As the largest non-OPEC oil producer in Africa as well as the continent’s second-largest natural gas producer, Egypt’s hydrocarbons resources and production play a central role in the nation’s economy. Exploration and production activity has not been significantly affected by the country’s ongoing political transition, with a handful of new investments having taken place since 2011. “Even with the uncertainty, Egypt is a major conventional player in energy and cannot be ignored,” Mohamed Al Ajeel, the country manager of the Kuwait Foreign Petroleum Exploration Company for Egypt, told OBG.
However, a number of long-standing challenges remain. These include an oil production level that has stayed flat in recent years and a rapidly rising demand for energy in the domestic market that has placed increasing pressure on Egypt’s exported gas supply. In tackling these challenges the government has formulated ambitious plans to join with the private sector to boost exploration and production in oil and gas, while also throwing its weight behind a drive to develop alternative forms of energy.
HISTORY: The nation’s first refinery was established by English-Egyptian Oil Wells Company in Suez in 1911 and commencing operations two years later. In 1922 it was joined by the Royal Governmental Oil Refinery, by which time exploration for further reserves was gaining momentum and managed through the Petroleum Search Authority. By 1937 the government had established its concession model, granting licences for areas of land of not less than 4 sq km, which were renewable on an annual basis.
By the 1960s the largest player in the market was Anglo-Egyptian Oilfields, a joint-venture between BP and Shell, but in 1962 it was nationalised and transformed into the Egyptian General Petroleum Corporation (EGPC) as the royalist era during which the private sector had thrived gave way to President Gamel Nasser’s brand of socialism. Private sector activity did not end there, however, and in fact has grown again over the years. A reorganisation of the sector in 2000 into separate authorities for oil, gas and petrochemicals was in part a move to more effectively manage the cooperation of the government and the many international oil companies (IOCs) that operate in Egypt.
PUBLIC SECTOR: The exploitation of natural resources for the purpose of meeting energy needs is overseen by two ministries: the Ministry of Petroleum (MoP), which governs the hydrocarbons sector through a range of parastatal agencies, and the Ministry of Electricity and Energy, which controls the government agencies charged with developing a fledgling yet increasingly significant renewable energy industry. Within the MoP, the EGPC takes the lead role with regard to the oil sector. Its broad mandate covers a wide remit, allowing it to act as the regulator, joint-venture partner, licence provider, refiner and marketer, thereby enabling it to provide a central point of reference for the industry.
EGAS: In 2001 the MoP established the Egyptian Natural Gas Holding Company (EGAS) as a parallel institution, intended to play a similar role within Egypt’s rapidly expanding gas sector as that of EGPC in the oil sector. Its primary responsibilities are the oversight of foreign investment in the upstream segment and the liquefied natural gas (LNG) industry, including both production and transportation. In 2003 the ministry undertook a further division of responsibility by creating the Ganoub El Wadi Petroleum Holding Company (GANOPE). Previously known as the South Valley Development Company, the new institution was granted authority over oil and gas development activities in Upper Egypt. Its purview includes over half of Egypt’s total landmass, including the large population centres of Sohag, Assuit, Qena and Aswan, and has seen some significant discoveries in recent years (see analysis).
As for downstream activity, in 2002 the government set up the Egyptian Petrochemicals Holding Company (ECHEM) to manage and market the nation’s petrochemicals industry. The organisation is currently deploying a 20-year plan, based largely on the nation’s natural gas reserves, to develop the sector through new investment and facilities.
PRIVATE SECTOR: A highly liberalised market has allowed the private sector to take the lead in exploration and production. By the end of the 2000s, around 80% of oil and gas services were operated by the private sector, and 90% of all exploration activity was conducted by multinationals, according to the African Development Bank. The market now contains more than 20 IOCs, including some of the biggest from Europe and the US, such as BP, BG, Eni and Shell, as well as mid-sized and independent players such as Apache and Dana Gas. Other notable market participants include Hess Corporation, Lukoil, Petronas, Repsol and Transglobe Energy.
LICENSING: Access to the market is granted through a standard licensing round mechanism and is arranged in the form of an agreement between the company and EGPC, EGAS or GANOPE.
