A gas field doesn’t disappear when its best years are behind it: The infrastructure is still there, the wells still produce — just less than before. Across our gas sector, declining output has erased almost a decade of production gains, leaving a country that spent years building its export ambitions back shopping for supply.

The last gas turnaround came fast enough to make the next one look easy. Eni announced the discovery of Zohr — the largest gas field discovered in the Mediterranean — in August 2015 and brought it into production two years later. By 2018, Egypt had returned to an annual gas trade surplus. Five years later, that surplus was gone.

That is the trouble with a discovery big enough to change the story: it is tempting to mistake it for the ending. Keeping the gas flowing required more than one extraordinary find. The country is now working on a sequel — with a growing import bill running through the opening credits.

The reversal

BY THE NUMBERS- Egypt’s return as a net gas exporter lasted five years. The country moved from a 9.2 bcm annual gas trade deficit in 2016 to a small surplus in 2018, before slipping back into net importer territory in 2023, according to our calculations using the Joint Organizations Data Initiative (Jodi) figures. By 2025, that deficit had widened to 21.1 bcm as domestic production fell and imports surged. Roughly 40% of production has gone in four years: annual gas output climbed from 42.1 bcm in 2016 to a peak of 70.4 bcm in 2021, before falling for four consecutive years to 42.3 bcm in 2025 — almost back to where it started, and 28.1 bcm of annual supply lighter.

Depletion did most of the damage: Zohr — which accounted for roughly 30% of the country’s total natural gas output — has seen its production slide to around 1.2 bcf/d from a 2019 peak of 3.2 bcf/d. “Energy companies, especially in the natural gas industry, often tend to extract as much as possible as quickly as possible for their margins,” Nour Taha, a political researcher with the Atlantic Council’s Middle East Programs, tells EnterpriseAM. “But since the gas inside a reservoir is a finite asset, aggressively extracting too much early on can impact the longevity of a reservoir, which is what happened in the case of Zohr,” he says.

Zohr is the marquee name, but the decline has a wider cast: Natural depletion has driven steep falls at many of Egypt’s shallow-water Pliocene gas fields, with declines accelerating as those fields mature, Martijn Murphy, North Africa and Eastern Mediterranean Upstream principal analyst at Wood Mackenzie, tells EnterpriseAM, adding that earlier-than-expected water breakthrough has contributed to underperformance at key developments. Offshore Nile Delta fields account for the producing areas with the largest depletion rates between 2021 and 2025, he says.

The export boom outlasted the production peak — briefly: Gas exports reached a decade-high 12 bcm in 2022, even as domestic output began falling and pipeline imports increased. By 2023, Egypt was importing more gas than it exported overall, despite continuing to ship LNG abroad. Monthly imports overtook exports in May that year and remained higher through December. However, between 2023 and 2025, annual gas imports increased from 8.6 bcm to 22.2 bcm, while exports fell from 5.6 bcm to just 1.1 bcm.

This year hasn’t broken the pattern: Domestic production fell another 7.8% y-o-y to 19.5 bcm in 1H this year, while imports jumped 51.7% to 13.1 bcm. Average production stood at roughly 3.8 bcf/d — some 44% below its level in the first half of 2021. LNG imports more than doubled y-o-y to 8.8 bcm in 1H 2026, accounting for two-thirds of total gas imports, while pipeline inflows fell 7.7% to 4.3 bcm. “Production is struggling to keep pace as consumption increases,” Laury Haytayan, MENA director at the Natural Resource Governance Institute, tells EnterpriseAM.

WANT A MORE IN-DEPTH LOOK? Back in June, we did a more micro-detailed analysis on Egypt’s gas balance in the last three years here.

Inside the well

Getting the gas back isn't one job. It's three, on three different clocks. Egypt’s recovery depends on three overlapping tasks: Getting more gas from producing fields, connecting nearby discoveries to existing facilities, and developing resources that require new infrastructure. Each comes with a different timetable. The nearer-term window lies in making better use of the production system already in place, while larger developments work their way toward first gas.

Existing infrastructure can make smaller discoveries worth it: Where technically feasible, a subsea “tieback” links a new offshore well to an existing production system, allowing it to share platforms, processing facilities, and pipelines instead of requiring new infrastructure. That cuts upfront costs and lowers the volume of gas needed to justify the investment. Egypt is already using the model, with approved projects connecting new wells to established networks and recent discoveries near existing facilities being assessed for accelerated development.

So the next time a big discovery makes the news, hold your applause for a year or two. Appraisal establishes the extent of the reservoir, how easily gas flows through the rock, and the production rates wells can sustain. Those findings determine the number and placement of development wells, the equipment required, and whether the expected gas sales justify the cost. A large estimate of gas in place is therefore an opening assessment, rather than a forecast of daily supply.

There is gas to develop — but commercial terms matter: Egypt has around 19 tcf of commercial gas reserves classified as 2P — equivalent in volume to roughly nine years of the country’s 2024 gas consumption — and another 20 tcf of contingent resources, classified as 2C, Murphy estimates.

SOUND SMART- 2P means “proved plus probable reserves” — gas estimated to be recoverable from commercial projects. 2C means the central estimate of “contingent resources” — gas that has been discovered but can’t yet be classified as commercially recoverable, due to obstacles that include pricing, development costs, infrastructure, or approvals.

