BASRA, Iraq/BAGHDAD (Reuters) – Just weeks ago, U.S. energy giant ExxonMobil looked poised to move ahead with a $53 billion project to boost Iraq’s oil output at its southern fields, a milestone in the company’s ambitions to expand in the country.

But now a combination of contractual wrangling and security concerns, heightened by escalating tensions between Iraq’s bigger neighbor Iran and the United States, has conspired to hold back a deal, according to Iraqi government officials.

The negotiations have been stymied by terms of the contract that Baghdad objects to, said four Iraqi officials involved in the discussions who spoke to Reuters on condition of anonymity due to the sensitivity of the matter.

Utilizing the Arctic, Moscow eyes 20% global market share, energy minister says.

MOSCOW — Russia aims to increase its liquefied natural gas output about fivefold by 2035 to capture about 20% of the global market.

The country envisions up to 70% of its LNG exports by then going to the Asia-Pacific region, through the Arctic Ocean shipping route.

Energy Minister Alexander Novak told Nikkei in Moscow that Russia’s government intends to strengthen its cooperation with Japan in terms of funding and technology for the LNG and related sectors.

Japanese Prime Minister Shinzo Abe and Russian President Vladimir Putin are expected to discuss economic cooperation in areas including energy when they meet in Osaka on June 29 on the sidelines of the G-20 summit. The leaders will also discuss a peace treaty and other matters between the countries.

Novak could join Putin’s delegation.

Russia’s current LNG output is about 28 million tons a year. This combines output from the Sakhalin-2 project, in which Japanese general traders Mitsui & Co. and Mitsubishi Corp. participate, and the Yamal LNG project in Arctic Russia.

Russian Energy Minister Alexander Novak told Nikkei that Russia aims to increase its LNG output about fivefold by 2035.

The plan is to raise the total, which now represents around 6% of global demand, to between 120 million tons and 140 tons by 2035, according to Novak.

Qatar and Australia each accounted for over 20% of the global LNG market in 2018. Russia’s goal is to rival these producers as well as the United States in LNG output.

Novak said the Asia-Pacific region is home to some of the world’s biggest LNG markets, and that Russia expects to boost exports to Japan, China, India, South Korea and Vietnam.

Russia also exports LNG to Europe but has hastened the introduction of a planned Arctic Ocean shipping route so that 60% to 70% of its exports will go to Asia-Pacific, Novak said.

Russia hopes to attract Japanese technology, loans and investments to its LNG sector, Novak said, adding that Moscow welcomes foreign partners, including Japan.

He also expressed hope that final-stage negotiations between Russia’s Novatek and Japanese companies, including Mitsui, regarding investments in the Arctic LNG 2 project will soon come to fruition.

Russia’s annexation of Crimea in 2014 triggered sanctions from the West. Novak said there is a possibility that the sanctions could apply to the LNG deals. He added that Russia will consider procuring funds in currencies other than the dollar as a way to maneuver around the sanctions.

The German utility paints a sobering picture for the future of the fuel, even in a lower price environment.

Low carbon heating systems and a huge growth in renewables will continue to drive down northwest European (NWE) gas demand, which has been structurally decreasing since the financial crisis, Andree Stracke, chief commercial officer at the supply and trading arm of German utility RWE, told the Flame gas conference in Amsterdam in May.

The RWE base case for NWE gas demand is 227bn m³/yr in 2030, down from 267bn m³/yr in 2018 and from 309bn m³/yr in 2010. Its high case scenario is 275bn m³/yr, but its low case is just 178bn m³/yr.

Substitution in the retail sector will drive the highest demand decrease. Electric heat pumps are a “real killer”, says Stracke, along with wood pellets and better insulation.

Residential and commercial gas demand peaked as far back as 2003 and has trended slightly lower ever since. RWE predicts a 21pc decrease from 2018 levels by 2030—rising to 30pc in a high-efficiency, low-demand scenario—which is “really significant” as heating is the bulk of overall demand.

Recent UK and Dutch regulation to outlaw gas supply to new homes are “really huge milestones”, says Stracke, even though new houses make up, for example, only 2pc of the housing stock in Germany . The Netherlands is aiming for 200,000 houses ‘free of gas’ by 2030.

Limiting gas supply bans just to new houses would not be enough to ensure meeting the heating sector’s overall strict emission reduction targets, he notes. Regulation covering existing houses could push significant costs onto house owners and tenants, so governments are loath to legislate. RWE’s base case scenario sees heating sector regulation reducing gas demand, but only slowly.