Since the onset of Egypt’s political transition in 2011 all three authorities have held licensing rounds that continued to attract international interest, despite the country’s broader turbulence, although some sector players see room for improvement. “We hope that investors will start showing more interest in Egypt’s energy sector, given that the latest rounds by EGPC, EGAS and GANOPE attracted a low number of bidders,” Ahmed Farid Moaaz, the country manager and director of local energy development firm Sea Dragon Energy, told OBG.
The results of an EGPC bid round launched in September 2011 were announced in October 2012, and led to the awarding of 11 blocks to IOCs. A bid round launched by EGAS in June 2012 for exploration blocks in the Mediterranean and the Nile Delta led to eight blocks being provisionally awarded as of mid-2013. In the south of the country, meanwhile, 20 exploration blocks under the purview of GANOPE are currently being put out for licensing, with the results expected before the end of 2013 (see analysis).
REGULATION: The legislative framework surrounding the oil and gas sector is relatively light, with no general law governing all of its activities. The interests of IOCs operating in Egypt are instead guaranteed by the Investment Incentives Law No. 8 of 1997, which offers protection from nationalisation, confiscation and freezing of assets. The law also establishes the right of IOCs to own 100% of downstream ventures, while the authorities of the MoP, such as the EGPC and EGAS, retain the right to take a 50% share in all upstream initiatives in the country. The responsibility of regulating the sector falls to the MoP and its subsidiaries, which establish the production-sharing agreements by which the activities of the IOCs operating in Egypt are most directly governed. The terms of these arrangements can differ from block to block, but exploration periods can typically be up to seven years in duration, while subsequent production rights usually last for 20 years, with the possibility of five-year extensions thereafter. IOCs risk losing blocks if production does not start within four years, or if they fail to meet minimum spending requirements for operations.
POTENTIAL REFORM: Although the creation of EGAS was intended to provide the gas segment with the same sort of focused authority as that provided by EGPC to the oil segment, the intermingling of oil and gas reserves means that the responsibilities of the two bodies frequently overlap. The resultant regulatory arbitrage is a potential risk in the system. There have also been calls to introduce greater transparency at the regulatory level, particularly with relation to EGPC’s delayed payments to IOCs. “Our biggest concern has been the delays in payments from the government regarding our production-sharing agreements,” Maximillian Fellner, the general manager of RWE Dea Egypt, the Egyptian subsidiary of international oil and gas company RWE Dea AG, told OBG.
The government has considered reforming the way in which the sector is regulated for some years, and this remains a possibility when the political and economic environment stabilises. A strategy formulated in the latter years of President Hosni Mubarak’s administration would create an independent regulator for the sector, leaving EGPC and EGAS to play roles more akin to those of national oil companies in other jurisdictions, such as Saudi Arabia’s Aramco or Malaysia’s Petronas.
OIL: Egypt’s oil is widely distributed across several areas, with most discovered fields to date located in the northern half of the country, in regions such as the Nile Delta, the Sinai Peninsula, the Gulf of Suez, and the Western and Eastern deserts. Proven reserves have been growing steadily over recent decades, with BP data showing a rise from 3.4bn barrels in 1992 to 3.5bn barrels in 2002 and 4.3bn barrels as of the close of 2012. Exploration efforts continue to buoy the reserve total. According to the MoP, there were 270 discoveries in the 2000-10 period. In recent years the Western Desert has proved to be particularly fruitful for oil firms, accounting for 80% of newly found oil reserves and 64 separate discoveries in the 2009/10 fiscal year, according to EGPC.
The political unrest which has prevailed in the country since 2011 has not interrupted primary exploration activity, although during the initial stages of unrest, majors such as Shell, BP and Lukoil temporarily evacuated non-essential staff.
Onshore oil is relatively cheap and easy to find in Egypt, although a 2012 paper delivered to the Society of Petroleum Engineers asserted that only 9% of wells are naturally producing. Therefore, standard artificial lift systems are common throughout the industry, including beam pumping, electrical submersible pumping and gas lift systems, as well as the less commonly implemented hydraulic and progressing cavity pumping systems.
