Digging deep: With large tracts of the country unexplored, the best may be yet to come

In terms of performance and, particularly, potential, Algeria is a major player in hydrocarbons. According to BP’s “Statistical Review of World Energy 2013” (SRWE), it ranked 15th among the world’s oil producers in 2012, with output of almost 1.7m barrels per day (bpd), 1.8% of the global total. Its performance in natural gas ranked it ninth, with marketed gas at 81.5bn cu metres (bcm) in 2012 and world share at 2.4%.

Served by developed production and distribution infrastructure, its exports go mainly to high-consumption markets: primarily Europe for gas, and Europe and the US for oil. Proven reserves are substantial, with 12.2bn barrels of oil and 4.5trn cu metres (tcm) of gas – 0.8% and 2.4% of world totals, respectively – for 13th and 11th place in the global hierarchy. The potential is huge, with much of the country unexplored and estimates of its shale gas resources high and rising.

DOMINANT: Hydrocarbons dominate Algeria’s economy. According to the Bank of Algeria (BoA) they accounted for 36% of GDP in 2011 and 97% of export earnings in 2012. Of non-hydrocarbons exports, a huge proportion – 93% in the first half of 2013, according to foreign trade agency Algex – consists of hydrocarbons derivatives, mainly petrochemicals products.

Hydrocarbons production is also vital to public finances, having helped Algeria to achieve successive surpluses over the past decade (see Economy chapter): 60-70% of government tax revenues come from oil and gas. Hydrocarbons exports are also responsible for a formidable accumulation of foreign exchange reserves, nudging €148bn in March 2013, and financing one of the region’s biggest sovereign wealth funds, worth €58bn in 2012. In recent years the government has used the proceeds of hydrocarbons production to finance growth in non-oil segments and drive the long-awaited push to diversify away from commodities that is generally admitted to be necessary.

MIXED FORTUNES: Over the course of 2013, the energy sector has seen a spate of new discoveries and infrastructure expansion, which – alongside planned reforms to the regulatory framework – contributed to a fairly positive outlook. This is strengthened by an underexplored mining acreage with a drilling density of less than 14 wells per 10,000 sq km.

The year brought challenges too. Oil and gas output had ended 2012 down year-on-year (y-o-y), stoking worries about plateauing upstream production. These concerns were upstaged in January 2013, when Al Qaeda-affiliated terrorists seized a key gas-processing complex near In Amenas, an unexpected event given that the sector has been largely untouched by violence over the past few decades.

The incident ended quickly, following decisive action by the Algerian military. However, around 40 workers were killed and the attack had an impact on production, with the plant – which is responsible for around 10% of marketed gas output – still operating below capacity in October, with repair work ongoing.

Uncertainty has also been caused by allegations of corruption against officials at state-owned hydrocarbons giant Sonatrach in 2013, following previous accusations in 2010 and 2011 that resulted in several changes to senior management. Among other concerns for operators are the requirement to advertise for local labour, even when the relevant skills will not be available, and high service costs.

NEW LAW: There have been positive developments too. A long-awaited new Hydrocarbons Law came out in February. The El Merk oilfield has been brought on-stream, as has a modern liquefied natural gas (LNG) installation at Skikda. There has been movement forward on the key Touat gas field in the south-west, and several new hydrocarbons discoveries have been made. Abderrahmane Beloucif, country manager for Algeria for Baker Hughes, told OBG, “The adaptation of the legal framework governing Algerian oil and gas seems to take account of the changes that are occurring on both the regional and international levels. These new provisions are intended to achieve the objective of increasing national reserves by improving the quality and the number of deposits and strengthening Algeria’s position on the international market.”

SONATRACH: Parastatal Sonatrach is the single largest operator in hydrocarbons, and a product of Algeria’s immediate post-independence period, bolstered by the 1971 nationalisation of the sector.

The company is involved in all exploration and production (E&P) in Algeria, both on its own and as a legally required majority partner to foreign firms in others (as of mid-2013, 40 permits were operated by Sonatrach alone, and another 13 by Sonatrach and partners). It has a mandated monopoly on domestic gas, oil and oil-product pipelines, excluding those for retail distribution of gas, which are the province of another state company, Sonelgaz. Sonatrach is also the Algerian shareholder in the country’s three international gas pipelines and the various terminals on the coast – for oil and for natural gas liquefaction – that account for non-pipeline exports. Further, it owns all of Algeria’s oil-refining capacity – with a joint venture arrangement operating only in one small refinery – and appears set to own those refineries due to be built in the next few years. Via its subsidiary Naftal, Sonatrach also plays a role in domestic fuel distribution. Finally, it is a partner in various petrochemicals ventures and is involved in the electricity sector, as well as various non-hydrocarbons mineral activities.

