Neptune Energy announces completion of seismic survey offshore Egypt

Neptune Energy has announced the successful completion of an ocean bottom nodes (OBN) multiclient survey in the North West El Amal block, offshore Egypt, delivering promising results for further analysis.

The project, prefunded by Neptune, was carried out by WesternGeco, the seismic and geophysical data solutions division of Schlumberger, under a contract with the Egyptian General Petroleum Corporation (EGPC), sponsored by the Egyptian Ministry for Petroleum and Mineral Resources. WesternGeco acquired the survey using third-party vessels.

The survey employed innovative OBN technology to overcome the challenge of acquiring improved imaging in the complex salt geometries of the Gulf of Suez. It was the first ever OBN seismic survey to be conducted in Egypt and the most detailed survey of the block since the first acquisition in 1988, providing an in-depth data set for processing, image analysis, and planning for potential exploratory wells in the future.

The North West El Amal offshore concession covers 365 km2 and is located in the central part of the Gulf of Suez, approximately 42 km south of Ras Gharib and 105 km north of Hurghada. Neptune was awarded the exploration licence in February last year, including the acquisition of 100 km2 of 3D seismic data.

Egypt Managing Director, Gamal Kassem said: “Egypt is important for Neptune and we are pleased to build on our strong relationships with the Ministry of Petroleum and Egyptian General Petroleum Corporation.

“The safe and successful completion of the seismic acquisition is an important achievement and is testament to the careful planning and professional execution by Neptune, EGPC and WesternGeco.”
The project involved placing large numbers of autonomous sensors on the seabed to acquire seismic data, then retrieving them for analysis. The process acquires more detailed data than standard technologies and is less sensitive to weather conditions which can impact traditional seismic survey vessels.

Neptune’s VP Exploration & Development, Gro Haatvedt added: “It’s very exciting to have been involved in the OBN seismic survey, the first time the technology has been deployed in Egyptian waters. Given the geographically-diverse nature of our global portfolio, Neptune is accustomed to working with innovative digital and subsurface technologies to tackle a variety of geological challenges.

“Obtaining subsalt imaging is particularly tough and the OBN technology was well-suited for this purpose. The next step is to analyse the data which has greatly improved our understanding of the block and will support our future plans including potential exploratory wells.”

Source: https://www.neptuneenergy.com/media/press-releases/year/2020/neptune-energy-completes-seismic-survey-offshore-egypt


About North West El Amal
Operated offshore concession in the central part of the Gulf of Suez

Block 4 - North West El Amal Offshore Concession

Status:
Neptune will acquire 100 km2 of 3D seismic data and drill one exploration well in the first phase, with two further wells planned in phase two.

North West El Amal facts:
Neptune was awarded its first operated concession in Egypt in 2019 and signed the concession agreement in 2020 with Minister of Petroleum Tarek El-Molla
The concession covers 365 km2 and is located in the central part of the Gulf of Suez
The area is 42 km south of Ras Gharib and 105 km north of Hurghada

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Soco acquires Egypt-focussed Merlon Petroleum

SOCO is rebuilding its business with the proposed USD215 million acquisition of Merlon Petroleum.

Merlon will significantly diversify the SOCO business adding Egypt as a new base from which to build a MENA portfolio. The acquisition will double SOCO's 2P reserves and production through the addition of 24mmbbl of oil.

Merlon's key asset is its 100% interest in the El Fayum licence which currently produces at c.7,000bbopd. The block contains 37mmbbl of contingent resources for SOCO to exploit which could take production beyond 15,000bopd. Furthermore, the northern area of the block is unexplored which SOCO will be keen to go after - management has already mapped 20 leads and prospects to be drilled between now and 2020.

The acquisition is to be financed by a mix of cash (up to USD158 million), assumption of debt (USD22 million) and issuance of 66 million new shares to Merlon's existing shareholders. The acquisition is expected to complete in H1 2019.

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SDX has made a gas discovery on its South Disouq licence

SDX made a gas discovery with the Ibn Yunus-1X well on its South Disouq licence. The well is planned to be tied into nearby infrastructure being constructed to commercialise the original gas on the block (SD-1X). First gas on the licence, which will now be from both wells, is targeted for H2 2018.