But retrofitting, as is being promoted in UK and Dutch initiatives, once a community agrees to it, could go much further, Stacke warns, confessing that, “after 25 years in the gas industry, the new rules are a shocker to me”.

On a slightly more positive note, there could be some switching from fuel oil to gas in the German heating market, says Stracke, but only if legislation mandates customers to switch away from oil.

Gas to power

Gas demand for power has fallen by 16pc from a 2010 peak, mainly due to renewables, as well as high gas prices relative to coal. Germany has 100GW of installed conventional thermal capacity, but now has 110GW of renewable capacity, says Stracke.

RWE’s base case sees relatively flat overall demand for gas power, as German and Dutch coal exits and a reduction of German, French and Belgian nuclear capacity are largely compensated by an increase in renewables.

Quicker nuclear and/or coal phaseouts could offer additional gas demand upside, as the resultant electricity supply gap could not be filled fully by renewable generation. Lower gas prices could also drive demand with a potential major impact in the power sector, although not in the retail sector.

On the other hand, politicians and voters want to reduce CO2 further, says Stracke.
“We have underestimated the will of the people to go into renewable energy,” he says. “A renewables glut is coming, and we have to adapt.”

One reality of this new paradigm is a significant increase in the need for gas-fired power capacity as a back-up for intermittent renewables. NWE, in RWE’s base case, will see 39pc increase in peak gas demand by 2030, from c.300mn m³/d to c.400mn m³/d. Gas transmission capacity will therefore still be needed, but only on a short-term basis, says Stracke. And the current driver of gas storage usage, for summer/winter seasonality, will also change.

The challenge is that “no-one so far” is prepared to pay for the increase in required peak gas-fired power capacity, particularly as baseload requirements decrease, says Stracke. “Who is investing, given the uncertainty? We have not seen it. We need sustained higher peak power prices into the future”.

Without a capacity market, as the UK and France have introduced, there is no incentive to invest, beyond small-scale open-cycle turbines, as these can pay back quickly over 3-4 years, he adds.

President Nicolas Maduro is standing firm, despite oil production falling to levels not seen since the infamous oil lockout of 16 years ago

Venezuela’s oil sector continues its precipitous collapse, stricken by US sanctions and mismanagement, which have reduced crude production to its lowest level since 2003 — when several months of nationwide protests at Pdvsa, the state-owned oil company, wiped out almost a third of production.

US sanctions on Venezuela’s energy sector are having a crippling effect. The US Energy Administration (EIA) has reported losses in overall Venezuelan production of around 400,000bl/d since the year began. In April, output averaged just 830,000bl/d according to the EIA, while Opec’s Monthly Oil Report put the estimated production figure even lower at 768,000bl/d.

Output has recovered slightly from March, when power outages across the country devastated the sector. Information provider S&P Global Platts calculated roughly 40,000bl/d returning to production in April, but many facilities remain damaged and further losses are expected. Power failures paralysed exports at Venezuela’s main oil terminal Jose, while the Puerto la Cruz refinery in Anzoategui, already barely operating, was put out of commission.

Until now, most of the production losses have been from Maracaibo and the Maturin sub-basin. But the power issues are now also starting to hit the Orinoco Belt oil fields. At the beginning of 2019, Orinoco constituted 40pc of total national output, according to the Center for Strategic and International Studies (CSIS) thinktank.

Three Orinoco upgraders were taken offline and are now in “recirculation” to prevent damage, but not outputting heavy crude. The Petropriar upgrader (jointly owned between Pdvsa and Chevron), Petromonagas upgrader (Russia’s Rosneft/Pdvsa) and Petrocedeno upgrader (Total/Norway’s Equinor/Pdvsa) were all affected and are still out of action due to lack of storage space. The Petrolera Sinovensa upgrader (China’s CNPC/Pdvsa) is partly running but only at 105,000bl/d. Combined, the four upgraders have a normal synthetic crude capacity of 600,000bl/d.

The Orinoco Belt is also struggling to cope with shortages of diluent, previously imported from the US, and available tankers. Last year, Venezuela imported almost 90,000bl/d of naphtha, mostly from the US, to help blend its heavy crude. Issues with sourcing alternative supply, as well as the scarcity of funds, is having a significant impact in the Orinoco. Platts reported combined production had dropped 77pc by mid-May to just 169,800bl/d, from 764,100bl/d at the beginning of April.

