Spain’s Repsol also exiting Ioannina license, to be fully held by Energean

Spain’s Repsol is continuing to disinvest its hydrocarbon interests in the Greek market in the wake of a return to the Greek State of its licensing rights for a block in Etoloakarnania, northwestern Greece, the company’s latest move being a plan to withdraw from a license concerning a block in Ioannina, also in the northwest.

Repsol, which formed a partnership with Energean Oil & Gas for the Ioannina block, holds a 60 percent stake in this project, now at a pre-drilling stage, as an exploratory step.

Repsol has informed EDEY, the Greek Hydrocarbon Management Company, of its decision to withdraw from the Ioannina block, according to sources. The Spanish petroleum firm’s 60 percent stake will be transferred to Greek partner Energean, currently holder of the license’s other 40 percent, the sources added.

The Spanish company’s decisions on Greece are part of a wider disinvestment strategy aiming to reduce the firm’s international exposure to hydrocarbon exploration and production activities, sources explained.

Energean will seek a deadline extension, from EDEY, for drilling at the Ioannina license as it intends to find a new partner, sources informed. The Greek company remains interested in exploring the area’s hydrocarbon potential, the sources added.

Repsol’s intentions concerning an offshore block in the Ionian Sea, for which it has formed a 50-50 joint venture with Hellenic Petroleum, remain unclear.

ELPE posting results amid strong pressure felt by petroleum industry

ELPE (Hellenic Petroleum), to post financial results today amid the pandemic’s adverse conditions, seen also impacting the global petroleum industry throughout 2021, is expected to announce adjusted losses of 14 million euros for 4Q in 2020, following a profit of 24 million euros in the equivalent period a year earlier, according to an Optima Bank estimate.

The petroleum group’s adjusted EBITDA for 4Q is expected to be 62 million euros, a 48 percent reduction from the previous year.

As for 2020, overall, ELPE’s adjusted EBITDA is expected to be 318 million euros, a 44 percent reduction. Adjusted losses are expected to be 1.5 million euros following a profit of 182 million euros in 2019.

The petroleum group intends to move ahead with a transformation plan and green-energy investment plans this year.

ELPE, as an initial goal, aims to develop a RES portfolio totaling 300 MW capacity in 2021 and 600 MW by 2025.

The corporate group has already begun work on a 204-MW project in Kozani, northern Greece, following a takeover deal.

Any prospect of a recovery by the global petroleum industry appears distant. Many facilities around the world have continued to restrict their operations.

A recent Wood Mackenzie report projected the European refining industry will register losses measuring 1.4 million barrels per day until 2023 as a result of the pandemic’s ongoing lockdown measures.

At least two refineries in the Mediterranean region are currently examining the prospect of closing down.

Total, ExxonMobil, ELPE delay Crete surveys for next winter

A decision by the three-member consortium comprising Total, ExxonMobil and Hellenic Petroleum (ELPE) to conduct seismic surveys at two offshore blocks south and west of Crete in the winter of 2021-2022, instead of this winter, highlights the upstream market’s negative climate, both in Greece and internationally.

Upstream players, drastically cutting down on investments costs amid the crisis, have cancelled scores of investment plans, especially those concerning the development of new fields.

Based on the terms of its contract, the Total-ExxonMobil-ELPE consortium also had the opportunity to conduct seismic surveys at its Cretan offshore blocks this winter.

It should be pointed out that the consortium has yet to receive environmental approval for these blocks. Nor have these slots been included in an annual workplan delivered by EDEY, the Greek Hydrocarbon Management Company.

Even so, Total, ExxonMobil and ELPE do not appear prepared, under the current conditions, to increase their investment risk in the region.

Spain’s Repsol on verge of exiting Greek upstream market

Spanish petroleum firm Repsol, a member of consortiums holding licenses to three fields in Greece, is on the verge of leaving the country’s upstream market as a part of a wider strategic adjustment prompted by the oil crisis and the pandemic, developments that have impacted exploration plans, as well as a company plan to reduce its environmental footprint, sources have informed.

The upstream industry has been hit hard by the pandemic, which has driven down prices and demand. The EU’s climate-change policies are another key factor behind Repsol’s decision.

Repsol is believed to have decided to significantly reduce the number of countries in which it is currently present for hydrocarbon exploration and production, the intention being to limit operations to the more lucrative of fields.

All three fields in Repsol’s Greek portfolio are still at preliminary research stages and do not offer any production assurances, meaning they will most probably be among the first to be scrapped by the company from its list of projects.

Respol formed a partnership with Hellenic Petroleum (ELPE) for offshore exploration in the Ionian Sea. Repsol is the operator in this arrangement. A license secured by the two partners for this region in 2018 was approved in Greek Parliament a year later.

Also, in 2017, Repsol agreed to enter a partnership with Energean Oil & Gas, acquiring 60 percent stakes, and the operator’s role, for onshore blocks in Ioannina and Etoloakarnania, northwestern Greece.

Repsol maintains interests in over 40 countries, producing approximately 700,000 barrels per day.

Prinos field threatened by poor results, decline projection

Operations at the Prinos field, Greece’s only producing oil field, in the country’s offshore north, are in great danger of being disrupted following poor production figures in 2020 and a further decline predicted for 2021, a wider company update just delivered by Energean Oil & Gas, the field’s license holder, has suggested.

In 2020, production at the oil field reached just 1,800 barrels per day, while its inferior-quality output was sold at a discount price, between 7 to 8 dollars below Brent levels.

This level of output represents less than 4 percent of Energean’s overall production, which, last year, reached 48,000 barrels – mostly natural gas.

Output at the Prinos field is projected to drop below 1,500 bpd in 2021 as, even if a rescue plan for the facility is approved, related investments needed at the facility will take time to complete.

The rescue plan, announced last June by Energean and dubbed Green Prinos, envisions an adjustment for eco-friendly operations through a series of investments worth 75 million euros.

Energean’s administration, in its company update to analysts, expressed hope that a solution can be found in the first quarter of 2021 for its rescue plan, submitted to the Greek government, which then forwarded the plan to the European Commission.

The rescue plan has remained stuck at the European Directorate for Competition, whose approval is required.

Energean is considering the development of a carbon capture and storage project at its Prinos field, which would be the first in Greece, promising new life for the project, along with the support of investments at field E, whose development depends on the outcome of a financing bid, company officials informed.

Overall, the news for the Prinos field is not good. Losses incurred by this unit since September, 2019, when its crisis began before being further aggravated by the pandemic, have exceeded 100 million euros.

This loss, however, has not affected the overall financial results of Energean, generating significant earnings in Egypt, primarily. Israel, too, could become a major source of earnings for the company as of next year.

Mediterranean Gas & Energy Week, key regional summit, starts tomorrow

Two of the Mediterranean’s most important summits, the 3rd Mediterranean Oil & Gas Summit and the 8th Balkans Petroleum, have merged for Mediterranean Gas & Energy Week, a major online oil & gas event, taking place take January 19 to 21.

Following the success of the Global E&P Summit and the regional Africa Upstream, Gas & LNG Summit, North Africa’s governments will be gathering again to meet with European and Balkans officials and IOCs at the Mediterranean Gas & Energy Week, organized by IN-VR, global leader in investment networking.

Key IOCs, investors and service providers will present their new opportunities and solutions, and network with attendees
online.

Top-ranked government officials from the region, including Greece, Montenegro, Malta and Albania, will present their licensing rounds, LNG mega-projects, and new midstream projects, together with the Mediterranean’s most-established investors and new players, including Shell, TAQA Arabia, Dana Gas and Enagas.

Also, over its three days, the event promises to be filled with networking opportunities and the latest upstream and midstream developments.

Participants will include:

● Vladan Dubljević, Director, Montenegro Hydrocarbon Administration
● Alexandra Sdoukou, Secretary General for Energy and Mineral Resources, Ministry of the Environment and Energy of Greece
● Adrian Bylyku, Executive Director, AKBN
● Dr Albert Caruana, Director General, Continental Shelf Department, Office of the Prime Minister, Malta
● Khaled Abu Bakr, Executive Chairman, TAQA Arabia
● Patrick Allman-Ward, CEO, Dana Gas
● Francisco de la Flor, Director of International Organizations, Enagas
● Morris J. Becker, Senior Exploration Geoscientist – Portfolio & New Business, Middle East and Africa, Shell
● Charles Ellinas, CEO, EC Cyprus Natural Hydrocarbons Company Ltd (eCNHC)

ELPE lockdown impact fears expressed amid poorer conditions

Hellenic Petroleum ELPE chief executive Andreas Siamissis has expressed fears of the latest lockdown’s impact on fuel consumption, which he will believes will be considerable, during a presentation of third quarter results to analysts.

Narrowed refining margins, which dropped to historic lows during the third quarter, combined with a drop in demand, resulted in unprecedently difficult conditions, ELPE officials noted.

However, rays of hope have emerged for an imminent improvement in refining margins, they added.

Elpedison, ELPE’s joint energy venture with Italy’s Edison, registered a strong power generation performance, up 31 percent in the nine-month period, aided by competitively priced LNG for its production units, company officials informed.

Electricity sales rose by 5 percent, while operating profit reached 43 million euros, from 15 million euros a year earlier.

As for the natural gas market, the commercial activity of gas utility DEPA, in which ELPE holds a 35 percent stake, increased in the third quarter.

DEPA – whose two new entities, DEPA Commercial and DEPA Infrastructure, are both headed for privatization in a procedure that is expected to be completed by March, 2021 – reported a 3Q volume-based sales increase of 48 percent. Its EBITDA figure moved up to 18 million euros, up from 6 million euros a year earlier.

ELPE’s list of imminent RES projects has more-than-doubled compared to last year, the company officials informed.

Africa Upstream, LNG & Gas Summit taking place tomorrow

Following the success of the online Oil & Gas Summit, hundreds of EPs and service providers are gathering to listen to Africa’s biggest E&P opportunities, expand their partnerships and prospects at the Africa Upstream, Gas & LNG Summit, taking place tomorrow.

Speakers include: Ritu Sahajwalla, Managing Director, Greenville LNG; Ian Simm, Principal Advisor, IGM Energy; Keith Hill, President & CEO, Africa Oil corp; Harriet Okwi, Consultant & Founder, Okwi & Partners; Immanuel Mulunga, Managing Director, NAMCOR; Martin Bawden, Business Development Manager, Zebra Data Sciences; Gbemi Otudeko, Principal, Actis; Matt Tyrrell, Chief Geologist, TROIS Geoconsulting; Philippe Herve, VP Energy, SparkCognition; Adeleye Falade, General Manager Production, Nigeria LNG; Brian Marcus, Head, Capital Management, Seplat Petroleum Development Company Plc; Tabrez Khan, Director, EMEIA Oil & Gas Transactions, Ernst & Young; Mike Lakin, Founder and Owner, Envoi, Allan Mugisha, Project Manager, Springfield E&P; Gil Holzman, President & CEO, Eco Atlantic Oil & Gas; Chryssa Tsouraki, Co-CEO, IN-VR; Gawie Kanjemba, Lawyer and Energy Specialist; Scott Macmillan, Managing Director, Invictus Energy; Gregory Germani, Managing Director, West African Gas Pipeline Company; Kadijah Amoah, Country Director, Aker Energy; Eyas Alhomouz, CEO, Petromal; Duncan Rushworth, VP Business Developmemt, Svenska Petroleum; Rogers Beall, Executive Chairman, Africa Fortesa Corporation; Oumarou Maidagi . D, Head of Exploration & Production, Ministry of Hydrocarbons; Peter Dekker, Chief Geophysicist, PetroSA; Tom Perkins, Director, Stellar Energy Advisors Limited; Yann Yangari, Head of New Business, Strategy and Intelligence, Gabon Oil; Monica Chamussa, Exploration Manager, ENH; David Boggs, Managing Director, Energy Maritime Associates Pte Ltd; Jorg Kohnert, Managing Director, Jagal; Amina Benkhadra, General Director, National Office of Hydrocarbons and Mines, ONHYM; Jeremy Asher, Chairman and Chief Executive Officer, Tower Resources plc; and Khaled AbuBakr, Executive Chairman and Co-founder, TAQA Arabia.