SDX has a 55% operated stake in the licence, having farmed out 45% to IPR in February 2015. SDX made the SD-1X discovery in 2017 which tested successfully and now being developed through an Early Production System. The gas price is understood to be under negotiation which could be above the country’s historical domestic price of USD2.65/mmbtu.

Further exploration on the licence is now planned targeting the estimated 1.3tcf of resource potential (P10).

Press announcement

SDX Energy Inc. (TSXV, AIM: SDX), the North Africa focused oil and gas company, is pleased to announce
that a gas discovery has been made at its Ibn Yunus-1X exploration well at South Disouq, Egypt (SDX 55%
working interest and operator).

The Ibn Yunus-1X well was drilled to a total depth of 9068 feet and encountered 100.8 feet of net
conventional natural gas pay in the Abu Madi horizon, which had an average porosity in the pay section of 28.5%. The well came in on prognosis but with a reservoir section that was of better quality and thicker than pre-drill expectations.

The well will be completed as a producer in the Abu Madi section and then tested after the drilling rig has moved off location. The testing is anticipated to commence between 30 and 45 days after the rig departs, depending on the availability of testing equipment. After a successful test, it is anticipated that the well will be connected to the infrastructure located adjacent to the original SDX discovery in the basin, SD-1X, where production start-up is anticipated in the second half of 2018.

Paul Welch, President and CEO of SDX, commented:
“We are extremely encouraged with today’s discovery, our second consecutive discovery at South Disouq.

This highly positive drilling result further demonstrates the very significant natural gas potential the
licence holds. Combined, these two successful wells confirm our views of the subsurface geology and
demonstrate that we are on course to realise the full potential of the licence. We look forward to updating shareholders on future developments at South Disouq in due course.” 

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Tamar: Win one contract, lose another

Following Noble Energy and Delek Drilling’s announcement in February that it would be selling gas to Egypt’s Dolphinus Holdings from the Tamar and Leviathan fields, Egypt is ditching a previous agreement to import gas from Tamar.

Madrid’s Union Fenosa Gas had signed a non-binding letter of intent in May 2014 with the Tamar field partners to buy gas for the supply of the Damietta LNG plant in Egypt. The LNG plant is operated by Segas, a JV between Union Fenosa Gas, Eni and the Egyptian state. This arrangement has been cancelled as at the end of March, citing that it was “no longer relevant”.

This suggests that Eni, one of the partners of Segas, will supply Damietta with gas from its Zohr field.

Last month, Dolphinus Holdings had agreed to import 3.5bcm from each of Tamar and Leviathan for a period of 10 years under a contract wortg USD15 billion.

Tamar is owned by Isramco Negev (28.75%), Noble Energy (25% operator), Delek Drilling (22%), Tamar Petroleum (16.75%), Dor Gas (4%) and Everest Infrastructures (3.5%) – this reflects the ownership post the recent sale of 7.5% by Noble Energy to Tamar Petroleum as reported previously (Tamar Petroleum to raise bonds to finance acquisition of Tamar from Noble and Israel capital cycle: Noble sells down Tamar to fund Leviathan).

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Delek and Noble seeking to acquire gas pipeline to Egypt

Following Noble and Delek’s agreement to sell 64bcm of gas into Egypt via Egyptian intermediary Dolphinus Holdings, the two upstream companies have commenced discussions to acquire EMG, the business which owns the Arish-Ashkelon pipeline (otherwise known as the EMG pipeline).

This is one of the routes contemplated by Noble and Delek as part of plans to export gas into the wider East Med and Europe. The 64bcm of gas will be sourced from Tamar and Leviathan, the latter scheduled to deliver first gas at the end of 2019. Both fields are operated by Noble Energy.

Source: Delek, February 2018

The EMG pipeline used to export gas from Egypt to Israel under a deal agreed in 2008. However post the Arab Spring, the pipeline was increasingly the target of militant attacks and together with an emerging gas supply shortage, gas exports to Israel were terminated altogether. A lawsuit is continuing in the background between Egypt, Israel and EMG around the termination of gas exports.