“Venezuela was able to obtain diluents from Russia and India after the OFAC [Office of Foreign Assets Control] action, but not in the volume needed for the Orinoco to run smoothly,” says Patrick O’Connell, fixed income analyst at Alliance Bernstein, a global asset management firm. “Partially due to the lower availability of diluent, Venezuela is converting its large Orinoco upgraders into simple blending facilities, which will yield a less valuable type of crude oil but save on imported intermediate products.”

Clinging on

Damage to the country’s oil industry may be a pyrrhic victory for the opposition-led National Assembly, increasing the pressure on incumbent president Nicolas Maduro, but so far there has been little sign of regime change.

On 30 April, head of the Venezuelan National Assembly and self-declared president Juan Guaido, alongside the recently freed opposition politician Leopoldo Lopez, called for national protests to unseat Maduro from power. He claimed Maduro no longer had the backing of the military; but the Venezuelan president, surrounded by key military personnel, quickly denounced the appeal as an attempted coup.

Pressure on the current regime will only mount, though, as crude production continues its prolific collapse. Carlos de Sousa, lead economist at Oxford Economics, a global economics forecaster, expects “oil production to fall to 500,00bl/d by year-end — China and India will remain the main buyers”.

But the CSIS predicts that, if Maduro remains at the helm, then output will likely fall below 500,000bl/d as early as October. If he is still in power by November the institution expects production to be hovering around 400,000bl/d. Even if the opposition takes control it will be difficult to return national output to 1.3mn bl/d any time soon. Damage to oil assets, attracting foreign investment and changes in global oil markets in recent years all point to a tough recovery even if the opposition gain control.

Cutting its losses

Meanwhile, Venezuela’s financial position could soon deteriorate even further. In May, the National Assembly voted to pay the $71mn interest on the Pdvsa bond 2020, the only bond the country has yet to default on, to avoid creditors seizing its US-based refining subsidiary Citgo. Bond holders control 50.1pc of shares in the company, while the remaining 49.9pc serves as collateral for a $1.5bn loan issued by Rosneft, who could equally enforce its security should Venezuela default on the payment.

“We believe the country will do what it can to keep current on these payments, as a default on this bond would lead to creditors attempting to seize control of Citgo — a valuable overseas asset which would likely prove crucial in an eventual debt restructuring,” says Thomas Nicol, product manager at Alliance Bernstein. “The National Assembly successfully paid the $71mn coupon within the 30-day grace period in May 2019, but making a payment of more than $900mn in October will prove more challenging, particularly in the absence of regime change against a backdrop of US sanctions and plummeting domestic oil production.”

Daniel Pilarski, a partner at law firm Watson Farley & Williams, a global law firm, doubts the legality of a forced sale. “Even if Venezuela wished to sell (which they do not), it would violate existing sanctions for any parties (US or non-US) to purchase Citgo and pay the proceeds to Pdvsa. Also, given Pdvsa’s dire financial position, the transfer would be potentially subject to fraudulent conveyance and similar conditions, so it would be very hard for the purchaser to get clean title,” says Pilarski.

Citgo has so far escaped sanctions but has until 27 July to end all crude imports from Venezuela. Similarly, US oil services companies Baker Hughes, Chevron, Halliburton, Schlumberger and Weatherford International all have a three-month window to exit the country.

Israel has agreed to a number of Lebanese conditions for negotiating the demarcation of their joint maritime border, marking a positive shift in years-long efforts to find a solution to the dispute.

According to a number of reports, including in local newspapers The Daily Star and Al-Akhbar, as well as Agence France Presse a new round of shuttle diplomacy by Acting U.S. Assistant Secretary of State for Near Eastern Affairs David Satterfield had been successful in setting some broad outlines for negotiations. These include a Lebanese demand to negotiate both the land and sea borders at the same time, and to hold negotiations under the auspices of the United Nations at Naqoura, Lebanon’s southernmost point, in the same manner that determined the Blue Line that marks Israel’s 2000 withdrawal from Lebanon.

Lebanese officials dispute more than a dozen points along the Blue Line, while a sliver of about 860 square kilometers of maritime area is disputed by Israel and Lebanon.

Lebanese officials have described the new round of talks as “positive,” but have said outlying issues remain. This reportedly includes the duration of negotiations, which Lebanon has demanded be open ended, but Israel has called for limiting to a six month window.

In late April, Berri said Lebanon was ready to demarcate its southern maritime border with United Nations supervision, using the same mechanism adopted for the Blue Line. The U.S would act as a facilitator of the negotiations.