Sonatrach has a range of specialist subsidiaries, including one for geological surveys, two drilling firms, a pipeline construction company, a shipping firm owning oil and LNG tankers, and even an airline. It has also been seeking to expand its international footprint – a previous CEO stated that the company was aiming to achieve production of some 120,000 bpd outside of Algeria’s borders. It has stakes of varying sizes in exploration blocks in Egypt, Libya, Mali, Mauritania and Niger, and an Algerian-Tunisian joint venture (Numhyd) with activities in both of these states.

Drilling of the first offshore wells in the Kaboudia field off Tunisia took place in 2011, while, in partnership with the Libyan National Oil Company, Sonatrach announced an oil and gas discovery in the Ghadames Basin south-west of Tripoli in February 2013. It also has a subsidiary in Peru, where it is a partner in the Camisea field and accompanying pipeline.

HEAVYWEIGHT: Sonatrach is by some estimates the world’s 12th-largest petroleum firm, its fifth-largest producer of natural gas, fourth-largest exporter of LNG and third-largest exporter of liquefied petroleum gas (LPG). Export revenues in 2011 were €55.8bn – a y-o-y jump of 27% on the back of rising oil prices – while domestic revenues rose by 10% to €2.4bn at 2011 average exchange rates. Partners’ production shares and assorted taxes, as well as normal labour and production costs, meant that 2011 net results were less spectacular but nevertheless substantial, at €6.33bn.

Sonatrach’s declared headcount in 2011 topped 63,000, although a 2012 company publication that included figures from subsidiaries stated the firm had 120,000 employees in 15 countries. Sonatrach is also a big investor. Investments in 2011 came to €9.3bn. This eased to around €7.8bn in 2012, but medium- and long-term plans are ambitious. In November 2012 the company’s CEO, Abdelhamid Zerguine, said that it would invest €62bn over the next five years – €9bn more than figures mentioned a few months before – with €12bn going to the downstream sector of refineries and the like, and the lion’s share, by implication, to upstream and midstream activities such as exploration, field operation and pipeline transport. Investment in 2013 alone would be €11.7bn, Zerguine said.

FOREIGN FRIENDS: While Sonatrach dominates – owning around 80% of equity in the upstream segment – foreign firms have a long-standing presence in Algeria. In June 2013 Ministry of Energy and Mining (MEM) officials told OBG that Sonatrach had partnerships with 32 foreign companies. Most of the big names are present. BP is active in gas projects at In Salah and In Amenas. The US’s Anadarko revived Algerian oil production in the 1990s and, with Sonatrach, has brought on a new complex at El Merk. France’s Total and GDF Suez, along with Spain’s Repsol and Germany’s RWE Dea, are active in the south-west.

Italy’s Eni, which has stakes in the country’s pipelines, has been present since 1981, and in 2012 was Algeria’s leading foreign producer, with equity production of around 80,000 bpd of oil equivalent. Eni is also interested in shale prospects, having signed a memorandum of understanding on the subject with the MEM, as have Royal Dutch Shell and Canadian independent Talisman, while Anadarko is reportedly eyeing shale deposits straddling the border with Morocco. Ireland’s Petroceltic is involved in a promising field at Ain Tsila in the Illizi Basin, while Thailand’s PTTEP and Russia’s Gazprom also have a presence.

INTERESTED PARTIES: A number of new investors have expressed interest in moving in, and the minister of energy and mines, Youcef Yousfi, reported talking to 80 companies about investment opportunities in the summer of 2013. The past few years have seen operating conditions tighten for foreign firms due to more stringent legislation, but that has not stopped new arrivals from setting up shop. Cepsa – a Spanish company owned since 2011 by Abu Dhabi’s International Petroleum Investment Company – is producing at the Ourhoud field. It was the only firm apart from Sonatrach to participate in the latest bidding round. Meanwhile, Indonesia’s Pertamina, keen to feed its domestic oil refineries, is in the process of buying a stake in three fields from ConocoPhillips for €1.36bn.

REGULATORY CHANGE: The legislation managing the energy sector has gone through a number of changes since 2006, which has been difficult for operators to keep pace with. A relatively liberal Hydrocarbons Law was passed in 2005, replacing 1980s legislation. It brought the system into line with international practice by creating specialist regulatory bodies where Sonatrach had doubled as regulator before. More downstream foreign participation was allowed and, while partnerships were still required, it relaxed ownership rules that had given Sonatrach the right to a 51% stake in any joint venture. However, the 51% requirement was reinstated in 2006, alongside a windfall profits tax on oil-producing firms operating under pre-2005 contracts, triggered when the price of oil rose over $30 per barrel, although the latter was successfully challenged through arbitration.

The impact of these changes is illustrated by the bidding rounds conducted by ALNAFT, the regulator responsible for managing the bidding process for exploration acreages under the 2005 law, as well as approving the resultant contracts and development plans. In the first round in 2008, which offered 15 blocks, just four were won by international companies: Eni, Germany’s E.ON Ruhrgas, Gazprom and BG Group. In the second, in 2009, it was three: alliances of Total with Partex, PTTEP with China National Offshore Oil Corporation, and Spanish company Repsol and GDF Suez with Italy’s Enel. The third round was held in March 2011, with 10 blocks on offer, but only one foreign company – Cepsa – was involved in the bidding.