In the meantime, it is understood that technical studies have begun to reverse the flow of the system for sending Israeli gas to Egypt.

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Dolphinus and the wider Egyptian gas hub story

Dolphinus was established with the main aim of becoming a “reliable and stable supplier of gas to major industrial gas distributors and consumers in Egypt”. It was co-founded by prominent Egyptian entrepreneurs Dr. Alaa Arafa, Eng. Khaled Abu Bakr and Mohamed Khalifa.

As a first step in its strategy, Dolphinus entered into a 64bcm, 10 year gas supply contract with Noble Energy and Delek Drilling for their gas in Israel (see Israel's Leviathan and Tamar gas to be sold into Egypt).

This is a welcome move for Egypt as Dolphinus can act as “middleman” for sourcing Israeli gas into Egypt. The two countries are still embroiled in a lawsuit over compensation to Israel when Egypt stopped supplying gas to the former in 2014 under a long term contract after Egypt ran into domestic supply shortages. Dolphinus therefore acts as a politically clean way to buy gas from Israel.

Dolphinus sees Egypt becoming a regional gas hub and looks to take part in that story by playing to the as import side of the story. Egypt has the right ingredients to be a hub. The country has a long history with gas, being an exporter for decades up until 2014 before needing to import gas in the last few years. This means the country has much of the infrastructure in place from domestic gas grids, cross-border pipelines, LNG facilities and access to FSRU capabilities.

While Egypt remains short gas, it is on the verge of being able to export again given the recent large discoveries in the offshore and also the emerging ability to re-export gas sourced from another country. This introduces the concept of Egypt being a gas trader, albeit currently at very early stages.

The existence of LNG export facilities means that the country has the ability (as it did before) to ship gas to a wide variety of destinations and is not reliant on pipeline infrastructure to penetrate markets. Being on the doorstep of the East Med allows Egypt to tap abundant sources of gas and the developing gas import dynamics means that the country is no longer tied to domestic supply sources to feed LNG – the issue back in 2014 when domestic demand outstripped supply and led to LNG facilities to call force majeure and stop exports.

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Israel's Leviathan and Tamar gas to be sold into Egypt

Noble Energy and Delek Drilling announced plans in February to export gas to Egypt. The plan is to supply 64bcm over a 10 year period to Egypt’s Dolphinus Holdings – 32bcm from Leviathan and 32bcm from Tamar.

Each field is contracted up to 3.5bcm p.a. or c.350mmcfpd and will bring the partners USD15 billion over the life of the supply contract. The contracted price and terms are in line with other supply contracts from these fields which is based on a Brent linked formula.

Source: Delek Drilling, February 2018

Leviathan is owned by Delek Drilling (45.34%), Noble Energy (39.66% operator), Ratio Oil Exploration (15%). The field is on track to target first gas by end 2019 and with the extra 350mmcfpd to Dolphinus brings contracted sales close to 900mmcfpd, just below the 1bcfpd target. The first phase of the field is planned to deliver 1.2bcfpd from four wells.

Source: Noble Energy, November 2017 with 525mmcfpd firm GSPAs at the time

Tamar is owned by Isramco Negev (28.75%), Noble Energy (25% operator), Delek Drilling (22%), Tamar Petroleum (16.75%), Dor Gas (4%) and Everest Infrastructures (3.5%) – this reflects the ownership post the recent sale of 7.5% by Noble Energy to Tamar Petroleum as reported previously (Tamar Petroleum to raise bonds to finance acquisition of Tamar from Noble and Israel capital cycle: Noble sells down Tamar to fund Leviathan).

The export route for the gas to Egypt is still to be decided but could utilise existing infrastructure or a new pipeline. At the end of February Noble Energy, Delek Drilling and Dolphinus were reported to be considering acquiring the Arish-Ashkelon pipeline owned by the East Mediterranean Gas company (otherwise known as the EMG pipeline).

Source: Delek Drilling, February 2018

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BP looks to sell out of Gulf of Suez

BP is running a process to sell its more mature fields in the Gulf of Suez, Egypt. The sale is hoped to raise between USD500 - 1,000 million.