Smaller developments can slow the bleeding, but only a big find reverses it. “There are few material fields waiting to be developed,” Murphy says, adding that returning production to some 6 bcf/d would require transformational exploration success — and exploration since Zohr has mostly disappointed.

Some of the spending will go toward losing less: Investment on wells and facilities can support production that would otherwise have declined further, without producing an obvious increase in national output. That makes the distinction between additional production at a project and net growth across the country essential — a successful development can still be offset by falling supply elsewhere.

The terms on offer

The investment bargain runs from pricing to paperwork. The Oil Ministry’s push extends from better prices for selected production to more flexible production-sharing arrangements, revised concession agreements, and simpler contracting procedures. In March, the government was amending several agreements — an acknowledgment that the old investment model has stalled. Different problems need different fixes: an expensive offshore discovery needs terms that justify years of spending before first gas, while a mature field needs further drilling to stay worthwhile as output declines.

For frontier exploration, the R-factor makes the production split respond to profitability: The mechanism tracks cumulative revenues or earnings against expenditure, allowing investors a larger share of petroleum earnings while returns remain low and increasing the state’s share as profitability improves. After introducing it in 2025, the ministry recently said that it had applied the model in the Western Mediterranean and expanded its use to the Red Sea and southern regions where substantial infrastructure investment is required.

The economic logic is to improve cashflow when investors are still earning their money back. A more generous early share strengthens the investment case for a costly development while preserving the state's ability to capture more of the upside later. How far that changes a project's economics depends on the agreed costs, revenue definitions, and thresholds that trigger a different split.

Mature fields are getting a different form of support. The new energy investment model — brought into action later in March — links the contractor’s share to Brent prices and daily production, with that share increasing when prices or output fall — a distinct mechanism from the R-factor, aimed at keeping investment attractive in older fields with higher operating costs. It fits alongside the ministry’s March plans for a fiscal regime encouraging horizontal drilling and hydraulic fracturing over the following five years.

The contracting overhaul also aims to put a clock on development: A proposed framework would simplify contracts and cap development leases at two years, after which Egyptian General Petroleum Corporation (EGPC) and Egas could reclaim concessions without compensation. Commercial discoveries would move to 20–30-year contracts with long-term sales agreements covering volumes, domestic and export allocations, and pricing. It would also simplify tax filing and retain equipment customs exemptions.

IN CONTEXT- EGPC and Egas’ efforts since the early 2020s have unlocked incremental investment, especially in onshore brownfield areas, Murphy tells us. Higher gas prices have encouraged exploration and development of fields that otherwise wouldn’t have been commercially viable. He identifies {West Delta Deep Marine Phases 10-12, North Idku/ North El Amriya, West El Burullus, Mina West, Harmattan, and Fayoum-5 as projects where more flexible fiscal terms helped secure final investment decisions.

The long climb back

Investors are responding, but the test is where the money turns into gas: The Oil Minister’s frequent meetings with international oil and gas executives point to renewed engagement. Global energy giants have also pledged to pour USD 19 bn into our energy sector over the next three years, giving a much-needed jolt. “Drilling is up, the rig count is up and companies are spending more,” Murphy says.

THE CAVEAT- Drillers have long memories and other options: Arrears have historically been cyclical, Murphy cautions, making the challenge whether Egypt can maintain repayments through economic headwinds. For companies considering developments with longer payback periods, confidence in payment must also come alongside terms competitive enough to secure investment against projects elsewhere. Competition for Egyptian assets in the Capricorn, Pharos, and BP’ acquisitions offers another indication of renewed appetite — something he says has been absent for years.

REMEMBER- We settled that question in June, to the tune of USD 6.1 bn. The government fully cleared its outstanding arrears to international oil companies in June this year — a backlog that stood at USD 6.1 bn in June 2024. Clearing the arrears backlog was the linchpin in the government’s strategy to restore investor confidence and get international operators drilling again. “Now that the burden of arrears is off the state’s back, there is a new window to renegotiate terms,” Taha says, arguing that the reluctance to explore while payments were outstanding had limited the state’s ability to negotiate over exploration and extraction.

But paying yesterday’s bills doesn’t produce tomorrow’s gas: Improved payments can help projects move forward, but development wells still need to be drilled, equipment procured and installed, and facilities connected and tested. The Oil Ministry acknowledged this when announcing the clearance of arrears, noting that deepwater developments require years of work before production begins. “Bringing gas from a large discovery to market would take around four years,” Murphy estimates.

The next discovery buys your grid time, nothing more: Murphy expects Egyptian gas production to continue falling, although at a slower pace, with new projects — notably Denise West and Nargis — helping offset losses from older fields. The existing infrastructure gives optionality to bring some discoveries into production faster and keep older fields operating longer, but whether that reverses import dependence will depend on the scale and timing of those additions, the losses they must replace, and the demand they ultimately have to meet.

What’s next? With gas output under 4 bcf/d and a push to add 1 bcf/d by year-end — part of a larger target to reach 6.2 bcf/d by 2027 — the strategy could largely depend on attracting enough investment to reverse the decline. The milestones to watch: investment decisions, development approvals, exploration success following seismic work, and competitive bid rounds attracting credible newcomers.