The broader global slowdown in upstream capital spending was also a factor in the limited level of interest, but the government, in a bid to stoke activity and continue the trend of new arrivals such as Cepsa and Pertamina, introduced a new Hydrocarbons Law in February 2013. Among the primary changes, there is a shift from turnover to profitability as the basis of taxation. Above all, there are considerably improved conditions, in terms of both taxation and periods allowed for exploration and exploitation, for deposits defined as unconventional – including shale and tight sands – areas of great potential where foreign participation is most necessary (see analysis). The new law will be put to the test soon. A new bidding round is expected to involve around 20 blocks, and the minister of energy and mines, Youcef Yousfi, said in October 2013 that it would be launched within three months.

OIL PRODUCTION: The new investment will help augment crude production, which has seen moderate growth recently. The SRWE’s 2012 oil output figure for Algeria of 1.67m bpd includes not only crude (around 1.2m bpd) but also condensates and LPG. This puts it above Libya but below Angola, Brazil and Qatar, and well behind giants such as Saudi Arabia and Russia. Algeria’s oil production for 2012 was 0.9% down y-o-y – contrasting with a world output rise of 2%. Output peaked at 1.99m bpd in 2007, falling below 1.8m in 2009 and 1.7m in 2010, with 2012 representing the lowest output since 2003 and a drop of 16.3% on 2007, compared to 4.7% growth worldwide.

According to the SRWE, proven oil reserves stood at 11.3bn barrels in 2002, 11.8bn in 2003, peaked at 12.3bn barrels in 2005, but have been stable at around 12.2bn since 2007, implying that discoveries in recent years have been no more than what has been needed to replace oil extracted, a contrast to broader trends which saw proven global reserves rise by 22.4% between 2006 and 2012. At current rates of extraction, reserves represent only 20 years’ production.

Most oil production takes place in the country’s east. The giant Hassi Messaoud field operated by Sonatrach, which has been exploited for over half a century, still produces 350,000-400,000 bpd according to the US government’s Energy Information Administration (EIA). The province in which it is situated accounts for 71% of proven, probable and possible oil reserves, but the field is maturing, requiring enhanced oil recovery techniques. Other large fields are Ourhoud (150,000-200,000 bpd of crude according to the EIA) and Hassi Berkine (100,000-150,000 bpd), both of which are situated in the Berkine Basin and are fairly mature. The former is operated, in partnership with Sonatrach, by Cepsa. Hassi Berkine is largely a collaboration between Sonatrach and Anadarko.

ADDED CAPACITY: New capacity came on-stream in 2013 through El Merk in the Berkine Basin, a multi-block development involving Sonatrach, Anadarko, Eni, Maersk and Talisman, which is expected to produce 100,000 bpd of crude, 30,000 bpd of condensate and 30,000 bpd of LPG. Condensate and LPG will be yielded by gas production and treatment brought on-line by Sonatrach and Eni at Menzel Ledjmet East in February 2013. Oil developments worth, between them, 60,000-80,000 bpd are expected to come on-stream at Bir Seba and Takouazet in 2014-15.

Whether new capacity will offset decline in older fields is not clear, however. In October 2013 Yousfi announced an additional billion barrels of reserves at Hassi Messaoud, though details are still pending, as are the country’s forecasts for shale oil (see analysis), which is currently put by the EIA at 5bn barrels. Crude oil is also produced at various smaller fields and liquids production is supplemented by condensate and field-level LPG: output of condensate in 2011 was 10.4m tonnes and field LPG 7.1m tonnes, compared with 55.3m tonnes of crude.

GAS: Algeria’s reported annual gas output rose from just 2.5 bcm in 1970 to 14.2 bcm in 1980, 49.4 bcm in 1990 and 84.4 bcm in 2000, with a peak of 88.2 bcm achieved in 2005. As with oil, recent gas production trends have been more moderate. The SRWE’s figure for 2012 was 81.5 bcm, a drop of 1.7% y-o-y and nearly 8% down on 2005, though higher than the totals for 2009 (76.9 bcm) and 2010 (80.4 bcm). This diverges from wider trends, as global gas output rose by 1.9% in 2012 and by 21% between 2005 and 2012, with the US, Qatar and China major contributors.

EXTRACTION: Yet Algeria’s figures do not take into consideration the full amount of gas being extracted from the ground. The numbers exclude flaring, reinjection and shrinkage, corresponding to the category of marketed gas. The exclusions are significant, with total extraction twice as high as the amount marketed, according to OPEC. Flaring has virtually halved since 2000, but reinjection, largely to keep up pressure in ageing oil reservoirs, has often absorbed as much or more gas as has been marketed: for example, 77.4 bcm was reinjected in 2012, and more than 88 bcm in 2013.