The exit of the Gulf of Suez will allow BP to focus more on its deepwater gas portfolio in the country's offshore in the West Nile Delta and Eastern Mediterranean including the Zohr field which it entered at the end of 2016.

BP has 100% of the fields in the Gulf of Suez area and operates them in a JV with the government called Gulf of Suez Oil Company or GUPCO.

GUPCO produces over 70mbopd of oil and 400mmcfpd of gas.

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SDX makes heavy oil discovery at West Gharib in Egypt

SDX has made a heavy oil discovery on the West Ghraib licence at the Rabul-5 well.

The partners had implemented a waterflood programme in 2017 on the block and commenced an exploration and appraisal programme. Rabul-1 and -2 were drilled last year resulting in two discoveries and the current Rubul-5 well is a continuation of the delineation programme. Approval for develeopment locations at Meseda will be sought in 2018.

SDX holds 50% interest in the block, with Dublin International Petroleum holding the remaining operated 50% interest.

Press release below:

SDX Energy Inc., the North Africa focused oil and gas company, is pleased to announce that
an oil discovery has been made at its Rabul 5 Well in the West Gharib Concession in Egypt (SDX 50% Working Interest & Joint Operator).

The well was drilled to 5,280 feet total depth and encountered approximately 151 feet of net heavy oil pay across the Yusr and Bakr formations, with an average porosity of 18%. Further evaluation of the discovery is ongoing, after which the Company expects the well to be completed as a producer and connected to the central processing facilities at Meseda.

Following completion of the Rabul 5 well the Company will move on to the Rabul 4 location, the second of two appraisal wells planned for the Rabul feature this year.

Paul Welch, President and CEO of SDX, commented:
"We are pleased to continue our recent run of drilling success with this oil discovery at Rabul 5. This well encountered the thickest section of pay sands seen in the Rabul area to date, demonstrating the significant oil potential contained within the licence. We have further drilling activity planned for the concession over the coming months and we firmly believe that these activities will enable us to increase output from the licence and achieve our ambitious production plans for 2018.”

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Mubadala enters Zohr - acquires 10% from Eni

Mubadala has agreed to acquire a 10% interest in Zohr from USD934 million. Mubadala will acquire an interest in the Shorouk concession which contains the Zohr field. The super giant field came onstream in December 2017, 28 months after its discovery. The field is currently producing 400mmcfpd and planned to reach plateau by the end of 2019.

For Mubadala, this adds a world class asset with long term cash flows into its investment portfolio. Musabbeh Al Kaabi, Chief Executive Officer of Petroleum & Petrochemicals, Mubadala Investment Company, and Chairman of Mubadala Petroleum said: “This is an important and attractive investment for Mubadala, adding a world-class asset to our portfolio with long-term cash flows. We are joining a strong partnership with Eni as operator, who have delivered the project in record time and with the full support of the Egyptian authorities.”

For Eni, the deal is consistent with its strategy of monetising development and producing assets to recycle cash flows for exploration. It also reduces Eni’s portfolio weighting more towards OECD, a long term shift that the company continues to pursue. Claudio Descalzi, Chief Executive Office of Eni, said: “We are pleased to be working with Mubadala and welcome them into the partnership for the Shorouk concession. This represents a further signal about the strength and quality of this world class asset developed by Eni”.

The deal follows Eni’s farm-out of Zohr to BP and Rosneft in November and December 2016 prior to development spending. At the time, BP acquired 10% for USD525 million and 30% to Rosneft for USD1.125 billion. This compares with Mubadala’s current buy-in price of USD934 million for 10%.

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SOCO terminates merger talks with Kuwait Energy

Soco has formally terminated merger talks with Kuwait Energy over valuation differences. Full press release from Soco below.

On 8 January 2018, SOCO International plc (“SOCO”) announced that it was in preliminary discussions with the newly-constituted Board of Directors of Kuwait Energy plc (“Kuwait Energy”) regarding a potential transaction.

SOCO confirms that it has terminated these discussions because it could not reach agreement with Kuwait Energy on the basis for an acceptable transaction.