Continued exploration and the deployment of efficient lifting techniques is particularly important in the context of Egypt’s production level. After peaking at around 935,000 barrels per day (bpd) in 1996, the production trend has been one of gradual decline. By 2002, according to BP data, crude production had fallen to 751,000 bpd, and by 2007 this figure reached its record low of this century of 698,000 bpd. This was followed by a recovery in 2009 to 730,000 bpd, and levels have plateaued since that time. In 2012 Egypt produced 728,000 bpd of oil, which represented a 0.1% rise on the previous year and accounted for 0.9% of the global total.
According to the US Energy Information Administration (EIA), Egypt’s oil production had fallen short of domestic consumption since 2008. This has compelled the nation to import refined petroleum products at increasing volumes. Given that petroleum products are subsidised by the government, this has led to issues over rising costs. Further, refining capacity currently exceeds Egypt’s oil production levels, meaning crude oil is also imported for processing and, in some cases, re-exportation.
GAS: Natural gas was first discovered in Egypt in 1967 in the Nile Delta region. Alongside a number of offshore blocks in the Mediterranean, this region remains one of the two principal gas-producing areas in the country. Unlike Egypt’s oil resource, the country’s natural gas reserves have grown rapidly in recent years, establishing the segment as the most vibrant in the wider energy sector. In 1982 Egypt’s gas reserves stood at 14.1trn cu feet (tcf), most of it associated. A series of non-associated gas finds in the 1990s saw this figure rise to 60 tcf by the close of 2002, by which time it was clear that gas would play a major role in the nation’s future energy mix. Further exploration activity followed, and by the end of 2012 proven natural gas reserves stood at 72 tcf, or 1.1% of the global total, the third highest on the African continent behind Algeria and Nigeria. There is a widespread confidence in the industry that this figure will rise again as more blocks are opened up. EGAS believes there are at least 223 tcf in the Nile Delta region alone that have yet to be fully explored.
NATURAL GAS PRODUCTION: Production levels of natural gas have risen in a similar fashion. In 2002, daily production stood at 964bn cu feet (bcf), while by the end of 2012 this figure had risen to 2.15 tcf, or 1.8% of the global total. However, consumption of natural gas within the domestic market has also grown at a rapid rate, largely as a result of its increased adoption as a fuel for power stations (see analysis), rising from 935.8 bcf in 2002 to 1.9 tcf at the close of 2012. When combined with Egypt’s natural gas export commitments, this demand has placed pressure on the MoP to increase the rate of production.
Just three non-associated gas fields in the Nile Delta and the coastal offshore regions (Abu Madi, Badreddin and Abu Qir) account for around half of total gas production. However, it is widely believed that the easy finds in onshore and coastal Mediterranean areas have already been made, and Egypt’s gas production future lies in the more technically challenging deepwater offshore blocks. Deepwater exploration and production is a more expensive undertaking, and therefore exploration activity in deepwater blocks in recent years has fallen behind that in the Nile Delta, coastal Mediterranean and Western Desert. This has prompted the MoP to revise its pricing policies in order to pay a higher rate for natural gas produced from these challenging areas.
For many industry observers, Egypt’s ability to increase production of both oil and gas rests largely on its ability to establish a contractual system that balances the interests of IOCs and the nation. “The days of easily accessible gas finds are gone,” Jeroen Regtien, the chairman and managing director of Shell Egypt, told OBG. “We are working under more difficult and unconventional environments with more risk, therefore the terms and conditions must be renegotiated and modified to address this risk.”
While Egypt’s efforts to exploit its gas resource in the first years of this century met with remarkable success, with production doubling between 2000 and 2006, since 2010 production levels have reached a plateau, and even shown a slight decline. According to the “BP Statistical Review of World Energy 2013”, Egypt’s natural gas production peaked in 2009 at 2.21 tcf, before declining modestly to 2.16 tcf the following year. In 2011 production levels remained almost level, at 2.17 tcf, but the trend dipped back into negative territory in 2012 with a 1.2% decrease for a production level of 2.15 tcf.