As for proven reserves, Algeria is better placed in natural gas than for oil: according to the SRWE it has 4.5 tcm, which at present rates of marketed production would last for 56 years, although rising local consumption and increased reinjection may impact that.

Hassi R’Mel, which entered service in 1956, holds more than half of Algeria’s proven reserves and, along with Hassi Messaoud, was reported by Sonatrach to account for 53% of total hydrocarbons production in 2011. Other sizeable fields include Alrar, Hamra and Rhourde Nouss. The In Amenas complex, a partnership between Sonatrach, BP and Norway’s Statoil that came on-stream in 2006, has three trains with annual natural gas capacity of 3 bcm each, and operated at 7.8 bcm per year in total in 2011 and 2012. Further south, BP’s In Salah project, operational since 2004, also has a capacity of 9 bcm per year and draws on seven gas fields, alongside plans for four satellite fields.

NEW DEVELOPMENTS: New production will be added in the next few years. The Menzel Ledjmet East development that came on-stream in early 2013, involving Eni and Sonatrach, will produce upwards of 3 bcm a year. The following year should see Gassi Touil coming to fruition, with Japan’s JGC completing field processing facilities for 4.5 bcm per year of gas destined for the LNG terminal at Arzew. Longer term, the Sonatrach-Petroceltic-Enel project at Ain Tsila – the development plan for which was approved in December 2012 – will start producing in 2017, and should yield at least 3.5 bcm per year once at plateau production.

There will also be key developments in the southwest of the country, which is home to a trio of large projects. Sonatrach and Total, along with Cepsa, are investing in the 1.6-bcm-per-year Timimoun field, due on-stream in 2014. In the six-field, €2.3bn Reggane Nord development (2.9 bcm per year), Repsol (29.5%) is partnering with Sonatrach (40%), RWE Dea (19.5%) and Edison (11%). GDF Suez is Sonatrach’s partner in the 4.5-bcm-per-year, 10-field, €2.3bn Touat development, which is expected on-stream, like Reggane Nord, in 2016. Recent progress at Touat includes the award of a contract for collection and processing infrastructure to Spain’s Técnicas Reunidas in July 2013.

The three developments – collectively known as the South-west Gas Project – were first sketched out in 2002, indicative of the extended gestation period for Algerian gas projects. The plan also involves the GR5 pipeline, linking Reganne Nord to the main network, being completed in 2016. Yousfi has been publicly bullish about gas output, predicting a doubling within seven years and pointing to significant discoveries in the south-east and the south-west, though giving little detail. Longer term, shale gas development offers an enticing if complicated prospect (see analysis).

PIPELINES: Algeria has a well-developed system of pipelines. A 4300-km network operated by Sonatrach, centred on the Hassi Messaoud field and its pipeline hub of Haoud El Hamra, transfers oil and condensate from production fields to northern refineries and coastal terminals. The largest export terminal for hydrocarbons is at Arzew, but six others operate at Skidka, Algiers, Annaba, Oran and Béjaïa, as well as the port of La Skhira in Tunisia, which is supplied directly from some of Algeria’s south-eastern fields and via Haoud El Hamra. LPG produced in Algerian fields is also piped northwards from Hassi R’Mel, with a 4.5m-tonnes-per-annum (mmtpa) pipeline running from Haoud El Hamra, and work is under way to build a second, adding 6.5 mmtpa, to deal with rising LPG output in the south.

Hassi R’Mel is the hub of the country’s 10,000-km gas pipeline system, with key lines connecting it to the south-east and south-west and others running north to, among other destinations, LNG facilities at Skikda and Arzew, and connecting with major export pipelines. Sonatrach runs this network, though Sonelgaz – supplied with gas by Sonatrach – controls a separate 15,260-km, high-pressure gas distribution system delivering supplies to Algerian customers. EXPORT OR CONSUME?: Oil and gas exports have accounted for the bulk of the country’s public revenues, but the various products have seen similarly varied performances of late. Crude oil has been the mainstay of Algeria’s hydrocarbons exports and remains the largest single item, accounting for 39% of the relatively high total of €53.8bn in 2012.

High crude prices have helped offset the fact that, in terms of volume, crude oil exports have been in steady decline since 2005, easing from 970,000 bpd to 690,000 bpd in 2012, according to the BoA. The reasons for this are complex and interrelated. Moderated output is one, as is slowing demand, in part a result of higher US shale production. Other liquids – such as condensate and LPG – have also slowed. Domestic consumption is another factor: according to the SRWE, domestic consumption of oil increased from 250,000 bpd in 2005 to 367,000 bpd in 2012.

However, exports of refined products seem to be on the rise – a trend encouraged by refinery investment. While modernised refineries have allowed Algeria to export products that have higher value than crude, domestic demand is heavy and will certainly grow.