A small sliver of maritime Bloc 9, where exploratory drilling is slated to take place next year, sits in the disputed area. Blocs 8 and 10, both included in a second licensing round launched in January, also partially lie in this area.

While several rounds of negotiations have previously failed, Roudi Baroudi, an independent energy analyst with over 40 years experience in the field, said that large hydrocarbon finds in the region, and associated interest from  leading companies, meant that all parties involved were keen to find a resolution.

“There are maybe trillions of dollars of hydrocarbons in this zone, and some of the biggest oil and gas players in the world are here,” Baroudi told LOGI. “They are not coming here to see us. They are coming here for our wealth, and big oil and gas companies don’t want to go exploring in an area where there is a problem.

For an explainer on the origins of southern dispute, click here.

Syrian Oil Minister Ali Ghanem announced that the country expects commercial production of offshore gas to begin by 2023, in a development that once again raises the issue of demarcating Lebanon’s northern maritime border with Syria.

Ghanem said that a Russian company already drilling onshore in Syria would go about the maritime exploration. The size of a single one of the five blocs Syria has delineated would hold reserves equivalent to its entire onshore reserves, he said, adding he expected some light oil to be found.

The announcement comes soon after Lebanon launched a second offshore licensing round which includes Blocs 1 and 2 – both of which lie in the north and border Syria’s maritime area. A zone of roughly 830 square kilometers is under dispute, according to Roudi Baroudi, an independent energy consultant with more than 40 years experience in the sector.

But while Lebanon is currently involved in serious UN-sponsored mediation efforts to resolve its southern maritime border dispute with Israel, there has been no public announcement of preparations to negotiate with Syria. The issue is politically sensitive, given divisions among factions in the Lebanese government over the nature of the country’s ties to Syria, effectively frozen since the Syrian crisis began.

The demarcation issue centers around the fact that Syria has never unilaterally published its maritime boundaries, while Lebanon did in 2011. When Lebanon’s line is compared to the blocs that Syria published in March 2019, there is an overlap of about 832 square kilometers, Baroudi said.

Because maritime boundaries are based on terrestrial borders, Baroudi said that demarcating the maritime border could be as simple as pinpointing the final land point between Syria and Lebanon, which would be in the middle of the northern Nahr al-Kabir. ”It has never been fixed because it’s never been relevant, but it’s no more than a technical issue” he said.

Baroudi noted that the northern demarcation issue would be aided by a resolution to the southern maritime border dispute with Israel, currently the subject of intensive U.S.-mediated negotiations. A resolution to that dispute would set a border point between Israel, Cyprus and Lebanon, known as a tri-junction point, which would aid in the drawing of the Syrian-Lebanese Cypriot tri-junction point.

Potentially complicating matters is the fact that Israel and Syria have not signed the UN Convention on the Law of the Sea, which in its article 74 sets out rules for delineating maritime borders between states with opposite or adjacent coasts.

Tests to flow Israeli gas through the East Mediterranean Gas (EMG) pipeline to Egypt are now under way and are expected to be concluded at the end of this month ahead of the startup of significant exports later in the year, an industry source told S&P Global Platts Thursday.

US-based producer Noble Energy and its Israeli partner Delek Drilling — together with Egyptian-owned Sphinx EG — in September last year agreed to buy a 39% stake in the idled EMG pipeline for $518 million as part of plans to use the pipeline in reverse for Israeli gas to flow to Egypt.

“Tests are under way and are on track to be completed as scheduled by the end of June. Once that is done, gas from the Tamar field can start to flow through the EMG pipeline on an interruptible basis,” the source said.

Noble could not be reached for comment, while Delek Drilling declined to comment.

The pipeline — which runs for 90 km off the Israeli and Egyptian coasts — connects the Israel pipeline network from Ashkelon to the Egyptian pipeline network near El Arish.

It started operations in 2008 to flow Egyptian gas to Israel until 2012 when operations were halted as Egypt’s gas production began to decline after the Arab Spring the previous year.

Noble — operator of both the producing Tamar field and the giant Leviathan field due online at the end of 2019 — has said it expects to flow at least 350 MMcf/d (10 million cu m/d) through the EMG pipeline once Leviathan starts.

The pipeline has a design capacity of 7 Bcm/year — or 19 million cu m/d.

The deliveries will be part of a deal signed in February 2018 to supply Egypt’s Dolphinus Holdings with 64 Bcm of Israeli gas over a 10-year period.

OFFTAKE DEAL

Noble and Delek on Wednesday also agreed a deal to supply gas from Leviathan to Israel’s main utility, the Israel Electric Corp. (IEC), for up to two years from its startup.

