Potential Revenues of the Lebanese Offshore Gas Discoveries

In 2017 Lebanon awarded two of its offshore blocks (4 and 9) to a consortium composed from Total, ENI, and Novatek.

In the country’s first signed Exploration and Production Agreements (EPA) Royalties were Not biddable. They equal 4% of the gas produced, and a varying percentage (between 5% and 12%) of the oil produced.

  • Profit split Biddable within R factor.
  • The minimum share of the State starts at 30% and then rises to a maximum of 55% (Block 4) and 40% Block 9 when the R Factor (the total of all income in the project over all outgoing payments) reaches 2.5.
  • Corporate Income Tax: 20%.
  • Cost Recovery Limits Biddable, ceiling is 60% in Block 4 and 65% in Block 9.
  • To mention unlimited carry forward losses, and stability clause are part of the contract, withholding tax on interests, taxed at a rate of 10%.

The model to the report published by the Lebanese Oil and Gas Initiative (LOGI) in mid-2020 is a static, deterministic Discounted Cash Flow model that follows the FAST methodology. The provenance of all inputs and assumptions which have been taken from primary sources. Lebanon published the two production signed agreements it signed with the consortium led by Total, so the full text has been available for fiscal interpretation. Data for project economics, such as capital and operating expenditure, is more speculative in two senses. First, there are almost no data about Lebanon’s offshore, since only one well has been drilled and no commercial discoveries developed. This means, from a modelling perspective, that the public statements of the companies have to be parsed for general indications, and projections made using generic industry approaches and projections.

Second, any production lies several years in the future in a market which, even without the extraordinary turbulence of early 2020, is always marked by volatility. So even if project-level data and estimates were available in public domain, they would almost certainly have changed significantly, in some way, by the time a field was developed and went into production. Results from the model should therefore be considered indicative rather than predictive. Nevertheless, sensitivity analysis within the model allows us to determine that broad conclusions of this report are somewhat robust to changing parameters.

Base Scenario Economic Assumptions in the model Exploration $60 million assumed as cost of one well to meet exploration obligations, and form based of exploration economics calculations; developed field exploration $200 million pre-Final Investment Decision Development Costs Pipeline-led development $4 billion; FLNG: $1,440 per tonne of LNG pa Operating Costs Pipeline development: $0.50 per MMscf; LNG development $40 per tonne of LNG Operational Parameters Exploration three years; Conventional Pipeline development five years; LNG development four years. Price $6 per mmBTU for base scenario, set as constant in 2020 real terms – user adjustable parameter

Base Scenario Economic Assumptions in the model Finance 2% inflation rate to convert real to nominal; 10% nominal discount rate for government take calculation; project finance not modelled. Decommission 15% of Capital Expenditure accrued from revenues once 50% of initial reserves are produced. Significant uncertainty around potential costs is likely to endure for a number of reasons.

Main findings:

• The deals negotiated in the first bid round, signed in 2017, show an average government take (undiscounted) of 56% across Blocks 4 and 9.

This falls in the middle of the curve of government take metrics for similar circumstances.

The terms signed for Block 4 differed from Block 9 in two ways: the cost recovery ceiling agreed was lower (60% versus 65%) and the profit split mechanism had a greater maximum share to the government (55% compared to 40%). These differences lead to a higher yield from Block 4 compared to Block 9, using the same economic assumptions.

• Tax contributions from the offshore gas sector cannot be transformative for Lebanon’s distressed public finances. Even taxes from a large field might peak at only 3% of the annual budget for a couple of years in the 2030s. Gas is not a silver bullet.

• Likewise, the sector is unlikely to provide a basis for further sovereign debt. The net present value of the government’s share of a large (10 trillion cubic feet) field might represent one year’s servicing of current debt of $80 billion. The question of extra debt required to fund direct state participation should also be carefully considered.

• With prospects closing of an export pipeline to Europe, even for a significant discovery, and geopolitics dogging regional project possibilities, development of any discovery is more likely to be led by LNG and / or the domestic market.

• International investors are unlikely to commit to developing a field unless they believe they can secure an average price at least $5 / mmBTU (in real terms) – more than twice the price of LNG today in all three traditional regional markets.

• Nevertheless, given the critical state of Lebanon’s power sector, a national gas project could have significant impact on the economy, particularly as the sector is currently heavily subsidised and expensive because it relies on fuel imports to generate electricity. But investors would likely need a lot of reassurance to develop a project that was locked into the domestic market, and there would be a natural cap on demand, possibly of between 10 tcf and 15 tcf.