REFINERIES: With five oil refineries and one condensate topping refinery, the refining sector has an aggregate capacity of 570,000 bpd. It comprises the huge and recently upgraded Skikda refinery (330,000 bpd), neighbour to the condensate refinery (100,000 bpd), with two smaller refineries at Arzew (50,200 bpd) and Algiers (54,200 bpd) – slated for 28% and 52% expansion respectively – as well as two even smaller units in the interior mostly geared to meeting regional needs, namely Adrar (12,000 bpd) and Hassi Messaoud (22,000 bpd). In addition, construction of five new sites with a combined capacity of 32 tonnes per year is slated for completion by 2018 and include Hassi-Messaoud, Hassi R’Mel, Biskra, Tiaret and Illizi.

While aggregate output would seem more than enough for Algerian needs, capacity mismatches – aggravated in the last couple of years by refineries closing for reconstruction – have meant that petrol and gasoil have had to be imported, with refined products imports running to 2.5m-3m tonnes in 2012 and “energy” (mainly refined products) imports rising from €915m in 2011 to €1.37bn in 2012, according to the BoA. Full operation at Skikda and upgrades at other coastal refineries are expected to reduce this, though early 2013 figures suggest a continued rise. New refineries have been long mulled, but in April 2013 officials announced that Sonatrach had earmarked €11.4bn of its investment plan to 2016 for the construction of up to six refineries designed to double current capacity and ensure self-sufficiency up to 2040. Sites have been identified at Biskra, Tiaret and Ghardaïa.

One of the clearest messages emerging is that Sonatrach will be 100% owner of all refineries, presumably leaving the joint venture formed with China National Offshore Oil Corporation in the Adrar refinery a one-off. Another likely consequence is that, if these refineries come to pass, Algeria could become a much less significant exporter of crude oil. While this may be compensated by rising oil product exports, a booming local market will probably ensure that this compensation is only partial.

THREE PIPES: While local consumption and tightening global demand are challenges for Algeria – as they are for any hydrocarbons producer – one of the country’s biggest advantages is the fact it has a direct line to major gas consumers in Europe. Natural gas is transported abroad both by pipeline and by tanker as LNG – a trade that Algeria pioneered with exports to Britain in 1964. In 2012 LNG represented 9.2% (€4.96bn) of total hydrocarbons exports and pipeline gas 22.4% (€12.05bn), according to the BoA.

Aside from relatively small sales to neighbours Morocco and, especially, Tunisia – totalling around 2 bcm in 2012, according to the SRWE – Algeria’s pipeline sales of gas go to Europe, mainly Italy (20.6 bcm in 2012) and Spain (10.2 bcm), with minor onward sales to respective neighbours Slovenia and Portugal. Peaking at just over 39 bcm in 2005, pipeline sales stood at 34.8 bcm in 2012, and will be considerably lower in 2013. Until 2011, supplies went via two international pipelines, both fed from Hassi R’Mel. The Trans-Mediterranean, commissioned in 1983 and owned and operated by Sonatrach with Eni, goes to Italy via Tunisia and Sicily; the latest of several expansions, in 2010, raised its capacity from 27 bcm per year to 33.5 bcm per year. The Maghreb-Europe gas pipeline goes via Morocco to Spain, with an underwater section at the Straits of Gibraltar, and can carry 11.5 bcm per year.

A third pipeline, Medgaz, is also fed from Hassi R’Mel. It began operation in April 2011 and involves a 210-km underwater link from Beni Saf in north-western Algeria to Almería in Spain. Aside from Sonatrach (36%), the original shareholders were Spain’s Cepsa (20%), Iberdrola (20%) and Endesa (12%), and France’s GDF Suez (12%). Shareholdings are changing in 2013, however, with Gas Natural Fenosa receiving a 10% share as part of a wider deal with Sonatrach, and both Sonatrach and Cepsa exercising pre-emptive rights on stakes being sold by Iberdrola, Endesa and GDF Suez. As of October 2013, Cepsa holds a 42% share. Medgaz has a capacity of 8 bcm per year, though original plans envisaged the option of doubling this later.

The ability to deliver gas to the doorstep of consumers has helped Algeria establish itself as a key supplier to the eurozone, although the economic troubles in southern Europe have affected consumption. Exports to Italy fell from 26 bcm in 2010 to 20.6 bcm in 2012, and press reports in August 2013 suggested that exports to Italy were running at half the normal rate and that Sonatrach had agreed to a 10-bcm-per-year cut in volumes to be delivered under its main contracts, with Eni, Edison and Enel. Deliveries to Spain increased from 6.97 bcm in 2010 to 10.2 bcm in 2012, though this rise is well below the increase in capacity. GOING FOURTH?: Schemes for a possible fourth pipeline are still pending; the 837-km Galsi would connect El Kala in Algeria with Cagliari on Sardinia, crossing the island to run underwater again to Tuscany and on to northern Italy. Shareholders in the project company are Sonatrach (41.6%) and Italian energy firms Edison (20.8%), Enel Produzione (15.6%) and Hera Group (10.4%), along with the Province of Sardinia (11.6%). An 8-bcm-per-year, €1.75bn project of some technical ambition – the Algeria-Sardinia stretch was billed as the world’s deepest underwater pipeline – it was first conceived in 2003 and was held up by negotiations over routing, but completed its front-end engineering and design (FEED) in 2009. It has had its final investment decision delayed several times, however.

