Egypt and Eastern Mediterranean Gas: From Exporter to Importer

Zohr decline and the collapse of Egypt's export model #

Zohr came online in December 2017 and was hailed as the largest gas discovery in Mediterranean history at roughly 30 trillion cubic feet of original gas in place. Production ramped to a plateau of roughly 75 bcm per year by 2019, and on the back of that volume Egypt restarted both Idku and Damietta LNG, signed transit deals with Jordan, and rebranded as the Eastern Mediterranean's gas hub. The model assumed Zohr would hold plateau through the mid-2020s while Noor, Atoll, and the Nooros complex carried incremental load.

The reservoir did not cooperate. Water breakthrough at several Zohr wells appeared earlier than the Eni development plan assumed, and pressure declined faster than the carbonate model predicted. Output fell to roughly 60 bcm in 2023 and to about 50 bcm in 2025 according to EGAS production filings cross-referenced with Eni operational disclosures. Independent reservoir engineers now expect Zohr to settle in a 35 to 45 bcm band through 2028 unless a deeper compression and infill drilling programme, currently held up by EGAS arrears to Eni, is funded and executed on schedule.

The decline matters because Egypt's domestic demand grew through the same period. Power sector gas burn rose with cooling load, fertilizer producers expanded, and population added roughly 1.5 million people per year. By summer 2024 the gap between domestic demand and indigenous supply was wide enough that Egypt had to choose between running its LNG export trains and keeping its grid stable. It chose the grid.

Idku and Damietta off lights, FSRUs on charter #

Idku, operated by a Shell-led venture, and Damietta, operated by SEGAS with Eni and EGAS as partners, sent their last meaningful export cargoes in mid-2024. Both plants have continued to receive maintenance crews and skeleton operating staff, but feed gas has been rerouted to domestic dispatch. Petroleum and Mineral Resources Ministry filings put combined LNG export volumes for fiscal 2024 to 2025 at less than 1 bcm, against a nameplate liquefaction capacity of roughly 17 bcm per year across the two sites.

To replace the lost domestic supply, EGAS chartered the Hoegh Galleon FSRU and stationed it at Ain Sokhna in mid-2024 with a regasification capacity of roughly 5.4 bcm per year. A second FSRU lease was signed later that year to lift total regas import capacity above 10 bcm per year. Cargoes have been sourced from spot markets and from a tolling-style arrangement that lets Egypt swap pipeline gas received from Israel for LNG cargoes lifted at Idku when arbitrage windows open.

The economics are punishing. Egypt is buying LNG at TTF-linked prices that ran in a 12 to 14 dollar per mmBtu band through most of 2025, while domestic gas tariffs to power and industry are administratively set well below import parity. The fiscal cost of the fuel subsidy has tracked above 6 billion dollars per year on IMF estimates, which is why the Article IV programme treats gas pricing reform as a central conditionality.

Israeli supply: Leviathan, Tamar, and the EMG pipeline #

Israeli gas has become the swing supply that keeps Egypt's grid running. The Leviathan field, operated by NewMed Energy with Chevron and Ratio as partners, holds roughly 22 trillion cubic feet of recoverable gas. Under the long-term export contract signed in 2018 and amended in 2023 to lift volumes, Leviathan delivers up to 12 bcm per year to Egyptian buyers, primarily Dolphinus Holdings, via the reversed EMG pipeline that runs from Ashkelon to El Arish. Tamar, operated by Chevron with Isramco and Tamar Petroleum as partners, supplies an additional volume that has run between 5 and 7 bcm per year through the same EMG route plus a smaller flow via the Arab Gas Pipeline through Jordan.

Leviathan phase 1B, which adds a third subsea production line and incremental topsides capacity at the Leviathan platform, is on track for first gas in late 2026 and lifts platform capacity from roughly 12 bcm to about 21 bcm per year. Tamar phase 2 expansion, sanctioned in 2023, lifts that field from roughly 11 bcm to about 16 bcm per year through additional wells and a new compression train onshore at Ashdod, with completion expected in 2026 and 2027. The Israeli Energy Ministry has indicated that incremental volumes will be split between domestic demand, expanded Egyptian export, and possible Cypriot routing. The table below sets out the production trajectory of the four largest Eastern Mediterranean upstream sources and the trade flows that now define the regional balance.

Pipeline routes and the EMG architecture #

The pipeline architecture that moves Israeli gas into Egypt has been reinforced through three rounds of capacity additions. The Eastern Mediterranean Gas pipeline, originally built to send Egyptian gas to Israel and reversed after the 2017 Dolphinus contract, runs from Ashkelon to El Arish with nameplate capacity now debottlenecked to roughly 9 bcm per year. The Nitzana interconnect added in 2023 provides a second crossing into Sinai and reduces single-point failure risk that became acute during the October 2023 conflict shutdowns of Tamar. A parallel route runs through the Arab Gas Pipeline, reversed in segments since 2020, which carries roughly 6 bcm per year of Israeli gas south to Jordanian power plants with a smaller spur east to West Bank distribution.

Egypt and Israel signed a memorandum in early 2025 that lifts the headline export ceiling on Israeli gas to Egypt and explicitly allows tolling of Israeli volumes through Idku for re-export as LNG. This is the most likely pathway by which any Mediterranean LNG returns to European markets through 2027, and it shifts a share of Egypt's LNG export economics from upstream resource rent to liquefaction tolling fees, which carries different fiscal and contractual implications than the prior export model.