 

 

Oil firms troubled by heating subsidy revision for gas, firewood inclusion

Petroleum product traders are troubled by government thoughts to broaden the eligibility of heating subsidy support so that, besides heating fuel, three new categories, natural gas, firewood and pellets, are also added to the list.

Contrary to natural gas, heating fuel is overtaxed, while the encouragement, through subsidies, of firewood as a heating source does not make environmental sense given the high levels of resulting smog, petroleum industry sources have pointed out.

High levels of smog have been recorded in Greek cities during winters over the past decade or so as struggling households have sought lower-cost heating amid the recession.

Heating subsidies are already limited and barely cover the needs of underprivileged households, petroleum industry officials have noted, fearing their share of the total could diminish if other heating sources also become eligible.

Heating fuel supply for the approaching winter season began yesterday at a level of 77 cents per liter, 2 cents lower than the price level at the close of last season’s trading, in May. Heating fuel prices are forecast to remain low, sources said.

Despite the lower price level, demand was subdued on opening day, yesterday. Many consumers took advantage of last season’s price drop and are already stocked up. In addition, temperatures around Greece remain mild.

ELPE seeking greater North Macedonia market share

Hellenic Petroleum ELPE, aiming to capture a bigger share of the North Macedonian market, is currently negotiating for extrajudicial solutions that would enable the reopening of a company oil pipeline linking Thessaloniki with Skopje.

In an effort to help resolve this issue, ELPE has proposed a series of RES investments in the neighboring country as well as a conversion of its Okta refinery into a petroleum products hub facilitating distribution to the western Balkans.

December will be a crucial month for the negotiations between ELPE and North Macedonia as a verdict is scheduled to be delivered on an ELPE compensation request for 32 million dollars for a breach, by the neighboring country, of contractual obligations concerning minimum supply amounts between 2008 and 2011.

The North Macedonian oil market is dominated by two Russian companies, Gazprom and Lukoil, both gaining further ground. Gazprom supplies fuel products to North Macedonia via Serbia and Lukoil does so from Bulgaria.

US officials, seeking to inhibit the dominance of Russian energy firms in North Macedonia, have intervened to help resolve the country’s differences with ELPE.

Just days ago, a meeting on ELPE’s effort to reopen the oil pipeline was held in Thessaloniki during an official visit to the city by US Secretary of State Mike Pompeo. US government officials, Greece’s energy minister Costis Hatzidakis and North Macedonian government deputies participated.

For quite some time now, Washington has made clear its stance aiming to limit Europe’s energy dependence on Russian companies and, as a result, is promoting the ELPE oil pipeline as an alternative supply route into North Macedonia.

 

ELPE negotiating reopening of North Macedonia oil pipeline

Hellenic Petroleum ELPE, Greek government and North Macedonian officials have begun talks aiming for the reopening of an oil pipeline linking ELPE’s Thessaloniki refinery with the company’s Okta refinery in the neighboring country through an extrajudicial settlement by the end of the year.

The issue was discussed at a meeting in Thessaloniki yesterday, held on the sidelines of a visit by US Secretary of State Mike Pompeo.

At the meeting, the ELPE and North Macedonian government officials appeared keen on achieving an out-of-court settlement, sources informed.

The Greek petroleum group is seeking compensation of 32 million dollars for a breach, by the neighboring country, of contractual obligations concerning minimum supply amounts between 2008 and 2011.

ELPE has already won an older case, on the same issue, at the International Court of Arbitration in Paris for compensation worth 52 million dollars. This verdict was delivered in 2007, three years after the case was filed.

The Greek and North Macedonian sides, encouraged by the US, agreed to form a committee to work, until mid-October, on a solution that could enable the oil pipeline to reopen following a seven-year interruption, sources informed.

The officials have set a deadline to reopen the pipeline by the end of the year, sources added.

ELPE has completed all technical work needed for the oil pipeline’s relaunch, sources said. The pipeline’s use in place of oil tankers would offer drastic transportation cost cuts.

The ELPE officials updated North Macedonia’s government officials on the company’s investment plan for the neighboring country, sources said. It is believed to include RES investments and a conversion of ELPE’s Okta facilities into a petroleum products hub that would serve the western Balkans.

ELPE is already present in Serbia and Montenegro and is now targeting the markets of Albania and Kosovo for supply of ready-to-use petroleum products.

The oil pipeline stopped operating in 2013 after ELPE deemed its Okta refining activities were no longer feasible. The 213-km pipeline has a 350,000-metric ton capacity.

Until 2013, the pipeline was used to transfer crude oil from ELPE’s Thessaloniki refinery to the Okta unit in Skopje.

Greek energy minister Costis Hatzidakis chaired yesterday’s meeting, which involved the participation of secretary-general Alexandra Sdoukou; deputy minister for economic diplomacy Kostas Fragogiannis; ELPE president Giannis Papathanasiou; ELPE chief executive Andreas Siamisiis; North Macedonian government deputies Liupko Nikolovski and Fatmit Bitikji; the country’s economy minister Kreshnik Bekteshi; US Assistant Secretary of State for Energy Resources Francis Fannon; and the US Ambassador to North Macedonia Kate Marie Byrnes.

Greece is ‘hydrocarbon-promising, strategically located’

By Mr. Tassos Vlassopoulos

CEO of Hellenic Petroleum (ELPE) Upstream

Greece has an old connection with hydrocarbons. More than 2,500 years ago, Herodotus mentioned the famous oil seep in Keri Zakynthos that still brings oil to the surface.

However, this connection is not only ancient. Besides the still producing Prinos Oil field and the verified West Katakolo Oil and Gas field, recent exploration activity has generated interest in the Greek hydrocarbons sector.

Oil and gas exploration began prior to the 2nd World War and intensified in late 70s to late 90s. A new turn was taken after 2015, as the collection of some new data was completed, prompting the proposal of new ideas.  International oil companies (e.g. TOTAL, ExxonMobil, Repsol, Edison), proceeded in several ventures in Greece and ELPE Upstream became an attractive partner.

Greece’s west, both onshore and offshore, seems to share many similarities with well-established Albanian and Italian hydrocarbon areas. In addition, following recent discoveries in our broader region, blocks around Crete were carved out. Total, Exxon and Hellenic Petroleum will be exploring their deep waters.

Greece is still considered an under-explored area despite the fact that more than 70,000 km of 2D and 2,000 km2 of 3D seismic lines have been acquired in addition to about 100 wells that have been drilled. However, recent technological developments enable feasible exploration of deeper waters, assuming the prospects are promising.

Greece, apart from being a hydrocarbons-promising area, is also strategically located in the middle of Mediterranean. The country is situated at the crossroads for transporting gas, from the current or future producing fields in the Caspian and the Eastern Mediterranean, to Western Europe. IGB (Gas Interconnector to link Greece with Bulgaria), Poseidon, TAP and East-Med are at different stages of development, They will link Greece and Europe’s west with all producing regions in proximity and provide potential leverage for potential developments in the regions of western Greece and Crete.

Oil and gas remains a key element of the energy mix, though the discussion on climate change continues and renewable energy solution costs have been declining. Natural gas is the transitional fuel, as we move away from coal and trend towards renewables. Electric vehicles are penetrating selected markets but not yet on a large scale, globally. Oil remains the main fuel for all other modes of transportation and petrochemicals have no real alternatives in the foreseeable future.

Tension rises as Turkish vessel enters Greek continental shelf

The situation concerning the Turkish research vessel Oruc Reis, which entered the easternmost point of the Greek continental shelf yesterday, is unchanged today, the Athens-Macedonian News Agency has reported.

Oruc Reis is accompanied by Turkish naval units, while the situation is being monitored by the Greek Armed Forces, the Greek news agency has reported.

Tension has re-escalated in the east Mediterranean since yesterday afternoon, with Turkey disputing, in practice, the Greek-Egyptian EEZ agreement through the presence and maneuvering of its Oruc Reis research vessel and Turkish warships.

Turkish survey systems are believed to be ready for application, but, according to Greek estimates, research work cannot proceed as a result of noise being generated by nearby ships, both Greek and Turkish.

Greek navy units, lined up opposite the Turkish ships, are seeking to prompt a Turkish withdrawal. The Greek Air Force and Army are also on standby.

Posting on Twitter, Cagatay Erciyes, a senior Turkish Foreign Ministry official, noted that Greece has created problems because of a 10-square-kilometer Greek island named Kastellorizo, which lies 2 kilometers away from the Turkish mainland and 580 kilometers from the Greek mainland.

“Greece is claiming 40,000 km2 of maritime jurisdiction area due to this tiny island and attempting to stop the Oruc Reis and block Turkey in the eastern Mediterranean.

“This maximalist claim is not compatible with international law. It is against the principle of equality. Yet Greece is asking the EU and US to support this claim and put pressure on Turkey to cease its legitimate offshore activities. This is not acceptable and reasonable,” he said.

Cyprus has responded by issuing a Navtex of its own, effective from today until August 23, through which it notifies that the Turkish research vessel Oruc Reis and accompanying vessels are conducting illegal operations within Cyprus’ EEZ.

Prinos field rescue effort now at the finance ministry

A government effort to rescue offshore Prinos, Greece’s only producing field, in the north, is now in the hands of the finance ministry following preceding work at the energy ministry, sources have informed.

The field, like the wider upstream industry, has been impacted by the pandemic and plunge in oil prices.

Deputy finance minister Theodoros Skylakakis is now handling the Prinos rescue case following the transfer of a related file from the energy ministry.

According to the sources, three scenarios are being considered. A financing plan through a loan with Greek State guarantees appears to be the top priority. A second option entails the utilization of an alternate form of state aid. The other consideration involves the Greek State’s equity participation in the Prinos field’s license holder, Energean Oil & Gas.

The European Commission will need to offer its approval to any of these options as they all represent forms of state aid.

Energy ministry sources have avoided offering details but are confident a solution is in the making.

Ministry OKs environmental study for blocks south of Crete

Energy minister Costis Hatzidakis has approved a strategic environmental impact study concerning an offshore area south of Crete in preparation for tenders to offer exploration and production licenses for two blocks covering most of the island’s width.

Giannis Basias, the former head official at EDEY, the Greek Hydrocarbon Management Company, went ahead with the strategic environmental impact study last August to clear the way for government authorities to stage tenders for licenses and also spare  winning bidders of needing to wait for pending issues to be resolved before they can begin their exploration efforts.

In addition, it is believed EDEY took swift action for the environmental impact study covering the offshore area south of Crete in response to interest expressed by oil majors.

The two offshore blocks south of Crete measure a total of 33,933 square kilometers and cover all four prefectures spread across the island.

These vacant blocks are situated next to two blocks southwest and west of Crete that have already been licensed out to a three-member consortium headed by Total with ExxonMobil and Hellenic Petroleum as partners.

The eastern flank of these two blocks is intruded by a corridor defined in a recent Turkish-Libyan maritime deal.

The Greek energy ministry’s approval of the strategic environmental impact study for south of Crete is not linked to Turkey’s heightened provocations in the Aegean Sea, ministry officials told energypress.

The environmental study’s approval means this offshore area is now set for tenders and also sends out a signal of readiness to the international upstream industry, the ministry officials explained.

Just days ago, the newly appointed EDEY administration and the energy ministry’s secretary-general Alexandra Sdoukou met with officials of Total, operator of the consortium holding the two licenses southwest and west of Crete. Seismic surveys for these blocks will be completed by March next year, the Total officials appear to have promised.

New leadership at hydrocarbon management company EDEY

The Greek Hydrocarbon Management Company (EDEY), an independent company owned by the Hellenic Republic that oversees and manages the nation’s oil & gas exploration & production, investor relations and a growing portfolio of international energy infrastructure projects, has announced the appointment of a new chairman of the board of directors and a new chief executive. 

The appointments by Prime Minister Kyriakos Mitsotakis, follow the nomination by Greece’s energy minister Costis Hatzidakis and endorsement by the Special Permanent Committee on Institutions and Transparency of the Hellenic Parliament.