CONSUMPTION & EXPORTS: While a production plateau, and even a decline, is a not uncommon feature of the hydrocarbons development cycle – the lengthy timescales of exploration and project development and the level of investment required to tap natural resources being notoriously difficult to pace at the strategic level – Egypt’s production slowdown comes at a time when consumption is rapidly increasing. In 2011 total natural gas consumption in the country stood at 1.75 tcf, but by 2012 this had increased by 5.7% to reach 1.86 tcf, 57% of which was accounted for by electricity generation.
Since 2004, Egypt has also been one of the world’s largest exporters of gas, shipping to markets in Europe, the US and South Korea, as well as a number of Arab countries through the Arab Gas Pipeline (AGP). In the 2011/12 financial year gas distributed through the pipeline brought in $1.96bn in revenue, a 2.9% year-on-year rise which established gas as the most valuable good shipped abroad after crude and refined oil, according to the central bank. Gas has thus been playing an increasingly central role in the national economy over the past decade: according to the Central Agency for Public Mobilisation and Statistics, it contributed 8% to total GDP at factor cost and nearly 56% to the value added to the mining sector over the period from 2007 to 2010. However, the past year has seen the tensions between supply, demand and Egypt’s commitment to its long-term export contracts come to the fore, compelling the government to make some difficult choices.
IMPORTING: In October 2012 it was announced that Egypt had agreed to import gas from Algeria and had commenced discussions regarding a similar deal with Qatar. The new arrangements were intended to meet government needs, which run the gamut from electricity production to the operation of government-owned factories, but by November 2012 it was clear that the private sector industries would also be granted permission to import gas in 2013. November 2012 also saw the bid closing date of the tender for a new LNG import terminal, which will include a floating storage and regasification unit (FSRU) and all the necessary facilities, equipment and pipelines to enable gas to be fed directly to the national gas grid. Under the terms of the contract, the supplier will enter service agreements to establish the facility on either the Mediterranean or Red Sea coastlines, and will be able to sell the imported gas in the Egyptian market via the grid in return for a transportation fee. The tender details also revealed the urgency with which the government viewed the situation: according to the tender document, priority for issuing approvals will be given to offers with early first delivery dates, starting from May 2013.
Before the close of 2012, one of Egypt’s foremost private equity firms, Citadel Capital, announced that it had entered into a joint venture with Qatari investors and Doha-based investment bank QI nvest to build the FSRU for LNG. The Egyptian firm has taken a 49% stake in the project, with the Qatari interests retaining a 51% interest.
While Egypt’s ongoing political transition has made it difficult to assess the progress of projects that have a large component of foreign funding, the continued development of numerous initiatives that have received financing from Qatar and other countries in the Gulf, such as the Egyptian Refining Company (see analysis), suggests that Egypt’s FSRU facility will be developed as planned.
EXPANDING PRODUCTION: Egypt’s decision to import gas using a FSRU is a popular mid-term solution for countries seeking to address supply shortages as it is significantly quicker and cheaper than building permanent on-shore regasification facilities. It also provides a high degree of flexibility, as it will allow the country to relocate the facilities during periods of lower demand. However, importing gas in the volumes necessary to address local needs is an expensive business, estimated at around $10 per million British thermal units (mmBtu) based on global advisor Poten & Partners prices, and Egypt’s long-term interests therefore lie being able to meet both its domestic demand and export commitments.
CONTINUED EXPLORATION: The outlook for this possibility remains positive. Exploration activity continues to reveal more reserves, one of the most recent being a significant gas discovery in the Nile Delta by the UAE’s Dana Gas, announced at the end of June 2013. Dana, along with BG and Apache, reported a slight decline in its production in 2012, but its latest discovery in its West El Manzala concession is expected to add a further 1600 barrels of oil equivalent per day (boepd) to its current output of around 33,600 boepd. The discovery is the company’s 25th in Egypt since 2007.
Another important player in the Egyptian gas sector released welcome news in the first half of 2013: Apache announced the discovery of three new significant discoveries in May. A test well in its North Ras Qattara concession produced a combined rate of 1625 barrels of oil and 18.7m cu feet (mcf) of natural gas per day, and more appraisal drilling is scheduled be undertaken in the area during 2013. In Apache’s North Tarek concession, meanwhile, an exploratory well tested at 14.8 mcf of gas and 1552 barrels of condensate per day. A gas gathering system currently being installed by a joint-venture company owned by Apache and EGPC is expected to be in place by the end of 2013.