SOCO’s Board remains committed to its strategy of shareholder value creation through sustainable cash returns to shareholders and growth of the business. The SOCO team, which has a track record of delivering shareholder value through asset acquisition and monetisation, delivering large scale developments, and returning capital to shareholders, evaluates M&A opportunities with reference to strict strategic, financial and operational criteria and only pursues transactions if they are determined by SOCO’s Board to be in the best interest of shareholders. SOCO’s Board continues to evaluate opportunities in accordance with these criteria.

Source: https://www.socointernational.com/statement-on-discussions-with-kuwait-energy-plc

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Zohr record breaker

In record time for a deepwater gas development of this scale, Eni has announced first production from Zohr. The field was discovered in August 2015 and FID taken in early 2016 - Eni achieved first gas from discovery in 2.5 years.

Zohr is the largest gas discovery ever made offshore Egypt and is located in the Shorouk block. The field has begun production at 350mmcfpd and is expected to grow to 1bcfpd by mid-2018. The speed of development is a testament to Eni's "Dual Exploration Model" which was adopted in 2013. Under this model, Eni works the exploration, appraisal and development planning and phases in parallel while bringing in minority partners at the same time to help fund the costs.

Zohr has >30tcf of GIIP and forms an important piece of the jigsaw to solving Egypt's short gas problem. The new production will help feed the hungry and growing domestic gas demand which Egypt has been trying to manage by raising domestic prices on the one hand and incentivising further gas exploration/development on the other.

The Zohr partners are Eni (60%), Rosneft (30%) and BP (10%). Eni is co-Operator of the project through Petrobel, which is jointly held by Eni and EGPC.

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Maersk Drilling exits Egyptian JV in line with strategy

Maersk continues to review and streamline its business portfolio. As part of that strategy, it announced today of its exit of the Egyptian rig company joint venture.

Press release
A.P. Møller - Mærsk A/S ("A.P. Moller - Maersk") and Egyptian General Petroleum Corporation ("EGPC") has today signed an agreement whereby EGPC will acquire A.P. Moller - Maersk’s 50 percent shareholding in Egyptian Drilling Company ("EDC") for USD 100m in an all-cash transaction.

Following the transaction EGPC will become sole owner of EDC and will as part of the agreement take over the entire portfolio, obligations and rights. EDC is one of the leading drilling operators in the Middle East and operates 70 rigs in total of which the vast majority are land based drilling rigs.

The divestment of EDC is in line with Maersk Drilling’s strategy to focus on offshore drilling in the harsh environment and deepwater markets.

“I am very pleased with this agreement with EGPC. The divestment is a natural consequence of our announced long-term plans to exit the EDC joint venture, when the timing was right. EDC has a very strong position in the Middle East, and I am confident that the new ownership will enable EDC to develop its business and capabilities even further,” says Jørn Madsen, CEO of Maersk Drilling.

EDC began operations in 1976 as a 50/50 joint venture between Maersk Drilling and EGPC, which is owned by the Ministry of Petroleum and Mineral Resources in Egypt. EDC employs approximately 5,000 people, whereof 34 are Maersk Drilling employees. Maersk Drilling is currently looking into future job opportunities for its employees in EDC.

Source: https://www.maerskdrilling.com/en/media-center/press-release-archive/2017/12/maersk-exits-egyptian-drilling-company-joint-venture

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Eni: Bringing in successive partners for Zohr

On 28^th November, Eni announced the divestment a 10% interest in Zohr to BP for USD375 million plus pro-rata reimbursement of past costs (c.USD150 million net), bringing total consideration to USD525 million. BP also has an option to acquire an additional 5% interest on the same terms before the end of 2017.

On 12^th December, Eni announced that it had divested a further 30% interest in Zohr to Rosneft for USD1.125 billion and USD450 million of back costs - i.e. on substantially the same terms as BP. Rosneft also has an option to acquire an additional 5% interest on the same terms.

The transactions reduce Eni's exposure to the Zohr development by 40% from 100% to 60%; this could fall to 50% if BP and Rosneft exercise their options for additional interests. The divestment will also reduce Eni's capex by c.USD900 million in 2017 ahead of first gas at the end of 2017. A similar capex saving is expected to be made in 2018.