Relatively little has been heard recently of an ambitious fifth project, initially mooted in 2009, which would not involve Algeria’s gas but would use its pipelines as a gateway: the proposed Trans-Sahara Gas Pipeline (TSGP). The TSGP would take Nigerian gas more than 4000 km from the Niger Delta through Nigeria, Niger and Algeria to Hassi R’Mel, whence it could be conveyed to international pipeline terminals at Beni Saf and El Kala, thus accessing European markets. The project involved Algerian, Nigerian and Russian backing, and while the 2013 Nigerian budget earmarked funds for it, no developments have yet materialised.

LNG: A pioneer in the 1960s and possessing considerable and increasing liquefaction capacity, Algeria’s LNG segment is centred on units at the ports of Skikda and Arzew, and at the end of 2012 comprised four main plants. Two of them are at Skikda, one dating from 1972 with nameplate capacity of 1 mmtpa of LNG (roughly equivalent to 1.38 bcm of gas at normal temperature) and the other of 1981 vintage and having a 2.2-mmtpa capacity. The two Arzew units date from 1978 and 1981, with capacities of 6.6 and 8.2 mmtpa, respectively. Some smaller, older units exist but are not much used: one, known as the Camel and with a 1.2-bcm capacity, was taken out of operation in 2010. All capacity is owned by Sonatrach.

Algeria is acquiring two new mega-trains in 2013-14, with a combined capacity exceeding 9 mmtpa. One new unit came on-stream at Skikda in early 2013, having been built for Sonatrach – which financed the project – under a €2.1bn engineering, procurement and construction contract awarded to the US’s KBR in July 2007 for the Skikda mega-train and associated infrastructure. This has a capacity of 4.5 mmtpa and was conceived as replacement for three of six trains at the Skikda plant which were destroyed in an explosion in 2004. The second addition, due on-stream in 2014, will be a 4.7-mmtpa train at Arzew, to be supplied from a gas field being developed at Gassi Touil. The facility is being built under a €3.4bn turnkey contract by a consortium of Italy’s Saipem and Japan’s Chiyoda.

REDUCED DEMAND: While expectations are high, recent performance has been modest. Output was not far short of 26 bcm in 2005, and just under 25 bcm in both 2006 and 2007. However, the global slowdown hit foreign demand, and LNG exports have been consistently easing since, to 20.9 bcm in 2009, 19.3 bcm in 2010, 17.1 bcm in 2011 and 15.3 bcm in 2012, even as Qatari and Malaysian production increased. As is the case with oil, the explanations for this too are complicated, a result of changing global consumption, including shale gas production in the US and depressed demand in Spain, as well as greater domestic demand. Local consumption rose by 5.5 bcm between 2008 and 2012. However, modern capacity should boost Algeria’s place in an increasingly competitive international market. LNG may take up some of the slack left by lower pipeline exports: commenting on agreements to cut deliveries to Italy, Yousfi said that gas would be diverted into LNG sales on Atlantic Basin and Asian markets. Individual opportunities are also cropping up; for example, the UK seems keen to reduce its dependence on Qatari LNG and there is already a regasification joint venture with BP at the Isle of Grain in England.

PETROCHEMICALS: The petrochemicals segment is another claimant for gas resources, although the prospect of economic diversification and value-added exports make this potentially a beneficial development. Closely associated with Algeria’s refineries and LNG capacity, the segment produced 320,000 tonnes in 2011, down from 367,000 in 2010. In tonnage terms, the most important products were methanol, liquid nitrogen and helium – the latter produced in a joint venture between Sonatrach and Germany’s Linde at Arzew. Resins, PVC and ethylene are also produced.

In the long run, synthetic fibres, plastics and fertilisers are especially promising areas, with Sonatrach keen to cooperate with foreign partners. One success has been the Sorfert joint venture with Egypt’s Orascom Construction Industries, which in the summer of 2013 launched a fertiliser factory based on natural gas feedstock at Arzew, producing 800,000 tpa of ammonia and 1.2 mmtpa of urea. It is expected to serve both export and domestic markets, with a commitment to sell a certain quantity at below international prices on the latter. A similar factory is also being built in a joint venture with Oman’s Suhail Bahwan.