Cyprus, Lebanon, and the contested eastern basin #

Cyprus is the second-tier story that determines whether the basin produces enough gas to refill Idku and Damietta after 2028. The Aphrodite block, discovered in 2011 and stalled for more than a decade over commercial terms, was relicensed in 2024 to a consortium of Chevron as operator, NewMed Energy, and Shell. The revised development plan routes Aphrodite gas via subsea pipeline to Egypt for liquefaction at Idku rather than building a stand-alone Cypriot LNG facility, which had been the prior concept under the abandoned 2019 plan. Final investment decision is targeted for late 2026 with first gas in 2028. Calypso and Cronos, operated by Eni with TotalEnergies, sit adjacent and would likely follow the same Egypt-routed liquefaction pathway if appraisal confirms commercial volumes.

Lebanon's southern blocks remain in stasis. The October 2022 maritime border agreement with Israel, brokered by the United States, transferred the Karish field firmly to Israeli waters and gave Lebanon clean title to the Qana prospect in Block 9. Drilling at Qana by a TotalEnergies-led consortium yielded non-commercial results in 2023, and exploration in adjacent blocks has been delayed by political instability and security risk through 2024 and 2025. Lebanon will not contribute meaningful supply to the regional balance through 2028 and probably not through 2030.

Turkey and the Turkish Cypriot maritime claims continue to overhang Cyprus exploration. The 2019 Turkey and Libya maritime memorandum claimed waters that overlap with Cyprus, Greece, and Egypt's declared exclusive economic zones, and Turkish naval activity periodically interrupts seismic and drilling campaigns. The East Mediterranean Gas Forum, headquartered in Cairo with Egypt, Israel, Cyprus, Greece, Italy, Jordan, the Palestinian Authority, and France as members, has institutionalized coordination among the producing states but has no enforcement role against Turkish claims.

EU integration, REPowerEU, and the EastMed pipeline aftermath #

REPowerEU committed Europe to displacing Russian gas with a combination of LNG, renewables, and pipeline diversification. Eastern Mediterranean supply was always a marginal contributor to that volume, but the 2022 collapse of Russian flows raised European interest in any incremental molecule. The EastMed pipeline, a 1,900 kilometre subsea line that would have connected Israeli and Cypriot fields directly to Greece and Italy, was formally deprioritized in 2022 after the United States withdrew political support, citing both commercial and decarbonization concerns. The cancellation pushed all incremental Mediterranean LNG ambitions back through the Egyptian liquefaction trains.

The practical EU integration pathway runs Aphrodite and incremental Israeli gas to Idku, then European-bound LNG cargoes lifted at Idku and Damietta. This concentrates European supply security on the operational uptime of two Egyptian liquefaction sites and on Cairo's willingness to release export volumes when domestic load competes for the same molecule. The 2024 and 2025 export collapse demonstrated how thin that margin can become. An alternative routing through a second EMG-style spur into Greece via Crete has been studied informally by EMGF members but lacks sponsors or financing, while hydrogen and ammonia export from Egypt's Suez Canal Economic Zone remains years from final investment decision.

What 2026 to 2028 looks like and the three decisions that matter #

The base case for 2026 is uncomfortable but stable. Zohr settles in the low 40s bcm per year, Leviathan and Tamar lift combined deliveries to Egypt toward 18 to 20 bcm per year as their phase expansions ramp, Egypt imports 7 to 8 bcm of LNG via the two FSRUs at Ain Sokhna, and Idku and Damietta operate at very low utilization with only opportunistic export cargoes. Power sector load shedding through summer 2026 is likely but should be less acute than in 2024 if Israeli volumes ramp on schedule and if the IMF programme keeps fuel imports financeable.

Three decisions determine whether this picture improves by 2028 or deteriorates. First, the Aphrodite final investment decision in late 2026 sets whether Cypriot gas refills Idku in 2028 and beyond. Without it, Egypt's LNG export trains face the prospect of being decommissioned or repurposed as floating storage. Second, the EGAS arrears to international operators, which ran above 6 billion dollars through 2024 according to S&P Platts reporting, must be cleared on a credible schedule for Eni, Chevron, and Shell to fund the next round of incremental drilling. The Article IV programme links arrears clearance to gas tariff reform, which is politically toxic but fiscally unavoidable. Third, the Tamar phase 2 and Leviathan phase 1B commissioning windows in 2026 and 2027 must hold. Any slippage of more than two quarters cascades into Egypt's summer 2027 dispatch and forces additional FSRU charters at peak spot LNG prices.

The strategic conclusion is that the Eastern Mediterranean gas story has flipped from an export growth narrative to a regional supply integration narrative. Egypt is the system operator of last resort. Israel is the swing producer. Cyprus is the option value. The European pull is real but conditional on Egyptian willingness to release export volumes when domestic politics tighten. The EastMed pipeline cancellation removed the bypass option, so the basin's commercial logic now runs through Cairo or it does not run at all.

Sources #

• Statistical Review of World Energy 2025
• Gas Market Report Q1 2026 and Egypt country profile
• EGAS production and trade statistics, fiscal year 2024 to 2025
• Natural Gas Supply Status and Leviathan and Tamar export approvals
• Aphrodite block development plan revision and Cyprus exploration update
• EMGF Ministerial Communique and 2025 Annual Coordination Report
• Egypt LNG export tracker, EGAS arrears and FSRU charter coverage
• Eastern Mediterranean gas flows and EMG pipeline capacity assessment
• Arab Republic of Egypt: 2025 Article IV Consultation and Extended Fund Facility Review
• Egypt FSRU arrivals, Hoegh Galleon and Israel pipeline export coverage