Presuming the fragile truce holds, a new MoU will allow global energy companies to invest in reconstructing Iran’s vast, undamaged oil and gas reservoirs

WHAT: A diplomatic breakthrough is set to reopen the Iranian energy market after devastating infrastructure damage.

WHY: Iran requires $185bn in investment to rebuild facilities and boost production.

WHAT NEXT: Many of the most attractive projects are the same as those Western firms were circling around a decade ago.

For the better part of a decade, Iran has served as both the industry’s most tantalising prospect and its most consistent disappointment. That duality may finally be resolving itself – though not in the way anticipated in January 2016, when the Joint Comprehensive Plan of Action (JCPOA) lifted sanctions sent a wave of European and Asian executives scrambling toward Tehran.

The war that began on February 28, 2026, and the memorandum of understanding (MoU) signed last week in Switzerland, have reset the board. Providing that pressure by Israel to disrupt the fragile truce is unsuccessful and that a lasting solution is found, the key question for decision-makers will no longer be whether Iran reopens – it will be where to move first.

A decade in three acts

When JCPOA Implementation Day arrived in January 2016, a NewsBase Special Report captured the industry mood: Iran was “El Dorado” to most IOCs, a country whose energy sector combined 158bn barrels of proven oil reserves, 34 trillion cubic metres of gas, and more than a century of production history with a near-total absence of modern international investment.

Production had fallen from just over 4mn barrels per day in 2011 to 2.8mn bpd by late 2015, and the upstream bore the scars of a decade of technology starvation.

The brief JCPOA window of 2016-2018 saw ENI, Shell and Total (now TotalEnergies) move back toward Tehran. Iran’s new Integrated Petroleum Contract (IPC) was designed to fix the fundamental flaw of the old buyback model: IOCs would still not own reserves, but 20-25-year joint venture structures, continuous revenue participation, and full cost recovery made the framework far more competitive.

Then came the US withdrawal and maximum pressure sanctions in 2018, collapsing output to 2.1mn bpd by 2020. Act three saw Iran adapt – working through China and a shadow fleet, the National Iranian Oil Co. (NIOC) rebuilt exports to a record 1.8mn bpd by mid-2025, while OPEC placed national production at 3.308mn bpd, cementing Iran’s position as the group’s third-largest producer.

War and damage

The US-Israeli strikes of February 28 fundamentally altered Iran’s energy landscape. Within eight days, around 20% of the world’s combined crude oil and natural gas supply had been disrupted as Iranian forces targeted tankers and energy infrastructure across the Strait of Hormuz. Oil prices breached $90 per barrel; Saudi Aramco’s Ras Tanura terminal was shut down; and Goldman Sachs warned of $100 per barrel of oil if Hormuz disruptions persisted.

On the Iranian side, the damage was acute but concentrated. Output that had been running at around 3.59mn bpd in February 2026 fell to 2.33mn bpd by May – a loss of roughly 1.26mn bpd in under three months.

The Asaluyeh gas processing hub took direct hits, disrupting onshore facilities serving South Pars; by late May, production from three offshore South Pars platforms had been rerouted to alternative processing sites while repairs proceeded onshore. Vitol CEO Russell Hardy estimated cumulative lost production could reach 1bn barrels by the conflict’s end. Critically, the wells and subsurface assets – the long-term value – remained largely intact.

MoU outlook

The MoU signed last week represents a structural break. The US will grant an immediate temporary oil sanctions waiver, enabling Iran to sell crude and receive funds, with banking, shipping and insurance waivers accompanying crude export relief.

The Strait of Hormuz will reopen for an initial 60-day period with longer-term management to be negotiated between Iran and Oman. All US and UN sanctions are to be lifted on a mutually agreed timeline once a comprehensive final agreement is concluded, covering nuclear enrichment limits and regional proxy groups; $25bn of frozen assets will be released.

Oil markets responded immediately – Brent crude fell over 4% on the deal announcement, settling around $83-84 per barrel from peaks near $106. S&P Global noted that supply losses are expected to exceed 1.5bn barrels by the end of June, with full Hormuz normalisation likely extending into 2027. That supply deficit creates the same structural demand for Iranian barrels that existed after 2015 – compressed into a tighter timeframe and against a backdrop of already-strained global upstream investment.

Investment landscape

Iran still holds 157-158bn barrels of proven crude oil reserves – the world’s fourth-largest endowment – alongside the second-largest gas reserves globally, with only around 10% of national territory yet explored. The production cost advantage is formidable: at around $9 per barrel for some onshore production, Iran competes directly with Saudi Arabia.

