese government quietly withdrew its financing and guarantees. The 260,000 barrels a day it was to have supplied, some 6% of Japan's crude imports, never arrived.

Everything then went into Ichthys, and the company bought in what it lacked. It sold 24% of the field to Total in 2006 for its LNG experience, took in around twenty of its senior engineers, and staffed a 300-person Perth office with Australian, European and American hands, designing every facility around proven technology to avoid surprises. The money was raised in layers: about $5.9B (¥520bn) of new equity in August 2010, $20 billion of project finance in August 2012, and retained earnings — because operating cash flow of some ¥200 billion a year could not cover ¥300 billion of annual investment. In December 2012 the board took final investment decision on a $34 billion project, more than the company's entire equity. Interest-bearing debt went from ¥273.1 billion in the year to March 2011 to ¥1,141.2 billion by March 2019.

The build was worse than planned. Up to 30,000 workers were on site as Australia's resource boom drained the labour market, wet-season rain caught the pipework, and start-up slipped about eighteen months past its end-2016 target while costs swelled by nearly ¥700 billion to $40 billion — just as oil fell from $100 a barrel to under $50, in a business where every dollar of average price was worth ¥2.5 billion of consolidated profit. Group revenue shrank 24% in two years and net profit fell from ¥183.6 billion to ¥16.7 billion. In the middle of that, in April 2015, Inpex secured 5% of Abu Dhabi's onshore ADCO concession for forty years, 2015 to 2054 — an unusual term, won after Total took its 10% and Japan, China and Korea fought over the remainder, settled by a call between Prime Minister Abe and the crown prince. Ichthys finally started up in July 2018, twenty years after the block was acquired: 8.9 million tonnes of LNG a year, roughly 70% contracted to Japanese buyers for two decades, and membership of the ten-odd companies worldwide able to operate a project of that size.

The structural weakness showed up the moment prices broke. In the year to December 2020 the group posted a net loss of $1.0B (¥112bn) — its first since the merger — on an average price of about $43 a barrel, after ¥189.9 billion of impairments including the Prelude floating LNG project; revenue fell 23% to ¥771.0 billion. In April 2021 the company renamed itself INPEX, and president Ueda Takayuki accepted the criticism directly: this was, he agreed, an Ichthys one-legged business, and an accident at that one plant would show up in the profit line. The answer he set out was to use the cash from oil and gas to build something else — blue hydrogen from the Minami-Nagaoka gas field with the CO₂ injected into another field nearby, and ammonia made from Abu Dhabi gas and shipped to Japan.

The upcycle that followed gave him the means. Revenue reached ¥2,316.1 billion in the year to December 2022 with ¥461.1 billion of profit, both records, as Middle East and Africa revenue doubled. Shareholder returns rose 4.6-fold in two years to ¥201.6 billion, with buybacks becoming an annual fixture. But foreign investors — about 30% of the register, down from over 45% in 2018 — pressed for more, and INPEX answered with a discipline unusual for a Japanese resource company: ROIC measured against a roughly 6% cost of capital rather than ROE, a progressive dividend adopted in February 2025 that will not fall with the oil price, and a 2025–27 plan promising over ¥400 billion of returns alongside ¥1.8 trillion of investment.

The second leg is still being built. Abadi, the wholly-owned Masela field, was derailed in 2016 when Indonesia rejected floating liquefaction and demanded an onshore plant for the jobs it would bring to the country's east; replanned at 9.5 million tonnes a year and some ¥3 trillion, it lost Shell's 35% in 2023 to Pertamina and Petronas, leaving INPEX with 65%, carbon capture designed in from the start, and first production around 2030. The 2022 long-term vision committed the company to net zero by 2050 with gas as the transition fuel and CCS, hydrogen and renewables beside it; INPEX Vision 2035, published in February 2025, put ¥1.8 trillion of growth investment behind five business areas and targeted ROE above 10%. Overseas assets now generate roughly nine-tenths of segment revenue — the international company the state set out to build in 1966, still looking for the thing that comes after oil.