Ambitious plans exist to develop petrochemicals at Arzew, in the shape of a complex valued at €2.3bn. Low-cost, locally sourced gas and labour could be decisive advantages for a project that is expected to produce 450,000 tpa of linear low-density polyethylene, 350,000 tpa of high-density polyethylene and 410,000 tpa of monoethylene glycol. A cracker is to be built to produce the necessary 1.4 mmtpa of ethane. A joint venture between Sonatrach and Total was formed in 2007, with Qatar Petroleum entering the picture later as a 10% shareholder. Sonatrach at present holds 51% and Total 39%. Getting as far as a call for bids for FEED services in 2010, the project was paused, apparently over the scale of investments required in ethane extraction upstream of the cracker.

LOCAL CONSUMPTION: Rapid growth of local demand is one of the driving factors for the downstream segment: consumption of 367,000 bpd in 2012 represented a single-year rise of 6.9%.

Consumption of natural gas in Algeria has been growing far faster than production. Having hovered around the 20-bcm mark between 1988 and 2002, consumption rose in all but one of the years between then and 2012. Cumulative growth was 51% over the period, including an 11% rise in 2012 alone.

Pricing is an issue: Algerian fuel prices are among the lowest in the region – nearly five and six times cheaper than the Moroccan levels for petrol and diesel, respectively – a situation which the government has made it clear it is unwilling to alter, unsurprisingly given the sensitivity of subsidy policies in neighbouring countries. Occasional local shortages result, and the situation is complicated by underinvestment in the distribution and storage system managed by Sonatrach’s subsidiary Naftal. In some areas there is storage capacity for only a few days, Yousfi said in May 2012.

Another contributing factor is Algeria’s swiftly growing demand for and supply of electricity, with most capacity currently gas-fired. According to Sonelgaz this rose from 11.7 bcm in 2008 to 13 bcm in 2011, and topped 14 bcm in 2012, accounting for almost half of domestic consumption. The huge amounts of gas-fired capacity coming on-stream in 2013-17 – 16,900 MW all told – will be more efficient in gas consumption than existing plants.

ACCESS: Ease of access for clients is also driving consumption, through the expansion of public distribution systems for natural gas, predominantly serving households but also small businesses and industrial consumers. These accounted for 6.34 bcm (22%) of consumption in 2011, up 22% from 5.2 bcm in 2008, with Sonelgaz reporting a 18.2% rise in consumption by the similar but not identical category of low-pressure clients in 2012. The consumption rise has largely reflected a fast-increasing quantity of customers: the number of low-pressure clients rose from slightly more than 2m in 2005 and 2.63m in 2008 to over 3.66m in 2012 (with the relevant households representing 18m people, not far short of half the population). This reflects a determined effort by the authorities to roll out distribution networks, the total length of which rose from 16,000 km in 2000 to 28,900 in 2005, 42,100 in 2008 and 63,000 km in 2012, while the number of localities served has risen from 860 in 2007 to 1381 in 2012. Sonelgaz is expecting client numbers to pass 6m in 2019 and to have reached 8.8m in 2023.

POWER: Though per capita consumption of electricity is low by Libyan or even Egyptian standards – at 1091 KWh in 2011 – over 98% of the population has access to power. Consumption, especially peak consumption, is rising fast. Some forecasts envisage growth of 14% per year in the near future and the development of the power sector is a major priority. Almost entirely gas-fired at present (aside from some diesel capacity and one hydroelectric plant), installed capacity at the end of 2012 was around 13,000 MW, having doubled in 10 years. Yet available capacity was far lower, and the central grid could not meet peak demand of less than 10,400 MW in the summer of 2012.

Over 2000 MW of new or rehabilitated capacity had come on-stream by the summer of 2013; almost 4000 MW (including 495 MW of renewables) is expected by summer 2014; and a cumulative gas-fired tally of 16,900 MW between 2013 and 2017 is anticipated. Central to this is a deal with the US’s General Electric (GE) supplying turbines for over 8000 MW of combined-cycle gas turbine (CCGT) plants. Capacity accumulation is set to continue beyond 2017, supplied partly by local production facilities GE will set up. At the end of 2012 Algeria had 270,000 km of electricity distribution grids and 23,800 km of high-voltage transmission grids. Heavy investment in both is expected, with the transmission grid set to expand by 75% within three years. Increased reliability and better connection with southern regions are among the priorities.

Others changes are afoot in the utilities sector, according to Miloud Boudali, managing director of EPIC ERMA, which handles public lighting in Algiers. “The sector is seeing rapid innovation; the introduction of GPS surveillance and solar panels in the Algiers public lighting network are just two examples of technological advances in recent years,” Boudali told OBG.

While the scope for equipment provision and construction is sizeable and Sonelgaz can make joint ventures with private or foreign players in the generation sphere, only one large producer with a substantive private stake exists. The vast majority of new projects are slated to be wholly owned by Sonelgaz, and independent power production prospects are limited.