Eni has successfully demonstrated its ability to monetise large resource finds. The farm-out significantly derisks the upcoming development and it is promising to see buyers for good quality assets despite the current oil price environment.

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The Egyptian gas landscape

The Egyptian gas sector has historically suffered from underinvestment and the country has experienced a domestic supply shortfall since the beginning of 2015. Subsidised gas pricing encouraged strong demand growth during the 1990s and 2000s and at the same time, declining gas reserves in the onshore and the high cost of offshore gas developments have resulted in investment being diverted away from gas to onshore oil.

The state of the gas market has led to two major concerns for the government: (i) the energy subsidies have become habitual and a key contributor to the fiscal deficit which is unsustainable at current levels; and (ii) persistent energy shortages and brownouts have been a cause of public discontent in recent years at a time when the government is trying to restore stability post the Arab Spring. President Sisi and his administration are keen to entirely phase out energy subsidies in an attempt to tackle the fiscal deficit, encourage more responsible energy use and reinvigorate investment in gas development. The move, which should lead to gas pricing increasing over time, is welcomed by international investors and the E&P industry.

In 2015, Egypt became a net gas importer in the face of a domestic supply shortfall. This followed the diversion of LNG export volumes to the domestic market with the Gas Natural operated Damietta plant and BG operated ELNG plant being placed into force majeure in 2013 and 2014 respectively. During 2015, two LNG regasification facilities were installed at the Port of Sokhna and multi-year supply deals were concluded with LNG sellers; the lease of a third regasification unit is under consideration. Discussions are also ongoing to import gas from Israel by pipeline to supply industrial customers and the grid.

LNG imports are an expensive source of gas supply and the government is keen to boost domestic production and reduce dependence on imports. The government has envisaged a gas supply shortfall for a number of years and has agreed to increase the gas pricing or improve fiscal terms for a number of developments since 2008; the pace of these revisions has increased in recent years. In 2015, Dea agreed a new gas price of USD3.5/mcf, BG and Eni agreed up to USD6.06/mcf for new phases of offshore developments and Apache’s shale gas production will receive USD5.45/mcf.

In July 2015, Eni made the Zohr discovery which is estimated to hold 30tcf of gas in place. The large resource base has the scope to help Egypt regain gas self-sufficiency (potentially with a return to gas exports), although in the near term, the country remains in a gas shortage and reliant on imports. Zohr’s ability to effectively address Egypt’s future gas shortfall could potentially limit the liberalisation of gas pricing. Despite the discovery being in deepwater (~1,500m) and 200km offshore, initial estimates suggest that a gas price of USD4.5/mcf could result in a 15%+ IRR for the project due to the large volumes and low operating costs once onstream. However, with the government’s plan to remove subsidies and IOCs’ desire to maximise gas pricing for developments/production, the outlook for the Egyptian gas sector appears positive. In the near term, costlier gas developments may be delayed or their ability to achieve higher gas pricing may be impacted by more favourable Zohr economics, however domestic gas pricing has the potential to increase significantly from current levels of USD2.73/mcf.

Egypt gas supply excess / (deficit)
Source: Wood Mackenzie, BMI research, BP Statistical Review of the World, EIA, OGInsights

Egypt gas pricing for producers
Source: Wood Mackenzie

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The Apache Egypt treasure map

Source: Houston Geological Society, HGS

Apache is a significant acreage holder onshore Egypt with an extensive infrastructure network which allows new discoveries to be brought onstream quickly and at relatively low cost. Its acreage can be broadly split into four areas, the most significant of these is the Western Desert Gas area which underpins the portfolio’s gas reserves and is a key supplier of gas to the domestic market.

Source: OGInsights

 The highlights from each area are below.

Western Desert Gas

This area has been a key source of growth in recent years and accounts for 80% of Apache’s Egyptian 2P reserves (Wood Mackenzie). The area comprises three sub-areas with the Khalda Area, which has been producing since the 1970s, being the most established. The Fahgur, Sushan and Matruh Areas all commenced production post 2005 and have all been a target area for exploration. Production in the Western Desert is currently constrained by lack of gas processing capacity (currently 900mmcf/d) and further investment to debottleneck the facilities is dependent on increase in gas prices.