IN DEVELOPMENT: Of particular interest to many industry observers are the development plans of the UK’s BG Group, which has played a large role in Egypt’s natural gas segment and is currently responsible for around a third of all gas produced in the nation. It holds two onshore and three offshore concessions in the country. The West Delta Deep Marine (WDDM) concession, which it operates through a 50% joint venture with Petronas, has to date yielded 14 gas fields, the production from which is directed to the domestic market, and the LNG plants at Idku and Damietta. The fields have undergone a number of developmental phases to maximise hydrocarbons recovery. In 2010 BG commenced its Phase 7 pipeline and compression project, which involved the installation of 68 km of pipe and onshore facilities.
In late 2011 Phase 8a, which comprised the drilling, completion and tie-back of nine sub-sea wells, came on-stream. This was followed by the first gas from Phase 8b, a deepwater development which built on existing sub-sea infrastructure, in June 2012. With the completion of the Phase 8a and 8b projects, the WDDM concession will have a total of 51 sub-sea wells. The company has now turned its attention to WDDM Phase 9, current plans for which include additional infill wells, new development wells and further workover programmes aimed at ensuring the concessions continued productivity.
THE CONTRACTUAL CHALLENGE: Although the term “concession” remains in use in Egypt, the bulk of oil contracts with IOCs take the form of either production-sharing agreements or joint ventures. Egypt employs a hybrid contractual mechanism, according to the stage of production at a given project. After the initial bidding round, concession licences limited to a geographical area are granted to IOCs, and in some cases licensing fees and signing bonuses are applied. After the discovery of an oil or gas resource the concession arrangement is concluded, a development lease issued and a joint venture is formed between the relevant MoP authority and the IOC. The joint venture prepares a development plan, which must be approved by the ministry, while the IOC remains responsible for the operational and financial concerns of exploration and development.
Once production commences, the relationship between the IOC and the government, represented by the MoP, is altered once again, now changing from a joint venture to a production-sharing agreement – a model that has become increasingly popular with oil-producing nations wishing to retain ownership of their resources since it was first introduced by Indonesia in the 1960s.
Since the political uprising of 2011, issues related to the contractual agreements governing Egypt’s gas and oil sectors have come to the fore. The prices EGPC and EGAS pay for oil and gas produced by IOCs is determined by weighted formulas tied to international market rates. However, alongside cost-recovery issues within contracts, the pricing structure has been seen as a disincentive to further exploration and production by the private sector.
A more challenging scenario has evolved with relation to IOCs as Egypt’s fiscal position has deteriorated over the past two years, stemming from the generous subsidisation of gas and refined products by the government. While the government, through the MoP and its agencies, purchases gas at a capped rate, it makes gas available in the domestic market at much lower rates – a discrepancy which caused EGPC to run up high levels of debt and fall behind on payments to IOCs in 2012.
While no official figure regarding its obligations has been released by the state-owned company, press report estimates range from $4bn to $7bn, and the issue has risen to such prominence that many industry observers believe it is a potentially significant block to future development. “Egypt continues to go through a very difficult transition period, but there are encouraging signs from both the ministry and the EGPC. The new oil minister has made it clear that reducing the debt to IOCs is one of his priorities,” Brian Twaddle, the country manager and director of TransGlobe Energy’s Egypt operations, told OBG. “This has been the biggest concern for IOCs and investors over the past two years.”
The question of subsidies is a long-term issue made more complicated by its political sensitivity (see Economy chapter), which some sector leaders believe needs more attention. “Privatisation is the last thing we want to do now. The market is growing so much that there is plenty of room to give to the private sector, so the question is deregulation. We need to give top priority to two issues: deregulation of energy pricing and clarity on energy subsidies, while developing a strong energy regulatory authority,” said Khaled AbuBakr, the executive chairman of TAQA. In the meantime the MoP has shown its willingness to create an amenable contractual regime: under a new price scheme introduced in 2013, EGAS has raised the price that it will buy gas from producers from $2.65/mmBtu to a varying schedule of between $3.95/mmBtu to $5.88/mmBtu.