The IPC framework, finalised during the first JCPOA era, remains the ready-made template – 20-25-year JV partnerships with NIOC, risk-adjusted compensation per barrel, full cost recovery, and a 51% local content requirement to drive technology transfer.

Iran’s own estimates suggest the oil and gas sector requires $185bn in investment over the next five years, following earlier projections of $150bn needed by 2019 that were never fulfilled. With reconstruction funding now part of the MoU framework and Washington committing to a development plan within 60 days of signing, the table is set – but the seats will fill quickly.

The crown jewels

South Pars (Phases 11-24) remains the single most strategically important project in Iran’s portfolio. The 9.2 trillion-cubic-metre field accounts for roughly 60% of Iranian gas production. Phase 11, originally cancelled by NIOC after persistent CNPC delays in 2013, is among the most accessible opportunities for a returning IOC.

Total had signed a $4.8bn agreement to develop Phase 11 before the 2018 US withdrawal forced its exit – that is now re-contestable. Production from three offshore platforms was already being restored as recently as May 2026, demonstrating reservoir and infrastructure resilience.

Azadegan oilfield – split into North and South sites across 900 square km southeast of Ahvaz – holds total estimated reserves of 42bn barrels of crude, of which around 7bn are deemed recoverable. Phase one targets 320,000 bpd; full development across both phases points toward 600,000 bpd. The China National Petroleum Corp. (CNPC) holds incumbent positions in both sites but has experienced persistent contractual friction with Tehran, including the cancellation of South Azadegan in 2014 over project delays. A returning European or Asian major could negotiate fresh IPC terms from a position of strength here.

Yadavaran, in southwestern Khuzestan, had its estimated capacity doubled to 34bn barrels following exploration during the sanctions era, with three development phases targeting a combined 300,000 bpd of output. Phase one has been producing around 85,000 bpd; the incremental capital required to move through phases two and three is relatively modest against the scale of the prize.

Underpriced midstream

Iran LNG – stalled at around 60% completion for well over a decade – represents one of the most asymmetric risk-reward propositions in the global energy sector. The facility, located at Asaluyeh adjacent to South Pars, was designed to produce 10.8mn tonnes per year of LNG.

With the LNG market structurally tightened by the European post-Russia pivot, the strategic case for completing this facility has arguably never been stronger. The capital required to finish what already exists is a fraction of a greenfield equivalent, and the feedstock – South Pars gas – is captive and abundant.

The Jask, Lavan, Sirri and Qeshm oil terminals, funded originally by Russian capital to diversify exports away from the Kharg Island terminal (which handles more than 90% of Iran’s crude exports), are now a near-mandatory infrastructure priority rather than an optional strategic upgrade. The war demonstrated precisely why single-point export concentration is a vulnerability no sovereign producer can afford. Services companies and midstream specialists with marine terminal expertise are particularly well positioned here.

IGAT-9, the pipeline running from Khuzestan through northern Iraq, Azerbaijan and on to Turkey with extensions planned to Greece and Italy, remains the most ambitious gas export vision in the region. Gazprom and LUKoil had previously committed to the international component; post-MoU, European utilities desperate for post-Russia supply diversification should be revisiting this route with urgency. Given Azerbaijan’s challenges securing European commitment to gas that would enable the expansion of its own pipeline capacity, the optionality and structure of LNG may see Iran LNG take priority.

Downstream reconstruction

The Abadan refinery, capable of 635,000 bpd before its partial destruction in the 1980 Iraqi invasion and currently running around 429,000 bpd, has been a target for Chinese investment since 2015 – upgrading to Euro-V fuel standards, adding a 210,000 bpd processing unit, and expanding diesel and gasoline capacity.

European and Asian services companies with refinery engineering capabilities face a straightforward entry point here with a well-documented scope of work already on record.

Strategic warning

One number captures the irreducible uncertainty: the MoU’s 60-day Hormuz management clause, the ongoing nuclear negotiating window, and the snapback mechanism that France, Germany and the UK had already triggered in August 2025 leave a credible tail risk that no investment committee can honestly dismiss.

Iran has managed this precise cycle – sanctions, partial relief, renegotiation, renewed pressure – for nearly two decades.

The companies that progressed furthest during the 2016 window were those that planned for a cycle, not a permanent opening. They moved fast on asset-light positions – services agreements, JV option structures, engineering and procurement contracts – that could be suspended and reactivated without permanent capital destruction. The same template applies now, with one modification: the infrastructure damage from the 2026 conflict means reconstruction opportunities may become available quickly. For energy companies with the risk appetite to move, that window appears to be opening.