In a statement, the Minister of Environment and Energy, Costis Hatzidakis, noted that the appointments “mark a new chapter for the company, which now has an expanded role following the absorption of a number of International trans-boundary gas pipeline projects, such as the Greek-Bulgarian (IGB) pipeline, IGI Poseidon and East Med – projects supported by inter-governmental agreements between several countries in the Mediterranean region that will strengthen European security of supply as well as Greece’s role as a protagonist nexus in some of the region’s most important strategic developments.” 

The newly appointed chairman, Rikard Scoufias, who joins the company in a non-executive capacity from a distinguished energy and extractives career in Europe, the Americas, Asia and Africa, commented: “This is an important moment in the history of EDEY. Strong corporate governance, especially environmental and social governance (ESG), is in unprecedented focus, nowhere more so than the energy and extractive sectors. It is a privilege to be asked to lead such an eminent board of directors, with distinguished careers from Greece, Norway, the Netherlands, Cyprus, Denmark and the United Kingdom, and we all look forward to work closely with the executive team and to guide the company into this new chapter of growth and continued success.”  

Aristofanis Stefatos, EDEY’s newly appointed CEO, who returns to Greece following a successful executive career in Norway’s oil and gas industry, where he served as COO, CEO and in non-executive roles noted: “Τhe opportunities that hydrocarbon exploration and production offer Greece are significant. By securing these opportunities today, we position the country for the widest possible strategic choices for the future – including the delivery of Greece’s committed plans for alternative energies and long-term decarbonization. We will achieve this ensuring that EDEY is widely recognized as an efficient, transparent and dedicated partner to investors and all stakeholders, whilst at the same time holding those partners to the highest international environmental and social standards.” 

International investors link up for Timor-Leste Oil & Gas summit

The ​Timor-Leste (East Timor) Oil & Gas Online Summit​, organised by IN-VR and under the endorsement of ANPM, Timor-Leste’s petroleum and minerals authority, took place on July 9, bringing together international investors together with the government, IOCs and key service providers.

The summit was sponsored by SundaGas​, ​Pacific Towing​, ​Vieira De Almeida​, ​TIMOR GAP​, ​CGG​, ​GLJ and ​Clifford Chance​.

H.E. Dr. Victor da Conceicao Soares, Minister of Petroleum and Minerals opened the summit welcoming investors and operators. He was followed by Dino da Silva, President of ANPM, who gave an overview of Timor-Leste’s 2nd Licensing Round, and Timor-Leste’s onshore and offshore opportunities.

“A very friendly tax system with relatively low tax rates [is offered] when compared with the average that we see not only in South East Asia, but in the world , when compared not only with the rest of South-East Asia, but even worldwide. It is clearly one of the most competitive countries in the world for the industry,” said ​Joao Afonso Fialho​, Partner and Head of Oil & Gas, VdA in his presentation on Timor-Leste’s investment environment.

“We are very nicely positioned in regards to infrastructure and transportation of gas. At the moment we are looking into having appraisal wells drilled in 2022,” noted Colin Murray, VP of Technical, Sundagas when discussing the Chuditch gas discovery and SundaGas’ progress within only one year of signing a PSC with Timor-Leste.”

“We look forward to establishing a similar relationship with Timor-Leste. In fact, it’s essential to the success of any marine business and essential to us. A strong relationship with the government is a critical component to our investments,” said ​Neil Papenfus​, General Manager of Pacific Towing, on comparing the company’s success in Papua New Guinea and investing in Timor-Leste.

“Timor-Leste has chosen the best solution, making access to its data free for interested investors, a model that works well for frontier countries,” commented Martin Bawden, Business Development Manager of Zebra Data, when asked about ANPM’s usage of their Virtual Data Room service.

ANPM, IOCs and investors renewed their meeting for the ​2nd Timor-Leste Oil & Gas Summit​ in Dili, Timor-Leste in 2021.

US backs Greece’s east Mediterranean activities, major projects

All countries in the east Mediterranean region must carry out their activities in accordance with international law, including the International Law of the Sea as stipulated by the 1982 United Nations Convention on the Law of the Sea, the Greek and US governments have jointly announced following a high-level virtual conference held yesterday on energy issues.

This statement clearly offers US support for the positions of Greece, facing Turkish provocation.

The working group’s participating Greek and US officials reiterated the commitment of the two countries to cooperate on the effort to diversify energy sources in southeast Europe, collaborate with regional partners for energy source development, and promote regional energy security.

The latest energy working group builds on steadily growing bilateral cooperation following Greek-US strategic dialogue meetings in December, 2018 and October, 2019, the joint announcement added.

The Greek team was represented by the Ministry of Foreign Affairs’ Deputy Minister for Economic Diplomacy and Openness Kostas Frangogiannis and Deputy Environment and Energy Minister Gerassimos Thomas (photo). The US team was represented by Assistant Secretary of State for Energy Resources Francis Fannon and Under Secretary of Energy Mark Menezes.

Fannon, the Assistant Secretary of State, expressed satisfaction on the completion of the Greek segment of the TAP gas pipeline project, to carry Azeri gas to Europe.

The US official also offered support for the ongoing construction of the Greek-Bulgarian IGB gas pipeline interconnection and the progress achieved in plans for an FSRU in Alexandroupoli, northeastern Greece, a South Kavala underground gas storage facility, and Greek-North Macedonian connection.

Petroleum sector rebounding, Motor Oil deputy tells

The petroleum market is now rebounding, a trend reflected by rising sales figures in May, Motor Oil’s deputy chief executive Petros Tzannetakis has told analysts during a virtual conference.

The official, responding to a related question, expressed cautious optimism for the petroleum sector’s performance this coming summer.

“Greece’s successful management of the pandemic can attract tourists. The borders have been opened and, at the same time, demand for gasoline is rising. I am cautiously optimistic,” Tzannetakis said.

It is currently not possible to make predictions on aviation fuel demand, he noted.

Motor Oil proved to be durable and resilient amid the pandemic’s unprecedented demand and price collapse for petroleum products, the deputy chief noted. The  corporate group’s major debt reduction and high-level liquidity played a key role, he pointed out.

Record sales figures in preceding years contributed to the corporate group’s resilience during the lockdown period, he explained.

Gov’t committed to Prinos oil field sustainability, deputy tells

The government is committed to supporting the sustainability of the offshore Prinos oil field in the country’s north, Greece’s only producing unit, heavily impacted by the coronavirus pandemic’s effects on the global economy, including record-low oil prices, deputy energy minister Gerasimos Thomas pledged last night in response to questions raised by MPs of the leftist Syriza party and KKE, the Greek Communist Party.

“We are committed to the oil field’s uninterrupted production, an effort through which jobs will be protected,” Thomas stated.

The government is currently negotiating with Energean Oil & Gas, license holder and operator of the offshore field, south of Kavala, for a solid solution, the deputy minister also informed.

A detailed announcement will be made once these talks have been completed and the government has shaped its proposals, the deputy minister told parliament after Syriza MP Soultana Eleftheriadou criticized him for being too vague with his remarks.

Thomas made note of the European Commission’s new framework for state aid as one of the solutions being worked on by the government. This framework provides flexibility, he pointed out.

The deputy minister also made reference to a government support plan for the Kavala region that includes the development of an underground gas storage facility at a virtually depleted offshore gas field south of Kavala, and an upgrade of the city’s port.

Argentina oil, gas energy online summit planned for May 12

IN-VR is organizing the ​Argentina Oil, Gas & Energy Summit under the Endorsement of the British Argentine Chamber of Commerce, taking place completely online on May 12, 2020.

The event, gathering key authorities and investors, will focus on Argentina’s plans in the current oil price landscape, the COVID-19 impact on the market, Vaca Muerta, one of the largest shale formations in the world, and Argentina’s LNG plans.

The summit will gather government officials, key IOCs, investors and service providers that will discuss these topics and network with attendees online in sessions and private B2B meeting rooms.

All profits from tickets will be donated to ​NGOs and charities that support doctors combating the coronavirus and groups most affected in Argentina​.

Key topics on the agenda: 

● How will the current oil price landscape affect Argentina?
● How will the coronavirus affect Argentina?
● Argentina’s shale oil government policies
● Identifying E&P opportunities in Vaca Muerta
● Service provider opportunities in Vaca Muerta
● Argentina’s future plans for LNG
● What are the best companies to partner with in Argentina?
● Q&A: How do foreign investors view Argentina’s oil & gas industry?
● Human resources needs in Vaca Muerta and Argentina.

Presenters:

● Daniel Dreizzen, ​Former Secretary of Energy Planning, Argentina
● Jimena Blanco, Head of Americas, ​Maplecroft
● Gabriela Aguilar, General Manager, ​Excelerate
● Diego Garcia, Partner, ​Bain
● Claudio Spurkel, Global Sales Business Development Manager, ​Agira
● Mark LaCour, Oil & Gas Expert & Editor in Chief, ​Oil and Gas Global Network

For further information visit:
https://www.in-vr.co/argentina-online

Or contact:
felix@in-vr.co

 

 

 

Energean’s Competent Persons Report for Karish North completed

Energean Oil and Gas, the oil and gas producer focused on the Mediterranean, has announced the completion of an independent Competent Persons Report by DeGolyer and MacNaughton (D&M) on the Karish North Field, offshore Israel, and submission of an addendum to the Field Development Plan (FDP) to the State of Israel’s Ministry of Energy for Karish North.

Highlights

  • Karish North certified to contain gross 2C resources of 1.2 Tcf (33.7 bcm) of gas and 39 million barrels of liquids (mmbbls). This represents a total of 250 million barrels of oil equivalent (mmboe), of which 84% is gas. 
  • Delivers a 32% uplift to Energean’s previous Karish North resource best estimate, including approximately 0.3Tcf (9 bcm) of gas plus 5mmbbls of liquids, a total of approximately 60 mmboe (of which 90% is gas).
  • Total gross 2P + 2C across the Karish, Tanin and Karish North  is now estimated to be almost 3.5 Tcf (99 bcm) of gas plus 82 mmbbls of liquids, a total of  698 mmboe (88% of which is gas).
  • 0.6bcm/yr contingent Gas Sales and Purchase Agreements (GSPAs) will now be converted to firm; firm GSPAs will now deliver approximately 5.6bcm/yr of gas sales on plateau, with FPSO capacity of 8bcm/yr.
  • Energean continues to actively market additional gas volumes to secure additional long-term cash flows that are largely insulated from global commodity price fluctuations.
  • Energean has also submitted an addendum to the Karish and Tanin FDP, to cover the Karish North development, envisaging a production capacity of up to 300mmscf/d (approximately 3 bcm/yr), initially from one well.
  • Karish North Final Investment Decision (FID) expected during 2H 2020 with first gas in 2022.

Mathios Rigas, CEO of Energean said:

“I am delighted that 2C resources atKarish North are some 32% ahead of where we had initially expected. This has enabled us not only to convert 0.6bcm/yr of contingent contracts into firm, but also to continue targeting additional gas sales opportunities that will be incremental to the 5.6bcm/yr of firm gas sales that we now expect to deliver on plateau.We are very pleased to be developing a world-class gas resource of 700 millionboe and look forward to more gas discoveries in our acreage in Israel and the wider Eastern Med region.” 

Details of D&M CPR

Reserves & Resources

Following a full analysis of the results of both the Karish North discovery well and the side-track, D&M has certified that the Karish North field contains gross 2C contingent resources of 1.2Tcf (33.7 Bcm) of gas plus 39.4 million barrels of liquids (Energean 70%), a total of approximately 250mmboe. This represents a significant uplift of 0.3 Tcf (8.5 Bcm) of gas plus 5.4 million barrels of liquids (approximately 60mmboe) to Energean’s previous best estimate of Karish North volumes. Best estimate Gas Initially In Place (GIIP) is now 1.7Tcf (approximately 48 bcm).

Gross and working interest 1C, 2C and 3C are shown in the tables below.