This change seems to have mollified investors somewhat. “The biggest issue for us today is the payment issue, but long term I don’t see any particular difficulties in doing business here,” Maqsood Sher, the president of GDF Suez, told OBG.
REFINING: Egypt has the largest refining sector in Africa, according to the Revenue Watch Institute, with nine refineries, most of them operated by EGPC and other state-owned agencies. The largest refinery currently in operation is the El Nasr facility on the Suez Canal, which has a nameplate capacity of 146,000 bpd, while the nation’s aggregate refining capacity as of January 2012 was 726,250 bpd, according to the Oil and Gas Journal. However, Egypt has an ambitious refinery expansion plan that aims to boost capacity by another 600,000 bpd by 2016.
However, shortfalls in diesel supply seen in 2012 underlined the need for basic fuel distillates in the market, an issue which is currently being addressed by the largest refinery project seen in Egypt for years. The ageing Mostorod refinery, located in the northern suburbs of Cairo, is the second-largest in the nation and the site of a public-private partnership (PPP) to build a new refinery that will take currently unused atmospheric residue from the existing facility and transform it into a number of sought-after products, such as diesel and kerosene. Financing for the project was successfully closed in the summer of 2012, and the new facility is expected to be operational by 2016. The development will have the capacity to produce 4.1m tonnes of high-quality oil derivatives per year (see analysis).
A methanol production facility in Damietta operated by EM ethanex, a joint venture between various state-owned sector bodies and Methanex, is also helping to meet demand for transport fuels. “Methanol use in fuel blending has seen successful applications elsewhere in the world and it can become part of the solution to the government’s large energy subsidy bill,” Kamilia Sofia, EM ethanex’s CEO and managing director, told OBG.
EXPORTS: Egypt’s benchmark oil blend is Suez, which is characterised by a relatively high sulphur content and therefore is sold at a discount to the Brent standard. Egypt’s exports of refined petroleum products have decreased over recent years, according to the EIA, falling from around 103,000 bpd in 2006 to 90,000 bpd in 2010. However, accurate data for hydrocarbons exports is not readily available, and some estimates place the 2010 figure at 95,000 bpd and record an increase to 114,000 bpd for 2011. “Exports are not the priority now for the Egyptian petrochemicals sector, as there is not enough output to cover the foreign markets and local demand,” Ahmad Al Bordini, the chairman and CEO of Sidi Kerir Petrochemicals, told OBG.
The lack of export growth for crude products reflects the rise in domestic demand for products such as motor gasoline, distillate fuel oil and kerosene, but Egypt continues to export a wide array of refined products, such as jet fuel and residual fuel oil, to a number of markets. In 2011 the most popular destination for the nation’s crude refined exports was India, which accounted for 51% of the total followed by Italy (22%), China (6%) and Israel (4%).
A key infrastructural component of Egypt’s oil exporting activity is the Suez-Mediterranean, or Sumed, pipeline. A joint venture project between Egypt, Saudi Arabia, Kuwait, the United Arab Emirates and Qatar in 1973, the pipeline commenced operations in 1977 and connects the Ain Sukhna terminal on the Gulf of Suez with the offshore terminal at Sidi Kerir, near the northern coastal city of Alexandria. The 320-km pipeline has a capacity of 2.3m bpd and, according to the EIA it carried an average volume of 1.7m bpd of crude oil in 2011 – which equates to over 3% of the annual global seaborne crude oil traded that year. The Sumed pipeline is also key as it provides an alternative route to the Suez Canal and a possible export route from some Gulf nations should the Strait of Hormuz be closed down.
DRY NATURAL GAS: Egypt commenced the export of dry natural gas in 2003 and rose rapidly to reach a peak of 647 bcf in 2009, according to the EIA. According to the petroleum minister, increasing domestic demand and low international prices resulted in a government decision to implement a two-year moratorium on new export agreements in 2008. By 2010 total dry natural gas exports had declined and continued to fall further in 2011, to 371 bcf. This occurred partly a result of the effects of regional unrest on Egypt’s dry gas export infrastructure.