The agreement — worth some $700 million — will give the Leviathan partners another guaranteed market for the first stage development of the giant field.

For IEC, the agreement gives it access to gas supply ahead of the startup of the Energean-operated Karish field offshore Israel.

The terms of the supply agreement will start on October 1, 2019 or the date Leviathan starts up — whichever is later — and end on June 30, 2021, or on the date Karish starts up, whichever is earlier.

According to a statement on the deal, if the startup of Karish is delayed, the Leviathan partners and IEC can extend the supply deal “by mutual consent.”

Delek Drilling CEO Yossi Abu said the $700 million offtake agreement with IEC was a “landmark win” for both parties.

“It is good for us, as it means the output from stage one of the development of the Leviathan field is now close to being fully taken up,” Abu said.

“For IEC, they have the guarantee of security supply from a low carbon energy source which will enable them to reduce their reliance on coal and reduce cost to both industrial and ordinary consumers,” he said.

“It also secures the status of the Leviathan gas field as an anchor resource for the entire region.”

–Stuart Elliott, stuart.elliott@spglobal.com

–Edited by Alisdair Bowles, alisdair.bowles@spglobal.com

While the Natural Gas Public Company (Defa) plans to finally seal a contract in October for the installation of an FSRU plus infrastructure, Greece’s Energean is pushing hard for the Cyprus market to be opened up.

Defa’s troubled tender process – launched last year – closes on July 12, its fourth attempt to nail down a supplier of natural gas.

It has extended the deadline several times since “to allow companies interested in bidding sufficient time to put together top-quality proposals so Defa has a better chance of success,” an official Cypriot source told S&P Global Platts.

Defa invited expressions of interest for the supply of LNG for the FSRU, which will be connected to the main power station at Vassiliko.

“There are two processes in the EoI. One calls for expressions of interest in the LNG SPA, which will involve negotiations for mid-term, 3-5 year LNG SPAs. The second invites expressions of interest for master sales agreements that will enable Defa to procure cargoes from the spot market,” the source said.

“The September 6 deadline relates to the SPA process and includes the first lot of MSA suppliers. The MSA will last up to June 2023 and it will be assessed annually after each subsequent September 6,” the source added.

“The first assessment starts September 6, 2019. Any company that submits an MSA after that date and before September 6, 2020, will be assessed in the next assessment period.”

“That will last up to four years. Defa plans multiple MSA agreements that will lead to mini-tender each time it wants to procure cargo from the spot market. Defa intends to arrange to have 15-20 MSAs available.”

But as this process unfolds, Energean Oil & Gas is lobbying hard to be allowed access to the Cyprus market so it can sell its Israeli gas via pipelines to Vassiliko by early 2021.

Officials from Energean visited Cyprus last week to make their pitch to Energy Minister George Lakkotrypis and convince other stakeholders, such as the Cyprus Electricity Authority (EAC) and the employers federation (OEB).

Although the government has rebuffed Energean’s “unsolicited offer” the Greek firm insist they can deliver quicker than the FSRU project and that competition should be allowed for the benefit of the end-user.

“We pointed out that Cyprus should not rely only on one source: all the countries in the region combine pipeline gas with LNG to enhance security of supply,” a company source told the Financial Mirror.

“Energean emphasised the fact that we can supply Cyprus with natural gas in 2021 -no way that FSRU will be ready by then- and at really competitive prices,” the source added.

Even if the figures add up financially, Nicosia is reluctant to abandon its plan as it doesn’t want to be dependent on a single supplier and forsake the construction of an LNG terminal.

“Defa [has] selected the FSRU solution and it has secured a €101 mln grant from the European Union, which gives the project economic sense, more so than anything in the past,” said an official source said.

Energean has submitted to the Cyprus Energy Regulatory Authority (CERA) an updated proposal to supply the island with natural gas through an FPSO, which will commence operations in March 2021 in the EEZ of Israel.

Legal action

There are even some suggestions the Greek firm could seek legal action to force its way into the Cyprus supply chain.

In its presentation to officials in Nicosia, Energean said it has the rights to export by the Israeli government, it has partners “willing to invest” in the $315 mln pipeline and “can work with the authorities to “achieve all the energy objectives”.

Energean said it can seek to obtain EU support to make the supply of gas even more competitive while reminding that Cyprus is legally obligated to switch from diesel to gas power generation.