In the CPR, Karish North resources are classified as contingent ahead of FID being taken on the project, which is expected during 2H 2020. Once FID has been taken resource volumes are expected to be reclassified as reserves, to the extent that they are underpinned by GSPAs.

D&M’s estimates are based on the results of the Karish North exploration and appraisal campaigns that were completed in 2019, coupled with an analysis of the recently re-processed and re-calibrated 3D seismic. The uplift in resource volumes largely results from the new conclusion that the Karish East structure is a part of the Karish North and Karish North-East structures, which were included in Energean’s original resource estimates. Following analysis of the re-processed and re-calibrated 3D seismic, Energean’s internal view is aligned with that of D&M, that Karish North, Karish North-East and Karish East form one structure.

Revised Gross Contingent Resource Volumes

Liquids

mmbbls

Sales Gas

Bcf

Sales Gas

Bcm

Total Oil Equivalent

mmboe

1C

21.4

642.7

18.2

135

2C

39.4

1,190.8

33.7

250

3C

55.6

1,701.7

48.2

357

Revised Working Interest Contingent Resource Volumes

Liquids

mmbbls

Sales Gas

Bcf

Sales Gas

Bcm

Total Oil Equivalent

mmboe

1C

15.0

449.9

12.7

95

2C

27.6

833.6

23.6

175

3C

38.9

1,191.2

33.9

250

Total, independently verified gross 2P reserves and 2C resources in the Karish and Tanin leases (Energean 70%) are now 3.5Tcf of gas (98.6 Bcm) and 82 million barrels of liquids, a total of approximately 698 million barrels of oil equivalent. Total gross recoverable 2P + 2C across theKarish and Tanin leases is presented in the following table.

Revised Gross 2P Reserve + 2C Resource Volumes

Liquids

mmbbls

Sales Gas

Bcf

Sales Gas

Bcm

Total Oil Equivalent

mmboe

Karish[1]

38.5

1,503.6

42.6

305

Karish North3

39.4

1,190.8

33.7

250

Tanin2

4.1

785.9

22.2

143

Total

82.0

3,480.3

98.6

698

Revised Working Interest 2P Reserves + 2C Resources

Liquids

mmbbls

Sales Gas

Bcf

Sales Gas

Bcm

Total Oil Equivalent

mmboe

Karish[2]

27.0

1052.5

29.8

213

Karish North3

27.6

833.6

23.6

175

Tanin2

2.9

550.1

15.5

100

Total

57.4

2436.2

69.0

489

Commercial & Financial Impact

Finalisation of the CPR results in the conversion of 0.6bcm/yr of conditional GSPAs to firm contracts. Energean Israel’s firm GSPAs now deliver sold volumes of 5.6bcm/yr on plateau. The CPR enables Energean to continue marketing its gas resources into the growing Israeli domestic market and key regional export markets, securing additional long-term cash flows that are largely insulated from global commodity price fluctuations.

Updated FDP

Energean has also submitted an addendum to the Karish and Tanin FDP, to cover theKarish North development, to the State of Israel’s Ministry of Energy Technical Department. Energean expects to take Final Investment Decision (FID) on the project in 2H 2020, with first gas expected during 2022. The FDP addendum envisages that two wells will be required to develop the greater Karish North structure. Phase 1 of the Karish North development will include the drilling of one well, tied back to the Energean Power FPSO, for the delivery of first gas in 2022. Phase 2 will include the drilling of a second production well around 2025, to optimise gas recoveries. The FDP allows for the production of up to 300mmscf/d through a dual flow line, which it is envisaged can be produced by a single well to start off with; Karish North reservoir properties are similar to those at Karish main. 

Energean is a London Premium Listed FTSE 250 and Tel Aviv 35 Listed E&P company with operations offshore Israel, Greece and the Adriatic. In March 2018, Energean took Final investment Decision on its flagship Karish and Tanin development, offshore Israel, which, following the discovery of Karish North, is estimated to contain approximately 700 million barrels of oil equivalent (Energean plc 70%), of which 88% is gas. Energean Israel’s firm Gas Sales and Purchase Agreements now deliver sold volumes of 5.6bcm/yr on plateau, providing sustainable, long-term cash flows that are underpinned by hard floor pricing and take-or-pay provisions.

Energean also has nine exploration licences offshore Israel, and a 25-year exploitation licence for the Katakolo offshore block in western Greece and additional exploration potential in its other licences in western Greece and Montenegro.

On 4 July 2019, Energean announced the conditional acquisition of Edison E&P for $750 million plus $100 million of contingent consideration. On 3 April 2020 it was announced that the acquisition agreement had been amended to exclude Edison E&P’s Algerian assets, accompanied by a reduction to the consideration of approximately $150 million. On 14 October 2019, Energean announced the conditional disposal of Edison E&P’s Norwegian and UK North Sea assets to Neptune Energy for $250 million plus $30 million of contingent consideration. These transactions are expected to close in 2020.

Energean to utilize measures for crisis-hit Prinos field

Energean Oil & Gas, whose offshore Prinos oil field in the country’s north has been heavily impacted by the coronavirus pandemic’s effects on the global economy, including record-low oil prices, intends to utilize relief measures offered by the Greek government for various sectors, including the upstream industry.

The government’s relief measures, introduced to help enterprises weather the financial impact of the unprecedented coronavirus crisis, promise respite in a variety of forms, including tax payment delays, VAT discounts as well as employee allowances covering suspended work contracts.

Energean, which has invested tens of millions of euros to keep upstream  activities alive in Greece, now needs to reduce its Prinos operating costs and keep production flowing. A disruption of production and resumption at a latter date is not technically feasible. Prinos is Greece’s only producing oil field.

The oil price plunge has made big impact on the Prinos field, an old high-cost venture whose production costs are estimated at 21.5 dollars per barrel.

This specific field produces heavy crude of higher refining demands. Subsequently, Energean sells the unit’s output to BP at price levels that are between 7 and 8 dollars lower per barrel compared to Brent prices.

Production at Prinos is declining. Output peaked at 4,000 barrels per day in 2018 but fell to 3,300 in 2019 and is projected to slide further in 2020, officials noted.

Energean has cut back on investments at Prinos by 80 million dollars.

International crude prices plunged from 66 dollars to less than 25 dollars per barrel in the first quarter. Prices have not fallen so low since 2003.

 

Crisis impacting energy sub-sectors in different ways

Energy companies are not being impacted in a universal way by the impact of the coronavirus pandemic, its effects varying from one sub-sector to another, as was made clear during conference-call presentations of 2019 financial results by two different types of firms, Motor Oil, active in refining and fuel trade, and Mytilineos, whose interests include energy production and supply.

Motor Oil needs to counter lower international oil prices, lowered by the coronavirus outbreak combined with a price war between Russia and Saudi Arabia. Oil prices may have fallen but fuel demand is expected to slide further as stricter coronavirus stay-at-home orders are enforced.

The main challenge for Motor Oil is to maintain liquidity at levels ensuring sustainability.

As for the corporate group Mytilineos, represented by Protergia in the retail energy market, it has yet to experience a drop in electricity demand. Italy, hardest-hit by the coronavirus in Europe, has seen electricity demand drop by 7 percent.

The significant decline in natural gas prices is expected to offer Mytilineos purchase cost savings of about 99 million euros over a one-year period.

The group is continuing its development of a new gas-fueled power plant.

Despite the crisis, the Mytilineos group aims to continue operating its units at full capacity and utilize the availability of low-cost fuel.

Energean Oil & Gas continues strong growth trajectory in 2019

Energean Oil and Gas, the oil and gas producer focused on the Mediterranean, has announced its audited full-year results for the year ended 31 December 2019 (“FY 2019”). Having grown its reserve base at 39% year-on-year, Energean is now at its next transition point as the company begins converting this into cash flows and production, de-risking investment case and moving closer to the medium-term goal of paying a sustainable dividend, the company noted in a statement.  

Mathios Rigas, Chief Executive Officer, Energean Oil & Gas commented:

“Energean continued its strong growth trajectory in 2019, becoming firmly established as a leading, FTSE 250 E&P independent. 

“The COVID-19 pandemic and OPEC+ price war have put us into uncertain times, but we are well-placed to weather the challenges. Once the Edison E&P transaction is completed, around 70% of our production will be sold under long-term gas sales agreements that insulate our future revenues against oil price volatility. Following completion of the Edison E&P transaction, we will continue to own and operate the majority of our asset base, and are well-funded for all of our projects. This will ensure that we can respond quickly and appropriately to the macro environment and take the right decisions to protect our business and our shareholders, as demonstrated by the $155 million cut to our 2020 capex guidance. The crisis finds Energean well prepared with full discretion on our non-Israeli capex programme and a very strong balance sheet further strengthened only recently by a further $175 million committed funding for our Karish project, demonstrating the strength of our banking relationships and the commitment of our lenders to the project. 

“In the coming weeks, you will see our FPSO hull sailaway from China to Singapore, a key milestone in the delivery of first gas from Karish, which is on track for 1H 2021. During 2019 we completed the drilling of the three development wells of Karish, confirmed excellent productivity rates from the wells and made a new discovery (Karish North) in Israel that we intend to develop in 2021. We continued to gain market share in Israel securing additional long-term gas contracts and bringing us closer to our target to maximise capacity utilisation of our FPSO. We expect the Edison E&P transaction to close during 2020, which, based on the agreed locked-box date of 1 January 2019, allows us to benefit from the robust results delivered by the business during 2019, including $152 million of Free Cash Flow from the assets to be acquired. This, combined with the receivables recovered in Egypt, exclusion of the Algerian assets from the transaction perimeter and our onward disposal of the North Sea assets to Neptune Energy, contributes to a low effective purchase price.  

“Fully committed to lead also on the ESG front, Energean became the first E&P company globally to commit to net zero emissions by 2050, and we have a firm plan to reduce carbon intensity by 70% over the next three years. 

“I look forward to continuing to deliver positive momentum and sustainable growth to maximise value for all of our stakeholders”.  

Highlights

  • Karish was 72% physically complete at 31 December 2019 and remains on track to deliver first gas in 1H 2021.  Firm gas sales of 5.0 bcm/yr with a further 0.6 bcm/yr to be converted to a firm basis immediately on publication of a satisfactory Karish North CPR, expected at the end of March 2020.
  • Post-period end, two of the three Karish development wells successfully flowed during clean-up operations, confirming that each will be capable of delivering up to the design limit of 300 mmscf/d (c.3 bcm/yr). The third development well is currently in the clean-up phase and production performance is expected to be similar, confirming that the three wells will be able to produce to the 8 bcm/yr capacity of the FPSO.
  • Increased 2P reserves and 2C resources to 558 MMboe, representing a 39% year-on-year increase, before any contribution from the Edison E&P acquisition. Energean is at a transition point in its history, from which it will convert this growth in reserves to growth in production and cash flow.
  • 2019 average Working Interest production was 3.3 kbopd from the Prinos field. Cost of production was approximately $21.5 /bbl.
  • 2019 full year revenue  was $76 million. Adjusted EBITDAX was $36 million. Capital expenditure was $685 million.
  • Recognised a $71 million impairment charge on the Prinos area, reflecting a reduction in Energean’s oil price assumptions and a change in the Group’s Prinos field production forecast.
  • Energean retains significant liquidity. At 31 December 2019, Energean had cash and undrawn facilities of $834 million, excluding the undrawn $600 million acquisition bridge facility.
  • Became the first E&P company globally to commit to net zero emissions by 2050 and have a firm plan to reduce carbon intensity by 70% over the next three years.