The 1200-km AGP connects Arish on the Mediterranean coast of the Sinai Peninsula, with Aqaba on Jordan’s Red Sea coast, and the Syrian cities of Damascus and Banias. Construction of the pipeline was enabled by a 2001 memorandum of understanding between Egypt and Jordan, an agreement which in later years was expanded upon to include Syria and Lebanon, while a further side deal resulted in the creation of a gas supply to Israel in 2008.
Since that time both Iraq and Turkey have signed deals in what has developed into a regional project. However, the inclusion of Israel in the agreement has proved controversial, and in 2011 alone the pipeline’s Egyptian section was bombed nine times. In October 2012 Cairo suspended AGP exports to address a spike in domestic energy demand, forcing Jordan to resort to expensive oil imports, but Jordanian officials negotiated a resumption of supply in 2013. Regional unrest has placed a question mark over future development of the pipeline, which includes an agreement to construct a second phase of the Syrian section that would connect it to the Turkish border, with a potential link at a later stage to European gas markets via the Nabucco pipeline project, and an Iraqi proposal to connect with the AGP as an outlet for its gas exports.
However, while dry gas exports continue, Egypt’s status as major natural gas exporter is largely built on its adoption of LNG technology. As well as the pending FSRU, there are currently three LNG trains in the nation, based at two separate facilities, both of which are the result of considerable private investment and shipped their first gas in 2005.
SEGAS: The Spanish Egyptian Gas Company ( SEGAS) LNG facility is located in Damietta, 60 km west of Port Said, and when it commenced operations in 2004 it was the largest single-train LNG plant in the world. Its development is the result of a joint venture between Spain’s Union Fenosa Gas, which retains an 80% stake in the operating company and the Egyptian government via EGAS and EGPC, which each hold a 10% stake. The plant is supplied with gas from BG Group’s West Delta Deep Marine Concession Area, and has the capacity to produce 5.5m tonnes of LNG per year using air-cooled refrigeration and fractionation, most of which has been sold into the Spanish market. A plan to construct a second train at the SEGAS facility to be supplied from the Satis offshore gas discovery is currently on hold due to growing demand for gas in the domestic market.
LIQUEFACTION FACILITY: Egypt’s largest liquefaction facility, Egyptian LNG, is located at Idku, around 50 km east of Alexandria. The two-train plant has a combined capacity of 7.2m tonnes per year, with the French and US markets the largest recipients. As with SEGAS LNG, international capital has played a central role in its development.
Designed with future expansion in mind, possibly up to six trains, Egyptian LNG is actually made up of a number of separate companies. The Egyptian Liquefied Natural Gas Company owns the site, the utilities and common facilities, while Train 1 is owned by El Behera Natural Gas Liquefaction Company, the shareholders of which are Petronas (35.5%), BG Group (35.5%), EGPC (12%), the Egyptian Gas Holding Company (12%) and Gaz de France (5%). Train 2, is owned by the Idku National Gas Liquefaction Company, which has a similar shareholding structure, without the participation of Gaz de France.
OUTLOOK: In the short term, while production is expected to proceed apace, political risk and policy uncertainty as Egypt’s political transition continues to play out is likely to continue to act as a brake on further sector development. Some of the central questions facing the energy sector, such as the abolition of subsidies that has been called for both by domestic reformers and international organisations such as the IMF (see Economy chapter), are unlikely to be resolved until after the election of a government with a clear mandate from the populace, and questions remains as to how Egypt will utilise its considerable hydrocarbons resources.
However, of the existence of those resources and the willingness of private players to invest in helping Egypt to exploit them there is no doubt. Indeed, in February 2013, Osama Kamal, the former minister of petroleum and mineral resources, announced the government had formulated a plan which envisaged attracting $72bn to fund exploration and production of gas and oil in the Western Desert and the Mediterranean. The continuation of IOCs’ activities, therefore, bodes well for the government’s longterm ambition. “The short term is a period of wait and see, but the long-term potential is incredible and we are very excited about the country,” Basil El Baz, the CEO and chairman of Carbon Holdings, told OBG.
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