Last month, Energean submitted an updated technical report detailing the way natural gas will be imported to Cyprus through pipelines from Karish offshore block to the “Energean Power” Floating Production, Storage and Offloading unit, and from there through a pipeline to Vassiliko where it will emerge onshore.

Energean has also signed a Letter of Intent (LOI) for the supply of natural gas to private power generation licence holders in Cyprus.

The company argues it would establish competition in the Cypriot energy market as a whole, as there are now options for the supply of natural gas to private electricity producers.

The Greek firm said it has already initiated the procedures for obtaining the necessary Natural Gas Εxport and Pipeline Construction Licences from its FPSO in the Israeli EEZ to Vasiliko.

CEO of Energean Mathios Rigas said in May: “We have submitted a comprehensive Plan to supply the Republic of Cyprus with natural gas through the infrastructure that Energean is constructing and will be operating in Israel.”

The company argues that its solution is “cheaper and quicker than any other” and that having multiple supply sources strengthens security of supply as well as competition for the benefit of consumers and the economy.

“We are at the disposal of the Cypriot Government and the Cypriot Authorities to discuss how this Plan could be implemented so that Cyprus will be able to start using affordable natural gas in March 2021, provided there are no delays in permitting procedures,” said Rigas.

Emerging market

Complicating matters is that the government has declared the natural gas market in Cyprus as isolated and emerging.

It effectively means that Defa is not only the sole importer and distributor of natural gas on the island but also the solitary entity allowed to supply the fuel.

Defa’s grip on the market squeezes out potential suitors wanting to supply the island with natural gas.

As the market was declared an emerging one, observers say the energy regulator is not obliged to accept or examine applications from companies like Energean wanting to secure a supply permit.

Defa issued a tender for the design, construction and operation of a floating LNG import terminal to be located at Vassiliko Bay, near Limassol, separately of efforts to import the fuel by January 2020 to avoid emissions fines.

Last July, Defa described as “unsolicited” a proposal from Energean to build a pipeline to Cyprus from Israeli offshore gas fields.

DEFA chairman Simeon Kassianides said at the time that the proposal was not submitted as part of a call for tender.

The new tender, issued on behalf of the Natural Gas Infrastructure Company (ETYFA), is for a floating storage and regasification unit (FSRU), a jetty for mooring the FSRU, a jetty borne gas pipeline and related infrastructure, all of which is expected to cost some EUR 250 mln.

The LNG terminal will be completed in 2020 and has secured a funding of 40%, or up to EUR 101 mln, as a grant from the EU under the Connecting Europe Facility (CEF) financial instruments.

London — Egypt is looking at launching a new license round for blocks in the western parts of Egypt’s Mediterranean waters following on from two other recent exploration rounds, a source at state-owned Egyptian Natural Gas Holding Company (EGAS) said Thursday.

Egypt has had significant success in recent years with major gas discoveries, including the supergiant 30 Tcf (850 Bcm) Zohr find and a string of other finds both on- and offshore.

In February, BP, Eni, ExxonMobil and Shell were among companies awarded blocks in a wide-reaching exploration round covering a number of East Mediterranean offshore blocks and some onshore zones.

A round was also launched in March for 10 blocks in Egypt’s sector of the Red Sea.

Some 11 blocks were also now expected to be put up for auction in western parts of offshore Egypt’s Mediterranean waters, with reports that the round could be launched by the end of 2019 or the start of next year.

“The decision has not been announced yet about the timing, or the offer,” a source at EGAS said Thursday. “We are just thinking about it.”

Egypt has offered attractive terms to companies looking for a share of the country’s vast resources.

Self-sufficiency

Zohr — and additional Egyptian gas field start-ups — made the country self-sufficient in gas last September and Egypt has since become an exporter of gas once again, having been forced to import LNG for several years to meet domestic demand.

Its gas production rose to some 58 Bcm in 2018, according to estimates from BP and the International Energy Agency, its highest level since 2012.

The oil ministry has said it expected production to increase to some 80 Bcm/year in 2020.

Zohr alone could produce at as much as 3.2 Bcf/d (the equivalent of 91 million cu m/d, or 33.2 Bcm/year) in the coming years.

Despite the optimism, the IEA said earlier this month it expected Egyptian gas output to peak at 77 Bcm by 2024 at an annual growth rate of around 4.8%.

The IEA also said it expected the policy of prioritizing domestic use will remain in force for the foreseeable future and that Egypt’s exports will remain at a maximum of 4 Bcm/year.

— Stuart Elliott, stuart.elliott@spglobal.com

— Edited by Dan Lalor, daniel.lalor@spglobal.com