 

Financial Summary 

 

FY 2019

FY 2018

 

$m

$m

Sales revenue

75.7

90.3

Cost of production ($/boe)

21.5

17.6

Operating profit / (loss)

(93.9)

23.8

Adjusted EBITDAX

35.6

52.4

Operating cash flow

36.3

62.7

Capital expenditure

685.1

494.6

Cash capital expenditure

954.6

293.6

Net debt (cash)

561.6

(75.6)

 Edison E&P Acquisition (subject to closing)

  • In July 2019, Energean agreed to acquire Edison E&P for $750 million of up-front consideration, adding immediate cash flows, EBITDAX and incremental growth opportunities. In October 2019, Energean agreed to sell Edison E&P’s UK and Norwegian subsidiaries to Neptune Energy for $250 million of up-front consideration.
  • Raised $265 million of equity and $600 million of bridge financing to fund the acquisition. The take-out of the bridge facility using a Reserve Based Lending (“RBL”) Facility of up to $525 million plus a bridge to disposal of up to $250 million for the UK and Norway Assets is progressing as expected.
  • Carve out of the Algerian assets from the transaction perimeter has been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.
  • Excluding Algeria, UK and Norwegian subsidiaries, Edison E&P delivered Free Cash Flow of $152 million during 2019.
  • Exclusive of Algeria and the UK and Norwegian subsidiaries, 2019 average Edison E&P working interest production was 56 kboe/d (64 kboe/d inclusive of these assets).
  • In January 2020, Edison E&P received the updated Environmental Impact Assessment (“EIA”) approval on the Cassiopea development, offshore Italy. The development is progressing as planned with first gas expected in early 2023. 

Outlook

  • Closing of the Edison E&P acquisition and subsequent sale of the UK and Norwegian subsidiaries to Neptune Energy will occur once the remaining conditions precedent to the transaction are fulfilled, which is expected during 2020. Energean is working with Edison E&P to fulfil these conditions precedent as soon as possible.
  • The Energean Power FPSO hull for the Karish gas project is expected to sailaway from China to Singapore in the coming weeks, and from Singapore to Israel around YE 2020.
  • Energean expects to issue an updated CPR for the successfully appraised Karish North discovery, around end 1Q 2020. An updated Field Development Plan (“FDP”) will be submitted to the Israeli government in 2Q 2020.
  • 2020 pro forma group production (including the assets to be acquired from Edison E&P) is expected to be between 42.5 – 50.0 kboe/d. Production in the first two months of 2020 averaged 52.4 kboe/d.
  • 2020 pro forma consolidated group capital expenditure (including the assets to be acquired from Edison E&P) of $840 million, an adjustment to the net consideration, the quantum of which is being agreed, on previous guidance following actions taken by management in the last two weeks. $580 million will be spent in Israel and $140 million is fully discretionary.
  • Decisions on FID at Katakolo (Greece) and Drill or Drop on both Ioannina (Greece) and Montenegro; outstanding financial commitment across these licences of $1 million.
  • Strategic review of the Prinos Area assets progressed; results expected in 2020. Capital expenditure on the assets, including Epsilon, will be minimised whilst the review is concluded. 

Operational Review 

Business Resilience and Current Response to the Macro Environment

Energean notes the recent fall in global oil prices and highlights its resilience to fluctuations in the global commodity prices. In addition, Energean has not currently suffered any delays due to the Coronavirus.

Defensive Reserve and Production Mix

  • 70% of Energean’s 2P reserve and 2C resource base will be gas once the Edison E&P transaction completes.
  • Once the Edison E&P transaction completes, around 70% of 2020 – 2025 expected production and 60% of Energean’s 2P and 2C reserve and resource base is gas that will be sold under Gas Sale & Purchase Agreements (“GSPAs”) that are largely insulated from fluctuations in the Brent price:
    • Israel gas is expected to account for 34% of 2020 – 2025 expected production and 49% of the reserve and resource base. Israel gas is sold subject to long-term GSPAs with some of the largest domestic independent power plant and industrial customers. All GSPAs have floor pricing and take-or-pay provisions, with no price no re-openers. One contract that has a limited amount of Brent exposure, representing less than 2% of current contracted gas sales.
    • Egypt gas[3] is expected to account for 37% of 2020 – 2025 expected production and 16% of the reserve and resource base. This gas is being sold to EGPC under the concession agreement. In Abu Qir, at prices of between $40 and $72 Brent, the gas price is $3.50 / mmBTU ($3.71/mcf). At $35/bbl, the gas price is $3.16 / mmBTU ($3.35/mcf). In NEA, the gas price has been agreed at a $4.60/mmBTU ($4.77/mcf). At prices between $40 and $25, the gas price gradually reduces to the floor price of $4.45/mmBTU.

Well-Funded for Current Activities and Working Capital

  • The Group retains significant liquidity and at 31 December 2019, Energean had cash of $354 million and undrawn facilities of $480 million, excluding the undrawn $600 million acquisition bridge facility. At 28 February 2020 (and after reflecting the project finance facility increase effected on 16 March 2020), Energean had undrawn facilities of $620 million, excluding the acquisition bridge facility.

Israel Project Finance Facility

  • In Israel, cash and undrawn facilities were US$555 million. On 16 March 2019, the project finance was increased to $1.45 billion, providing an additional $175 million of liquidity for the Karish project and future appraisal activity in Israel. The project finance facility aids the defensive nature of Energean’s funding position and is largely unaffected by volatility in the oil price because:
    • It is non-recourse to the parent;
    • There are no redeterminations for the duration of its tenor;
    • Interest payments and other project costs are covered by the sizing of the facility; and
    • Due to the nature of the GSPAs underpinning the Karish and Tanin projects’ revenues, fluctuations in the oil price do not materially affect the cashflow covenants in the facility.
  • Energean’s Karish development is being executed largely through a lump-sum, turnkey EPCIC contract with TechnipFMC, which helps to protect the Company against capital expenditure overruns.
  • Liquidated damages payable by the Company resulting from any potential delay to the project are broadly back-to-back with any liquidated damages payable to gas buyers that may arise from late delivery of first gas. This limits Energean’s commercial exposure to any future delay. 

Funding position ex-Israel

  • Energean’s business excluding Israel had cash and undrawn facilities of $279 million at 31 December 2019.

Flexibility over capital investment programme

  • The Prinos Basin and Katakolo assets are fully-owned and operated, providing absolute flexibility over discretionary capital expenditure.
  • Energean’s exploration assets have minimal outstanding firm commitments, again giving Energean flexibility over capital expenditure.
  • Energean’s 2020 capital expenditure guidance benefits from strong funding and its discretionary nature:
    • 2020 pro forma consolidated group (including the proposed acquisition of Edison E&P) capital expenditure has been reduced to $840 million, from $995 million. The majority of this decrease is due to i) deferral of Cassiopea[4] expenditure; ii) deferral of Epsilon expenditure; and iii) deferral of the $35 million Zeus exploration well; results from the Karish North CPR are expected to be sufficient to ensure that Energean has enough gas to be able to participate in upcoming GSPA opportunities in Israel. This has allowed Energean to defer investment and conserve capital without impacting potential cash flow-driven returns for its shareholders.
    • $580 million relates to Karish development and is funded by the project finance facility.
    • A further $140 million is fully discretionary for 2020, principally relating to capital expenditure in Egypt and various projects in Italy. 

Israel

Karish-Tanin development project

Energean is on track to deliver first gas from its Karish project in 1H 2021. As of 31 December 2019, physical progress on the project was approximately 72% complete, the drilling of the three Karish Main development wells had been completed and significant progress had been made on the hull and topsides of the Energean Power FPSO. The FPSO Hull is expected to sailaway from China to Singapore in the coming weeks, signalling delivery of a key intermediate milestone towards delivery of first gas in 1H 2021. 

FPSO progress and key milestones

FPSO keel laying took place successfully at the COSCO Yard, Zhoushan, China, in April 2019 and in October 2019 the hull was undocked and floated out from COSCO Shipyard’s dry dock.

To date, in 2020, despite Coronavirus, the workforce in the COSCO yard has been maintained above 550 people. The FPSO Hull sailaway is expected in the coming weeks and it is due to arrive in the Admiralty Yard in Singapore shortly thereafter. Good progress has been made on construction of the topsides in Singapore, and Energean is working with TechnipFMC to mitigate the impact of the deferred sailaway from China on Practical Completion of the project and is on schedule to deliver first gas in 1H 2021. 

Gas sales and purchase agreements

During 2019, Energean agreed an additional 0.8 Bcm/yr of new and increased contracted and unconditional (“firm”) GSPAs and 0.4 Bcm/yr of contracted and conditional (“contingent”) GSPAs with gas buyers. In early 2020, a further contingent GSPA for up to 0.2 Bcm/yr was signed.

Total contracted gas sales are now as follows:

Contracted and Unconditional GSPAs

  • c.5 Bcm/yr (484 mmcfd)

Contracted and Conditional GSPAs

  • IPM Beer Tuvia: 0.4 Bcm/yr (39 mmcfd) of sales post-2024. Energean may supply additional gas pre-2024 at the option of both counterparties. The IPM contract is conditional, inter alia, on Energean certifying additional 2P reserve volumes and will be converted to firm GSPAs immediately on issuance of the Karish North CPR shortly.
  • New Contract: Up to 0.2 Bcm/yr (19 mmfcd) of sales, under which supply ramps up between 2022 and 2025. The new contract is also conditional, inter alia, on Energean certifying additional 2P reserve volumes. Energean expects the contract to be converted into firm upon publication of the Karish North CPR shortly.
  • Or Contract: 0.7 Bcm/yr (68 mmcfd) of sales to Or Power, which depends on Or Power succeeding in its application to receive a new licence from the Electricity Authority to construct a new power generation plant in Israel and successfully completing this project.

In the medium term, Energean aims to secure both the resource and offtake for the remaining spare capacity in its 8 bcma (775mmcfd) capacity FPSO, whilst bearing in mind the need for capital conservation in the current market environment. 

All GSPAs contain take-or-pay and floor pricing provisions, which reduce the risks associated with Energean’s cash flow generation profile and limit Energean’s exposure to global commodity price fluctuations. 

Energean is also evaluating gas export monetisation options, including the markets of southern Europe. As part of this strategy, the Company signed a Letter of Intent (“LOI”) in January 2020 with the Public Gas Corporation of Greece for the potential sale and purchase of 2 Bcm/yr of natural gas from Energean’s fields in Israel through the proposed East Med Pipeline. At this stage, there is no commitment to supply this gas and Energean views the LOI as a longer-term option for monetisation of its gas resources. 

2019 Drilling Campaign

During 2019, Energean drilled the KM-01, KM-02, KM-03 development wells and the Karish North exploration well and sidetrack. Completions and installation of the Christmas Trees on those three development wells was the focus of operations during 1Q 2020; clean-up of two wells is complete and one is ongoing, following which the wells will be ready for integration with the subsea infrastructure and hook up to the FPSO.

The three development wells are expected to deliver 5.0 bcm/yr (484 MMscfd) of firm contracted gas into the Israeli domestic market commencing in 1H 2021. During 2020, successful results were achieved from production measurement performed during clean-up of the KM-02 and KM-01 development wells. Both wells flowed at a maximum rate of 120 million standard cubic feet per day (MMscf/d) of natural gas, limited only by the capacity of the surface equipment. Performance modelling confirms that each well will be capable of delivering at the 300 MMscf/d design capacity when connected to the FPSO. Clean-up of the third development well, KM-03 has commenced and the results of production measurement, which are expected to be similar, will be announced to the market in due course. Energean is confident that the three development wells can produce at combined rates of 800 mmscf/d, which is sufficient to fill the capacity of the FPSO. 

The Karish North field was discovered in April 2019, with appraisal confirming initial best estimate recoverable resources of 0.9 Tcf (25 bcm) of gas plus 34 MMbbl of light oil/condensate. An independent CPR is being prepared and results will be communicated to the market shortly. On publication of this CPR, 0.6 bcm/yr of contingent GSPAs are expected to be immediately converted to firm GSPAs. The company is preparing a field development plan, envisaging a tie-back to the Energean Power FPSO. A final investment decision on that project, which is estimated to cost circa $125 million, is anticipated during 2020, with first gas during 2022. 

Exploration Programme

Energean has decided to defer its exploration activity on Block 12. Results from the Karish North CPR are expected to be sufficient to ensure that Energean has sufficient gas resources  to be able to participate in upcoming GSPA opportunities in Israel. This has allowed Energean to defer investment and conserve capital without impacting potential cash flow-driven returns for its shareholders.

The Zeus and Athena prospects remain very attractive and Energean intends to re-visit its investment decision in due course. 

