Lebanon’s plan to import natural gas raises questions that extend beyond the project’s cost and investment returns. While state-owned Electricité du Liban (EDL) struggles to secure enough gas oil to operate its power plants at available capacity, the new plan assumes it will be able to purchase natural gas regularly and guarantee payments to investors operating the new infrastructure. If foreign currency shortages are preventing EDL from increasing electricity production today, where will the dollars come from to secure gas purchases tomorrow? And will natural gas’s lower cost compared with gas oil be enough to solve the problem? A second question concerns the economics of building a floating liquefied natural gas (LNG) import and regasification terminal at an estimated investment cost of $130 million, while the Energy Ministry works to rehabilitate Lebanon’s section of the Arab Gas Pipeline, which could bring gas through Jordan and Syria. Jordan has already agreed to supply Lebanon using its existing regasification terminal in Aqaba. Why then is the state investing in new import capacity while restoring infrastructure that could serve the same purpose? Were the alternatives and their costs adequately assessed before the investment decision? The studies estimate that replacing gas oil with natural gas at the existing Deir Ammar plant would save around $27 million annually during the first two years. A $614 million project On October 1, the Cabinet approved a public-private partnership to build a floating storage and regasification unit (FSRU) in Deir Ammar. The approval followed the Higher Council for Privatization and Public-Private Partnerships’ endorsement of financial, technical, legal and environmental studies prepared by the International Finance Corporation (IFC) and other advisers. According to a project committee report dated September 1, 2026, and approved by the council on September 18, estimated capital expenditure stands at $614 million, divided into two components. The first, costing $130 million, covers the lease and operation of a floating LNG storage and regasification vessel, a connecting platform and a subsea pipeline running to shore from a site about five kilometers north of Tripoli port. The second, costing $484 million, involves building a new 436-megawatt combined-cycle gas-fired power plant in Deir Ammar. The components will be implemented under separate public-private partnership contracts lasting up to 20 years. The report proposes financing 75% of the investment through debt and 25% through equity, with a targeted internal rate of return on equity of about 18%. The studies estimate that replacing gas oil with natural gas at the existing Deir Ammar plant would save around $27 million annually during the first two years. Savings would rise to $206 million in 2033, when the new plant is expected to enter service, and reach $370 million by 2049. Longer supply hours require additional fuel purchases and cash flows that current collections may not cover. Funding still questionable These projected savings depend on two conditions. EDL must be able to purchase sufficient quantities of gas, and the total cost of importing it and converting it into electricity must genuinely be lower than the alternatives. Under the proposed arrangement, EDL would be the sole buyer of gas and electricity from the project companies. It would provide natural gas to the new plant free of charge and bear the risk of fuel shortages. The private plant operator would be responsible for converting gas into electricity efficiently and maintaining the equipment under a tolling agreement. It would not be responsible for securing gas from international markets or absorbing price fluctuations. The published summary does not clarify who would sign contracts to buy LNG from foreign suppliers or how supply risks would be divided between the terminal operator and EDL. The more fundamental issue is EDL’s ability to pay. Since direct government financing for fuel purchases ended, the utility has relied on its own revenues to secure supplies. Its updated cost-recovery plan, issued in December 2025, likewise assumes operating expenses will be covered by the utility’s income. Yet its finances remain strained. On August 14, EDL reported that international gas oil prices had approached $1,500 per ton, compared with the $680 per ton assumed in its 2026 budget. It attributed its difficulties to rising fuel prices, lower bill collection in several areas and mounting arrears owed by public administrations and institutions. The utility even threatened to cut electricity to public bodies that failed to pay their bills. This explains why EDL cannot increase generation simply because it has the technical capacity to do so. Longer supply hours require additional fuel purchases and cash flows that current collections may not cover. Natural gas could lower production costs and allow EDL to generate more electricity with the same funds. But that prospect must be demonstrated financially, particularly if gas contracts require minimum purchases regardless of actual demand. The studies also assume EDL can meet its payment obligations and propose an extensive guarantee structure, including revolving letters of credit covering six to 12 months of payments, World Bank guarantees and a sovereign guarantee from the Finance Ministry for certain contractual compensation payments. These provisions highlight the assumptions underlying the projected savings, particularly EDL’s ability to finance gas purchases and maintain regular generation and revenue collection. The estimated $27 million in annual savings during the initial phase cannot be treated as a net gain until it is clear whether the figure includes all regasification, transport and financing costs or merely reflects the price difference between natural gas and gas oil. That distinction is essential to determining the project’s actual benefit to EDL. The Arab Gas Pipeline option has gained importance because rehabilitation work inside Lebanon is already under way. A regasification terminal or a pipeline The second issue concerns the source of the gas and the route it will take to Deir Ammar. On September 6, 2026, Jordan’s Cabinet approved arrangements to supply natural gas to Lebanon through Syria. Under the plan, Jordan would import LNG from international markets, regasify it at the existing floating terminal in Aqaba, then pump it through pipelines across Jordan and Syria into Lebanon. The comparison is therefore not necessarily between Egyptian pipeline gas and LNG delivered by ship. The gas Jordan intends to supply is also imported LNG, but it would be regasified at an existing facility rather than at a new terminal off the Lebanese coast. Lebanon effectively has two options for securing the same commodity, either import LNG by sea and build domestic regasification capacity, or use Aqaba’s existing facility and pay regasification, transport and transit fees through Jordan and Syria. The Arab Gas Pipeline option has gained importance because rehabilitation work inside Lebanon is already under way. On June 15, 2026, a $748,100 contract was signed with TGS to rehabilitate the section running from Aboudieh to the Deir Ammar plant, with the specified works due to be completed within three months. On September 17, Energy Minister Joe Saddi announced a Qatari grant to complete maintenance on the Lebanese section. On September 21, Jordan’s Energy Ministry said the contractual supply volume for Lebanon was estimated at around two million cubic meters of gas per day. Deliveries had not yet begun, and final volumes would depend on the readiness of Lebanon’s infrastructure. At that volume, even a small difference in the delivered gas price could have a substantial impact. Importing two million cubic meters daily throughout the year would mean an additional cost of about $26 million annually for every $1 increase per million British thermal units, based on natural gas’s average energy content. That is roughly equivalent to the projected annual savings from providing the existing Deir Ammar plant with gas during the first two years. Comparing pipeline rehabilitation costs with the $130 million price tag of a new terminal is therefore insufficient. Lebanon needs to calculate the final cost of each million British thermal units delivered to Deir Ammar under both options, including the global gas price, regasification fees, transport, operations and maintenance, financing costs and any fixed payments. This does not necessarily mean pipeline imports would always be cheaper. The route could face capacity constraints, high transit fees or supply disruptions through Syria. A Lebanese terminal could also enable larger future imports and diversify supply routes. But these considerations must be quantified to establish how much Lebanon would pay for greater control over its import route. Timing raises another question. The existing Deir Ammar plant needs gas now to lower generation costs, while the new plant is not expected to enter service until 2033. If the Arab Gas Pipeline can supply the existing plant years earlier, why not separate the decision to provide it with gas from the decision to build a new regasification terminal? And will the pipeline have enough capacity to supply both plants eventually, or is the need for additional volumes what justifies the offshore investment? This is an edited translation for an article published in Arabic.