Apache Merged Area

The blocks in this area were acquired from BP in 2010 with production underpinned by two fields: Abu Gharadig and Razzak. Both of these fields are mature and in terminal decline, although horizontal drilling and water flooding efforts have been successful in arresting declines. The area is considered as underexplored and exploration success will be important to maintain production levels in the longer term. A seismic programme in 2010/11 and subsequent simulation studies has helped Apache identify new targets for future exploration and development.

East Bahariya Area

Apache aggressively explored the East Bahariya block between 2000-2005 bringing on-stream a number of discoveries. Since 2005, Apache has implemented water flooding on all the fields in the block which has boosted production. In 2008, the Heba Ridge cluster of fields were discovered which is now a key growth area on the block. Apache acquired the nearby El Diyur and North El Diyur blocks after recognising the

extension of one of the East Bahariya reservoirs into these blocks.

Qarun

The fields on the Qarun block are mature and in decline with production expected to cease in the next few years. The East Beni Suef block is also in decline, although Apache has been able to sustain production through water flooding. Exploration success on East Beni Suef has also helped to maintain production, although discoveries have been small in size (1-5mmbbl).

Apache exports its production via an extensive network of oil and gas pipelines and facilities. A schematic of the network is shown below.

Source: OGInsights

Source: Apache Egypt EIA
https://www.miga.org/documents/Apache_Egypt_2004_Egyptian_Oil_and_Gas_Activities_EIA.pdf

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Apache's Egyptian Jewel

Apache entered Egypt in 1994 and has since built up a dominant onshore position through a series of acquisitions and an aggressive exploration campaign. It is the largest acreage holder in the Western Desert and operates 24 licences. In 2010, Apache expanded its position through the acquisition of BP’s entire Western Desert portfolio as part of a wider transaction involving BP’s North American assets. In 2013, Apache divested 33.3% of its Egyptian portfolio to Sinopec for USD3.1bn in an effort to refocus on its North American business.

Apache’s Egyptian portfolio contains c.594mmboe of 2P reserves (Wood Mackenzie) as at the end of 2014 with about half of these reserves being gas. Gas production is an important part of Apache’s business, which is a material supplier of gas to the domestic market with a 12% market share (excluding Sinopec’s interest in the portfolio). All gas is sold to EGPC.

One of the biggest concerns for Egyptian operators over the past couple of years is the receivables balance due from the EGPC. To date, EGPC have not defaulted (to Apache or any other operator); in fact, EGPC have been aggressively paying down the balance since the beginning of 2015. To manage payment default risk, Apache has insurance with USD300mm of cover from the Overseas Private Investment Corporation  and this is in place until 2024.

Egypt has been one of Apache’s success stories, where production and cash flow have grown strongly with each USD1mm of investment generating USD2mm. This has be driven by strong and consistent exploration success – success rate has averaged above 80%. The company holds a large acreage position with 72% still undeveloped which will provide significant opportunities for the future.

Historical production

Cash flow growth

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Apache divesting international assets? A hard one!

On 31 July 2014, Apache announced its Q2 2014 results

• Apache said it was looking to exit its Canadian LNG positions and was considering options around its international assets
• This comes amidst Jana Partners, a hedge fund which recently picked up c.USD1bn of shares in Apache, wrote to investors arguing that Apache should focus its efforts on the North American onshore
• Reasoning behind this is that over the last few years, a number of North American onshore pure plays have outperformed Apache
• Apache's international assets, it is argued, are diluting its North American onshore story
• However, analysts do not necessarily agree
• Apache's international assets, especially those in Egypt and the North Sea, generate significant free cash flow for the group
• These are areas of existing production and are low risk operations
• The cash flows are important for the funding of the North American portfolio
• It is further noted that given the number of North Sea assets on the market, the geopolitic issues plaguing North Africa and the relative maturity (though strong cash flow generation) of these assets, it is unlikely that Apache will fund a buyer willing to pay full value
• Its other main operations are in Australia, including the Wheatstone LNG project

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