Acreage

Energean also added to its Israeli acreage in 2019. The Company, as part of a joint venture with Israel Opportunity, was awarded four new licences – 55, 56, 61 and 62 – in Zone D of the Israeli EEZ. The licences are situated approximately 45 kilometres off the coast of Tel Aviv and represent a strong potential source of upside in Energean’s Israel portfolio. 

Greece

Production

At the end of 2019, Energean decided to place its Prinos area assets under strategic review, the results of which will be communicated to the market once complete.  Working interest production from Greece averaged 3,312 boepd during 2019, however, investment in Prinos, Prinos North and Epsilon will continue to be limited whilst this strategic review is concluded and 2020 production is, therefore, expected to be in the range of 2,000 to 2,500 boepd, assuming no contribution from Epsilon. Output from Prinos and Prinos North is to be maintained through rig-less activities requiring limited expenditure.

Due to higher-return capital allocation priorities, Energean no longer carries a medium-term production target for the Prinos area asset; future production will be a function of the level of investment in the assets. 

Development – 2019 Overview

During 2019, all three Epsilon Lamda platform development wells were drilled successfully. As previously announced, additional pay was encountered in the deeper and dolomitic zones of the Epsilon reservoir. This resulted in an NSAI-audited reserve and contingent resource increase of 26 MMboe, to 44 mmboe.

At Katakolo, award of the EIA is expected in 2Q 2020 with potential Final Investment Decision thereafter. NSAI-audited Katakolo reserves are 14 MMboe, a 36% increase on 2018.

The proposed underground gas storage project in South Kavala saw a positive development in 4Q 2019 when an amendment to the law was passed on 10 December 2019, making it possible for the regulating energy authority to regulate the tariff. This paves the way for a tender for the project, which is expected in 2020. On 11 March 2020, the Greek Energy and Finance Ministries signed a decision to allow the country’s state-asset sales fund to proceed with an international tender to construct, maintain and operate an underground gas storage facility at the South Kavala field, with the first step a cost-benefit study.  The right to exploit the facility will be 50 years. 

Exploration

In Ioannina, interpretation of the newly acquired seismic lines is ongoing and a drill-or-drop decision will be taken in 1H 2020. The quality of acquired seismic was a major improvement when compared to historic vintages and the lines have identified two prospective trends with multiple analogue prospects. Further, the new 2D seismic has verified the existing geological model, de-risking existing prospectivity. The seismic lines were acquired with minimal environmental impact and Energean and the operator, Repsol, have agreed to plant trees in areas away from the 2D seismic lines. The outstanding net financial commitment on the Ioannina block is less than $0.5 million.

In Aitoloakarnania, the operator, Repsol, is carrying out the necessary environmental studies in preparation for the 2D seismic acquisition campaign, which is expected to commence in 2Q 2020, subject to permitting. The outstanding net financial commitment on the Aitoloakarnania is less than $3 million.

In February 2020, Energean signed an agreement for the acquisition of Total’s 50% stake in, and operatorship of, Block 2, offshore Western Greece, providing further material exploration opportunities in its core area of the Eastern Mediterranean with limited financial exposure. Energean’s net remaining expenditure (at 50% Working Interest and post including consideration) towards satisfaction of the minimum work obligation, which includes 1800 kilometres of 2D seismic acquisition and processing, is approximately €0.5 million. Energean believes that this is a highly attractive transaction in the context of the early stage prospectivity identified on the block.

Work to date on the licence has identified that Block 2 contains part of a large four-way closure at the Top Jurassic Apulia platform. The prospect is believed to be an analogue to the Vega field, offshore Italy, which Edison E&P operates with a 60% Working Interest. The structure is covered by sparse 2D seismic and could be de-risked through the seismic acquisition programme to be executed as part of the minimum work obligation. 

Montenegro

In February 2019, Energean commissioned PGS for the acquisition of a new 3D seismic survey over Blocks 26 and 30. The PGS Ramform Titan, one of the best seismic acquisition vessels in the world, deployed 14 geo-streamers, 6.5 kilometres for each streamer length, using a triple source array to cover a total area of 338 square kilometres. The 3D seismic survey substantially fulfils the licence commitment for both blocks 26 & 30 with a net outstanding financial commitment of less than $0.5 million.

Results from the seismic survey have identified a number of shallow gas prospects and deeper carbonate prospects have been identified through interpretation of the newly acquired seismic data. Energean is awaiting final data in order to confirm the primary prospect. The Ministry of Economy in Montenegro confirmed that Energean will receive an extension to the first exploration phase to 15 March 2021, with a drill-or-drop decision due by year end 2020. 

Energean Reserves and Resources

Energean increased 2P reserves and 2C resources to 558 MMboe, up 39% year-on-year, before any contribution from the Edison E&P acquisition. Energean’s reserves and resources benefitted from two discoveries during 2019, the Karish North discovery in Israel, which added 190 mmboe, and the Epsilon Deeper and Dolomitic Zones, which added 25 mmboe. 

Israel

Greece

Total

Oil

Gas

Total

Oil

Gas

Total

Oil

Gas

Total

Commercial Reserves

mmbbls

Bcf

mmboe

mmbbls

Bcf

mmboe

mmbbls

Bcf

mmboe

1 January 2019

22

1,558

298

49

5

49

71

1,563

347

Revisions

7

(99)

(11)

8

1

8

15

(98)

(3)

Disposals

Transfer from contingent resources

(2)

(2)

Production

(1)

(1)

(1)

(1)

31 December 2019

29

1,460

287

54

6

55

83

1,465

342

Contingent Resources

1 January 2019

0.7

133

23

33

15

35

33

148

58

Additions

 

Revisions and Discoveries

23

618

134

20

22

24

43

640

156

Disposals and relinquishments

Transfer to commercial reserves

31 December 2019

24

751

157

53

37

59

76

788

216

Total Commercial Reserves & Contingent Resources

1 January 2019

23

1,692

321

81

20

84

104

1,711

405

31 December 2019

53

2,211

444

107

43

114

159

2,253

558

Edison E&P acquisition

In July 2019, Energean agreed to acquire Edison E&P for $750 million plus $100 million of contingent consideration. Energean raised $265 million of new equity and $600 million in bridge financing from leading international banks to fund the deal. Energean is in the process of refinancing the acquisition bridge facility using an RBL, which is expected to be sized at up to $525 million, plus a $250 million bridge to disposal for the UK and Norway assets.

Energean is working actively to close the acquisition as soon as possible, with approval from Italian regulatory authorities anticipated soon. Formal approval from Egyptian regulatory authorities is expected soon after shareholder approval at the EGM. As announced on 23 December 2019, the transaction will now exclude the Algerian assets. Carve out of the Algerian assets from the transaction perimeter has been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.

In October 2019, Energean agreed to sell Edison E&P’s UK North Sea and Norway assets to Neptune Energy for $250 million (plus up to $30 million contingent consideration). The deal is aligned with Energean’s strategy of optimising its portfolio and the stated goal of disposing of non-core assets. The onward sale is expected to complete as soon as is practicable following the close of the acquisition of Edison E&P. 

Edison E&P financials

During 2019, Edison E&P delivered the following financial results. These results have been prepared on the basis of Edison E&P’s accounting policies and are subject to adjustments when included in Energean’s upcoming Circular and Prospectus.

Edison E&P financials are presented on a pro forma basis and are unaudited.

 

Edison E&P

 

2019 – $ million

Edison E&P exclusive UK North Sea, Norway & Algeria

2019 – $ million

Revenue

531

433

Operating Costs (including G&A)

255

196

EBITDAX

276

237

Operating Cash Flow

252

212

Development and Production Capital Expenditure

136

33

Exploration Expenditure

49

28

At 31 December 2019, net receivables (after provision for bad and doubtful debts) in Egypt were $222 million, of which $126 million were classified as overdue (31 December 2018: $240 million net receivables, of which $106 million were classified as overdue). A further payment for $55 million was received in January 2020.

Edison E&P production

Average Working Interest production from the Edison E&P portfolio during 2019 was 64.2 kboed. Average 2019 production from the assets to be retained by Energean was 56.4 kboe/d and, for this set of assets, pro forma 2020 production guidance is a range of 42.5 – 50.0 kboe/d. Average Working Interest production in the first two months of 2020 is estimated to have been 52.4 kboe/d.

During 2020, Energean expects Egyptian production to average 32 – 37 kboe/d, Italy to average 8 – 10 kboe/d and Croatia to average 0.5 kboe/d. After an initial reduction during 2020 due to the natural depletion of the fields, production is expected to rise again in the medium term mainly due to new developments; Cassiopea in Italy, Yazzi/NEA/NI in Egypt and, potentially, Irena in Croatia. Production is also expected to be enhanced through the drilling of additional wells at Abu Qir; four locations have been identified for near-to-medium term drilling that, if sanctioned (noting that these wells represent discretionary capital expenditure), would target a combined 30 mmboe of reserves for a total budget of c.$90 million.  

Country

2020 Pro Forma Production Guidance

  • kboe/d

2019 Average Working Interest Production – kboe/d[5]

Italy

8 – 10

10.4

Egypt

32 – 37

45.5

Croatia

0.5

0.5

Edison E&P Assets to be Acquired

42.5 – 50.0

56.4

Algeria

 

5.2

UK

 

2.5

Total

 

64.2

Edison E&P reserves

As at 30 June 2018, the Edison E&P assets to be acquired had 2P reserves of 239 mmboe of working interest 2P reserves according to an independent CPR prepared by DeGolyer and MacNaughton. The reserves report is currently being updated to reflect an effective date of 31 December 2019 and will be published in the Shareholder Circular, to be sent to shareholders in connection with the acquisition. The new CPR is expected to reflect a corresponding decrease in reserves as a result of 18 months of production. Reserve replacement has been limited over the period due to limited investment associated with the disposals process and change of control. 

Edison E&P Development

Italy  – Argo Cassiopea

In December 2019, ENI and Edison E&P received the renewal of the Italian EIA approval on Cassiopea (ENI 60% Op., Edison E&P 40%). The development consists of four subsea wells (two new wells and two re-completed wells) and uses a subsea production system with a 60 kilometre pipeline to shore, where gas compression and treatment will be performed inside the existing Gela refinery. The drilling campaign is expected to be undertaken between 1Q and 3Q 2022 and the subsea installation campaign 2Q to 4Q 2022, with first gas expected in early 2023. The development is expected to add an estimated 60 mmscf/d (10 kboe/d) of net production.

Egypt – NEA/NI

The NEA and NI assets are satellite fields of the Abu Qir gas-condensate asset. Edison E&P has a 100% working interest in both accumulations. The development concept includes four subsea wells, to be drilled in water depths ranging from 30 to 85 metres, and tied back to the North Abu Qir III platform. A final investment decision is expected in mid-2020 with first gas expected 18 months later. The development will target an estimated 52 million barrels of working interest 2P reserves at a total cost of approximately $200 million.  

The development will add limited operating costs to the Abu Qir complex, resulting in attractive netbacks.

Expected peak production from the NEA / NI development is an incremental 90 mmscf/d plus 1 kbopd of condensate.

Croatia

Edison E&P expects to spud the Irena-2 appraisal well in 2Q 2020. It will target the same gas-bearing horizon that was successful in Irena-1 and, in the event of a success, the well will be suspended for future production.

Edison E&P Exploration

In Egypt, the Ameeq well, which is being drilled on the North Thekah Offshore Block, spudded on 18 January 2020.

In Italy, an additional two firm exploration wells will be drilled into the Gemini and Centauro prospects, which are adjacent to the Cassiopea field, in 2022. These wells will target a combined c.9.7 mmboe of gross prospective resources and each has a Geological Chance of Success of 90%. If successful, the wells would be tied back to the Cassiopea subsea system. 

2020 Guidance – pro forma for the combined business, includes Edison E&P

The production and financial data below reflects the Edison E&P forecasts for the full year. Edison E&P will be consolidated into Energean’s financial statements from the date of transaction completion, which is expected later in 2020. Energean will benefit from net cash flows between the locked-box date of 1 January 2019 and the date of transaction completion through an adjustment to the variable consideration.

 

2020

 

Jan & Feb 2020 Performance

 

Production

 

 

 

     Egypt (kboe/d)

32 – 37

40.2

 

     Italy (kboe/d)

8 – 10

9.7

 

     Greece (kboe/d)

2 – 2.5

2.2

 

     Croatia (kboe/d)

0.5

0.3

 

Total Pro Forma Production (kboe/d)

42.5 – 50.0

52.4

 

 

 

 

 

Financials

2020

Discretionary Amount

 

Operating Costs & G&A ($ million)

225 – 250

 

 

 

 

Development and Production Capital Expenditure

 

 

 

  • Israel ($ million)

580

Funded by project finance facility

  • Egypt ($ million)

100

100

70 million NEA/NI; $20 million Abu Qir facilities; $8 million Abu Qir wells

  • Italy ($ million)

75

40

All discretionary apart from $25 million investment in Cassiopea and $10 million in Leoni

  • Greece ($ million)

5

100% owned and operated, Epsilon investment deferred

  • Croatia ($ million)

10

Appraisal well committed, capacity to delay exists

Total Pro Forma Development & Production Capital Expenditure ($ million)

770

140

 

 

 

 

 

Exploration Capital Expenditure (Firm)

 

 

 

  • Israel ($ million)

5

 

  • Egypt ($ million)

60

 

  • Italy ($ million)

 

  • Greece ($ million)

5

 

  • Croatia ($ million)

 

  • Other ($ million)

 

Total Pro Forma Exploration Capital Expenditure ($ million)

70

 

Financial review

Focused on maintaining strong financial discipline

Revenue, production and commodity prices

Working interest crude production from Greece averaged 3,312 bopd, a decrease of 18% for the period (2018: 4,053 bopd). The decrease in production was due to the decision to put the Prinos Area assets under strategic review following the review of capital allocation that was initiated earlier in the year. As a result, investment in Prinos and Prinos North was limited to $14.0 million during the period, while this process was being undertaken.

Prinos crude is sold at a $6.6/bbl. discount to Urals Med blend, adjusted for final cargo API. In 2019 the average sales price achieved was $58/bbl.

Depreciation, impairments and write-offs  

Depreciation charges before impairment on production and development assets increased by 15% to $39.1 million (2018: $34.3 million) due to increased capital expenditure invested in Greece during 2018, along with finance lease assets’ depreciation recorded for the first time in 2019 (IFRS 16 adoption). The Group recognised a gross impairment charge of $71.1 million in 2019 (2018: $nil). In the period, indicators of impairment were noted for the Prinos CGU, being a reduction in both short-term (Dated Brent forward curve) and long-term price assumptions and a change in the Group’s Prinos field production forecast, which have resulted in an impairment of $71.1 million in the carrying value of the Prinos CGU. 

Selling, general and administrative (SG&A) expenses 

Energean incurred SG&A costs of $13.7 million in 2019. This represents a 13% increase on the previous year (2018: $12.1 million) and is due to the additional staffing and administrative costs associated with the continued growth of the Group’s portfolio and the efforts associated with developing the Karish project.

For the full year 2020 Energean expects stand-alone SG&A costs to be $15.0 million. Edison E&P adds an estimated additional $30 million on a pro forma basis.

Other expenses

Other expenses of $21.6 million (2018: $1.1 million) consist predominantly of the direct costs incurred in 2019 relating to the proposed acquisition of Edison’s E&P business.

Finance costs

Financing costs before capitalisation for the period were $48.9 million (2018: $22.7 million). Included within this balance is $34.4 million of interest (2018: $12.2 million), of which $7.0 million relates to interest incurred on the RBL facility and $27.4 million on the Karish project finance facility. In addition, there was $7.2 million (2018: $5.7 million) of interest expenses relating to long term payables representing future payments to the previous Karish/Tanin licence holders. This was offset by capitalised borrowing costs of $39.9 million (2018: $9.3 million). The remainder of the total finance costs expensed relate primarily to finance and arrangement fees and other finance costs and bank charges. Total finance cost expensed amounted to $9.0 million (2018: $13.5 million).

Crude oil hedging

Energean had no hedges during the period and has no outstanding crude oil hedges at year-end. Energean will keep its hedging position under review.

Taxation               

Energean recorded tax income of $20.5 million in 2019 (2018: $15.5 million tax income) primarily associated with the deferred tax impact of the impairment losses associated with the Prinos assets.

Operating cash flow

Cash from operations before movements in working capital was $18.5 million (2018: $53.9 million). After adjusting for working capital movements, cash from operations was $36.3 million, a 42.1% decrease on the comparable period (2018: $62.7 million). The decrease is driven by reduced production and revenue in the period and due to $8.1 million of direct transaction costs for the proposed acquisition of Edison E&P in 2019, which have been recorded under operating activities.

Financial results summary

Metric

2019

2018

Av. Daily working interest production (kboed)

3.3

4.1

Sales revenue ($M)

75.7

90.3

Realised oil price ($/boe)

57.6

61.3

Cost of oil production ($m)

25.9

26.0

Cost of production per barrel ($/boe)

21.5

17.6

Administrative & selling expenses ($m)

13.7

12.1

Adjusted EBITDAX ($m)

35.6

52.4

Cash flow from operating activities ($m)

36.3

62.7

Capital expenditure ($m)

685.1

494.6

Cash capital expenditure ($m)

954.6

293.6

Net debt (cash) ($m)

561.6

(75.6)

Net debt/equity (%)

44.5%

(6.95)%

Non-IFRS measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include adjusted EBITDAX, cost of oil production, capital expenditure, cash capex, net debt and gearing ratio and are explained below.

Cost of oil production

Cost of oil production is a non-IFRS measure that is used by the Group as a useful indicator of the Group’s underlying cash costs to produce hydrocarbons. The Group uses the measure to compare operational performance period to period, to monitor costs and to assess operational efficiency. Cost of oil production is calculated as cost of sales, adjusted for depreciation and hydrocarbon inventory movements. 

 

2019

 

2018

$M

$M

Cost of sales

65.6

58.8

Less

          Depreciation

(36.6)

(33.9)

          Change in inventory

(2.9)

1.1

Cost of oil production

25.9

26.0

Total production for the period (boe)

1,208,978

1,479,367

Cost of oil production per boe ($)

21.5

 

17.6

Prinos production fell by 18% in 2019. This has resulted in a 22% increase in per barrel production costs, from $17.6/bbl. in 2018 to $21.5/bbl.

Adjusted EBITDAX 

Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, other income and expenses (including the impact of derivative financial instruments and foreign exchange), net finance costs and exploration costs. The Group presents adjusted EBITDAX as it is used in assessing the Group’s growth and operational efficiencies, because it illustrates the underlying performance of the Group’s business by excluding items not considered by management to reflect the underlying operations of the Group. 

 

2019

2018

Metric

$M

$M

Adjusted EBITDAX

35.6

52.4

Reconciliation to profit/(loss):

 

 

Depreciation and amortisation

(39.1)

(34.3)

Exploration and evaluation expense

(0.8)

(2.1)

Impairment loss on property, plant and equipment

(71.1)

Other expenses

(21.6)

(1.1)

Other income

3.1

8.9

Finance expenses

(9.0)

(13.5)

Finance income

2.5

1.7

Gain on derivative

96.7

Net foreign exchange

(3.9)

(23.5)

Taxation income/(expense)

20.5

15.5

(Loss)/income for the year

(83.8)

100.8

Capital expenditure

Capital expenditure is a useful indicator of the Group’s organic expenditure on oil and gas assets and exploration and appraisal assets incurred during a period. Capital expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets excluding decommissioning, capitalised depreciation, less capitalised borrowing cost.

 

2019

2018

Metric

$M

$M

Additions to property, plant and equipment

670.6

502.0

Additions to intangible exploration and evaluation assets

61.7

6.2

Less

 

Capitalised borrowing costs

(39.9)

(9.3)

Capitalised depreciation

(1.9)

(2.6)

Change in decommissioning provision

(5.4)

(1.8)

Total

685.1

494.6

Capital expenditure was $685.1 million, of which $611.9 million was invested in Israel, $68.4 million in Greece (Epsilon – $45.2 million) and $4.9 million in Montenegro.

Cash capital expenditure in 2019 was $954.5 million (FY 2018: $293.6 million).

 

2019

2018

Cash Capital Expenditure

$M

$M

Payment for purchase of property, plant and equipment

897.2

290.1

Payment for purchase of intangible assets

57.4

3.5

Total

954.5

293.6

Net cash/debt and gearing ratio

Net debt is defined as the Group’s total borrowings less cash and cash equivalents. Management believes that net debt is a useful indicator of the Group’s indebtedness, financial flexibility and capital structure because it indicates the level of borrowings after taking account of any cash and cash equivalents that could be used to reduce borrowings. The Group defines capital as total equity and calculates the gearing ratio as net debt divided by capital.

Net debt reconciliation           

 

 

2019

 

2018

 

 

$M

 

$M

Net Debt

Current borrowings

38.1

Non-current borrowings

877.9

144.3

Total borrowings 

916.0

144.3

Less: Cash and cash equivalents and bank deposits

(354.4)

(219.9)

Net (Funds)/Debt (1)

561.6

(75.6)

Total equity  (2)

1,260.8

1,087.8

Gearing Ratio (1)/(2):

44.54%

(6.95%)

In July 2019, Energean raised $265.1 million through the issuance of new ordinary shares on LSE and TASE. Net of cash transaction costs of $8.2 million this contributed $256.9 million of cash to the Group in 2019 .

Edison E&P acquisition

In July 2019, Energean agreed to acquire Edison Exploration & Production S.p.A. from Edison S.p.A. for $750 million, to be adjusted for working capital, with additional contingent consideration of $100 million payable following first gas from the Cassiopea development (expected early 2023), offshore Italy.

Energean also agreed to sell the UK and Norwegian subsidiaries of Edison E&P to Neptune Energy for $250 million, to be adjusted for working capital, with additional contingent consideration of up to $30 million. The sale is contingent on Energean completing upon its acquisition of Edison E&P and is expected to close as soon as is reasonably practicable after close of the Edison E&P transaction.

On 23 December 2019, Energean announced that Edison S.p.A. had received a letter from the Algerian authorities, which invited Edison to discuss the transaction with Sonatrach. Energean and Edison E&P subsequently agreed to exclude the asset from the transaction perimeter.  Carve out of the Algerian assets from the transaction perimeter has now been agreed in principle at an effective price of $155 million, based on an effective transaction date of 1 January 2019; the carve out remains subject to a signed, amended SPA.

Financing of the acquisition

The initial consideration was supported by a $600 million committed bridge loan facility underwritten by ING and Morgan Stanley, and S$265 million of equity financing. The total debt and equity capital raised was sized to cover both the initial consideration and working capital requirements of the enlarged group.

The bridge loan facility is expected to be replaced in 2020 using a reserve based facility and a bridge facility for the onward sale of the UK and Norwegian assets to Neptune Energy. The $100 million of contingent consideration is expected to be funded by the combined free cash flow of the Enlarged Group as well as any incremental reserve based facility capacity.

Placing

In July 2019, Energean also launched a placing with institutional investors of new ordinary shares of 1 pence each in the capital of Energean to raise up to £211 million (approximately $265 million) before expenses.

Proposed Edison E&P acquisition – 2019 financial results

During 2019, Edison E&P delivered the following financial results. These results have been prepared on the basis of Edison E&P’s accounting policies and are subject to adjustments when included in Energean’s upcoming Circular and Prospectus.

 

Edison E&P

Edison E&P exclusive of the UK, Norway and Algeria assets

 

2019 – $m

2019 – $m

Revenue

531

433

Operating costs

255

196

EBITDAX

276

237

Operating cash flow

252

212

Development and production capital expenditure

136

33

Exploration expenditure

49

28

Liquidity risk management and going concern

The Group carefully manages its risk to a shortage of funds by monitoring its funding position and its liquidity risk. Cash forecast are regularly produced and sensitivities run for different scenarios including change in Brent prices, different production rates and future capital expenditure investment profile.

Short-term cash forecasts have been stress-tested in light of the significant oil price reduction seen in early March 2020, with a primary scenario using an average price of $35.0/bbl for 2020 and $42.5/bbl for 2021, and a downside sensitivity run at $30/bbl average for both 2020 and 2021.

In this scenario, the Group would also target a further rationalisation of its cost base, including cuts to discretionary capital expenditure and operating cost. As at 31 December 2019, the Group had cash and undrawn facilities of $834.2 million million. Post-period end, Energean has also successfully increased its Israel Project Finance Facility by $175million to $1.45 billion (from $1.275 billion), providing additional headroom on its Karish development.

The Group’s revised forecasts show that the Group will be able to operate within its current debt facilities and has sufficient financial headroom for the 12 months from the date of approval of the 2019 Annual Report and Accounts. In arriving at this conclusion, the Directors also had regard to the Group’s ability to raise necessary funding as and when needed. In 2019, the Group successfully raised gross proceeds of $265.1 million through a private placement on the London and Tel Aviv Stock Exchanges. The Group also raised a $600 million bridge facility to provide funds for its acquisition of Edison E&P. The Group expects to replace this with a Reserve Based Lending (“RBL”) Facility (of up to $525m, of which between $400 and $450million is expected to be available) plus a Bridge to Disposal Facility (of up to $250million) for the sale of the UK and Norway assets to Neptune Energy. The purpose of the RBL will be to fund the acquisition, refinance the Greek RBL and provide headroom over the medium term for capital expenditure within the Group (excluding Israel).   

Based on an assessment of the Group’s cash flow forecasts under various scenarios, including the identification of associated risks and mitigants, the Directors have concluded that they have a reasonable expectation that the Group will continue in operational existence for a 12 month period from the date of approval of the 2019 Annual Report and Accounts and have therefore adopted the going concern basis in preparing the Group and parent company financial statements.

Coronavirus

Energean continues to monitor the ongoing COVID-19 outbreak, accessing the advice by the World Health Organisation and Public Health England to ensure that best-practice precautions are being applied. Clear information and health precautions on how employees should protect themselves and reduce exposure to, and transmission of, a range of illnesses along with general advice has been communicated across the organization.

Coronavirus has not yet affected Energean’s operations, but in the event that the COVID-19 outbreak escalates, Energean has contingency plans in place that will be followed.

Events since 31 December 2019

Energean is exposed to macro-economic risks, including pandemic diseases that could have a material adverse effect on its operations. We continue to monitor the recent Coronavirus outbreak, which is causing global economic disruption and may impact our performance in 2020. To date, the Coronavirus has not had a material impact on Energean’s activities. However, at present, it is not possible to predict whether the outbreak will have a material adverse effect on our future earnings, cash flows and financial condition.

On 6 March 2020, OPEC and non-OPEC allies (OPEC+) met to discuss the need to cut oil supply to balance oil markets in the wake of the Coronavirus outbreak, which has had a material adverse impact on oil demand. OPEC+ failed to reach agreement and on 7 March 2020, Saudi Aramco cut its Official Selling Prices, prioritizing market share over pricing. As a result, oil prices have fallen materially, which may have a material adverse impact on the component of Energean’s future earnings that are linked to oil prices.

In January 2020, Energean reduced the size of it EBRD Reserve Based Lending Facility to $161 million.

On 16 March 2020, Energean Israel signed a $175 million increase in its project finance facility, which is now sized at $1,450 million, increasing liquidity available to the company. 

Group Income Statement

 

YEAR ENDED 31 DECEMBER 2019    

 

 

2019

 

 

2018

 

Notes

$’000

 

 

$’000

Revenue

6

75,749

90,329

Cost of sales

7a

(65,552)

 

 

(60,019)

Gross profit

10,197

30,310

 

Administrative expenses

7b

(13,305)

(11,666)

Selling and distribution expenses

(345)

(453)

Exploration and evaluation expenses

 

(801)

(2,102)

Impairment of property, plant and equipment

10

(71,115)

 

 

Other expenses

7c

(21,584)

 

 

(1,118)

Other income

7d

3,095

 

 

8,869

Operating (loss)/profit

(93,858)

23,840

 

 

 

 

 

 

Finance income

8

2,496

1,735

Finance costs

8

(9,002)

(13,471)

Gain on derivative

5

96,709

Net foreign exchange losses

8

(3,933)

 

 

(23,521)

(Loss)/profit before tax

(104,297)

85,292

 

Taxation income

9

20,531

 

 

15,527

(Loss)/profit for the year

 

(83,766)

 

 

100,819

 

 

 

 

 

 

Attributable to:

 

Owners of the parent

(83,313)

105,279

Noncontrolling interests

 

(453)

 

 

(4,460)

 

 

(83,766)

 

 

100,819

 

Basic and diluted total (loss)/earnings per share (cents per share)

2

 

 

 

 

Basic

($0.50)

$0.80

Diluted

 

($0.50)

 

 

$0.79

 


 

Group Statement of Comprehensive Income

 

YEAR ENDED 31 DECEMBER 2019

 

 

 

2019

 

 

2018

 

 

$’000

 

 

$’000

Consolidated statement of comprehensive income

 

 

 

 

 

 

 

 

 

 

 

(Loss)/profit for the year

 

(83,766)

 

 

100,819

 

Other comprehensive loss:

 

Items that may be reclassified subsequently to profit or loss

 

Cash Flow Hedge, net of tax

 

434

 

 

Exchange difference on the translation of foreign operations

 

(3,751)

 

 

(4,288)

 

 

(3,317)

 

 

(4,288)

 

Items that will not be reclassified subsequently to profit or loss

 

Remeasurement of defined benefit pension plan

(466)

(444)

Income taxes on items that will not be reclassified to profit or loss

 

117

 

 

107

(349)

(337)

Other comprehensive loss after tax

 

(3,666)

 

 

(4,625)

 

Total comprehensive (loss)/income for the year

 

(87,432)

 

 

96,194

 

Total comprehensive (loss)/income attributable to:

 

Owners of the parent

(87,109)

100,856

Non-controlling interests

 

(323)

 

 

(4,662)

 

 

(87,432)

 

 

96,194

 

 

 

 

 


Group Statement of Financial Position

YEAR ENDED 31 DECEMBER 2019

 

 

2019

 

 

2018

 

 Notes

$’000

 

 

$’000

ASSETS

 

Non-current assets

ͮ

Property, plant and equipment

10

1,902,271

1,341,704

Intangible assets

11

71,876

10,555

Goodwill

75,800

75,800

Other receivables

4,076

71,845

Deferred tax asset

33,038

15,532

 

 

2,087,061

 

 

1,515,436

Current assets

 

Inventories

 

6,797

9,912

Trade and other receivables

12

59,892

32,883

Cash and cash equivalents

354,419

219,822

421,108

262,617

Total assets

 

2,508,169

 

 

1,778,053

 

EQUITY AND LIABILITIES

 

Equity attributable to owners of the parent

 

Share capital

13

2,367

2,066

Share premium

13

915,388

658,805

Merger reserve

139,903

139,903

Fuel price plunge pressuring refineries, opportunities seen

The plunge of international crude oil prices is impacting Greek refineries and local fuel trade, while, worse still, market forecasts are impossible to make, even for the short term.

Hellenic Petroleum (ELPE) and Motor Oil, Greece’s two refinery groups, are being tested by the fall of Brent prices to levels of around 30 dollars per barrel. Highlighting this challenge, unleaded 95 octane fuel prices have dropped to less than 1,000 euros per cubic meter (including surcharges before VAT) for the first time in many years.

This represents a drop of more than 100 euros compared to prices on March 9, dubbed “Black Monday” as it was the worst day in markets since the financial crisis, a result of the outbreak of the oil price and output level war between Russia and Saudi Arabia, along with the coronavirus spread’s impact on demand.

The drop in prices is seen continuing. Domestic fuel demand is falling as a result of the Greek government’s broadened enforcement of restrictive measures aiming to contain the coronavirus spread. Local transportation needs have subsequently dropped dramatically, while the only other viable option left for Greek refineries, exports, has been canceled out by plunging fuel demand internationally. Borders have closed and airlines are limiting flights.

The cost of fuel stocks, purchased at far higher prices, is a big concern for both ELPE and Motor Oil. This cost, however, can be partially offset by opportunities currently available for lower-cost production.

On a more positive note, both refineries reduced their loan servicing costs prior to the crisis. This is particularly so for ELPE as the petroleum group was pressured by high borrowing costs. Motor Oil has traditionally pursued a more conservative borrowing policy.

Both refineries will need to take extremely cautious steps amid these highly unpredictable market conditions, analysts agree.

Lower-cost oil, gas an obstacle for RES growth, electric cars

Lower-cost oil and gas, as well as solar module supply chain irregularities caused by the coronovarirus spread in China, the world’s dominant supplier of solar energy systems, have emerged as obstacles for RES sector growth and investments.

Numerous solar energy projects around the world are being delayed or postponed as a result of the solar module supply problems in China.

The recent plunge of oil and gas prices, prompted by the impact of the coronavirus spread on economies and a simultaneous oil-price war between Russia and Saudi Arabia, has suddenly made RES investments less competitive against conventional technologies in terms of electricity generation, energy efficiency or electrification of sectors such as transportation or shipping.

The duration of lower oil prices remains unknown.

Natural gas prices have fallen as a result of idle LNG shipments in China and forecasts for weaker demand worldwide.

Under the current conditions, market forces will turn against green energy technologies, which had just begun establishing themselves as competitive options against conventional technologies.

Questions are also being raised about the growth prospects of the electric vehicle market, still at an embryonic stage.

 

Lower-cost gas may save PPC an estimated €100m this year

The sharp drop in energy product prices, pressured by the coronavirus outbreak and an oil price war between Russia and Saudi Arabia, promises major and unexpected financial relief for power utility PPC.

The plunge of gas prices, alone, should benefit the Greek power utility by an estimated 100 million euros this year – assuming this drop is not ephemeral.

In the first half of 2019, PPC’s total purchasing cost for natural gas reached 222.5 million euros, a 57.1 percent increase.

In the liquid fuels category, PPC’s purchase expenses were also elevated, reaching 319.7 million euros, as a result of higher prices paid for mazut and diesel used by the utility at power stations on non-interconnected islands. To the delight of PPC, mazut and diesel prices are also tumbling.

Electricity tariff hikes made by PPC last September as well as a revised payback plan offering consumers greater incentive to service electricity-bill arrears through monthly installments are both producing favorable results.

A series of memorandums of cooperation, such as an agreement signed this week with Germany’s RWE, all promising dynamic penetration into Greece’s renewable energy market, offer further potential for PPC.

However, the power utility still faces an uphill struggle along its road to recovery. PPC’s financial results for 2019 will be announced in April.

 

Pros and cons for refineries, fuel demand sliding

The drop in oil prices as a result of the price war between Saudi Arabia and Russia and the coronavirus spread presents a major challenge for petroleum firms.

Brent crude’s 30 percent plunge last Monday inflicted major damage on companies stocked with petroleum products, Greek refinery officials informed, as these products had been  purchased at previously higher prices.

The market volatility, however, has also created opportunities, namely lower-cost supply of raw materials without the need for high working capital. Operating costs have dropped considerably.

The major concern at refineries and petroleum product trading companies is demand, or fuel consumption, expected to drop amid the growing number of mobility restrictions being imposed by governments around the world in an effort to contain the coronavirus outbreak.

Demand for gasoline and diesel has dropped since last weekend as a result of reduced transportation needs. This decline in fuel demand is expected to continue following latest preventive measures. The Greek government yesterday announced a measure closing all educational institutions for 15 days as of today.

Fuel demand levels during the year’s first two-month period were unchanged compared to a year earlier, but the month of March has already shown first signs of a decline. Many airlines are cancelling flights.

Petroleum companies fear a further deterioration from May onward, when Greece’s tourism season begins in earnest.

For the first time since 2009, the International Energy Agency has forecast a drop in petroleum consumption for 2020.