INTEGRATED APPROACH: A key aspect of the strategy for electricity production is integration, or the localisation of equipment production. According to Sonelgaz it is a requirement for those who want to supply equipment in future. The kit for the six CCGTs will be supplied from GE’s factories in the US. However, in the longer term GE is committed to investment in a joint venture with Sonelgaz that will produce 2000 MW worth of equipment per year at four facilities in Algeria. Holding a 49% stake in the joint venture, GE is expected to invest around €150m in this.

Algerian electricity demand – and the capacity to service it – will be growing long after the six CCGT plants come on-stream. Excluding renewables and on top of the capacity commissioned up to 2017, the 10-year plan envisages that forecast demand will necessitate an additional 13,700 MW of conventional generating capacity in the years 2018-23.

NEW SOURCES: Benefitting from a high insolation rate and hoping to mitigate rising domestic consumption, Algeria has embarked on a 20-year programme of renewable energy development, which aims to raise the share of renewables in national electricity consumption to 30% by 2030 (see analysis). Some 12,000 MW of renewables capacity is to be put in place, with headline figures for costs as high as €75bn.

Still in its pilot phase – with various projects designed to test assorted technologies – the programme shows signs of being mobilised to help meet demand from an electricity-hungry populace. An ambitious 400 MW of photovoltaic power is to be deployed in 2014. Full-scale roll-out starts in 2015, and the latest forecasts see upwards of 5500 MW of renewable capacity coming on-stream by 2023. The government seems strongly committed, with greater funds to be allocated to the scheme than to conventional gas-fired plants. A resolutely statist approach, an emphasis on local equipment manufacture and a lack of experience could still prove problematic, however. The 2011 programme also envisaged the possible development of up to 10,000 MW of renewables capacity for export purposes. While projects in Morocco continued under the German-led Desertec solar scheme, demand for such projects, given the required capital expenditure, may be modest until European markets see renewed growth.

NUCLEAR: Aside from renewables and relatively minor coal reserves that are not being exploited, the government is also looking to nuclear power as a way of diversifying away from (and economising on) hydrocarbons resources. The country has untapped uranium reserves of around 29,000 tonnes, which, according to Yousfi, is sufficient to fuel two 1000-MW nuclear units for 60 years. In 2008 it was announced that the country would commission its first commercial nuclear plant in 2020, with new units to follow at five-year intervals.

Aspirations were reaffirmed in the wake of the 2011 Fukushima disaster in Japan, but the timetable is now longer term. In May 2013 Yousfi said that the first plant would be commissioned in 2025, and pointed out that a nuclear engineering institute had been established to train the necessary engineers and technicians. Algeria has some nuclear experience in the shape of two experimental reactors – built with Chinese and Argentinian help and with a combined capacity of 18 MW – and has signed nuclear cooperation agreements with France, South Africa, the US and Russia.

WATER: Water is a scarce resource in Algeria, and the water infrastructure has been the subject of various government programmes over the past decade. Approximately €15bn was allocated to the water sector in the government’s five-year infrastructure plan to 2014. Dam building has been one area of focus: as of 2012 Algeria had 68 dams to supply fresh water, with capacity at 7 bcm, compared with 2.6 bcm in 1999, and 15 more dams are either under construction or planned.

Desalination of seawater has been another priority. The first big desalination plant – coupled with a power plant – came on-stream at Arzew in 2005 with a capacity of 91,000 cu metres per day. A programme involving the launch of 13 more plants by 2015, with a combined capacity of over 2.3m cu metres per day, was inaugurated by the start-up of a 200,000-cu-metre-per-day unit at Hamma, built and 70% owned by GE. Build-operate-transfer (BOT) has been the predominant method in the programme so far, with stakes usually of 51% held by foreign developers or consortia thereof in the 10 projects assigned since Hamma. Foreign partners have included Befesa Agua, Acciona, Aqualia and Singaporean specialist Hyflux, whose 500,000-cu-metre-per-day plant at Magtaa, near Oran, which came fully on-stream in 2013, is the largest desalination plant in the world. Magtaa is also exceptional because Hyflux’s stake is only 43%.

Despite implementation delays in some cases, eight of the 10 plants are now operational, though the ninth, being built at Tenes with Befesa Agua as the foreign partner, now seems likely to be commissioned in September 2014. The cost of the plants – including Hamma but excluding the hybrid Arzew unit – is in excess of €1.75bn. Three 100,000-cu-metre-per-day units from the 13-plant programme – at El Taref, Oued Sebt and Béjaïa – remain to be assigned, with the BOT approach likely to be abandoned. Another unit of similar size is planned at Jijel, but with no clear timetable.

In statistical terms, water supplies have improved, especially in the bigger cities. Daily supply in Algiers rose from 120,000 cu metres in 2002 to 1.2m cu metres in 2012, while in Constantine it increased from 60,000 to 200,000 over the same period, though this is partly offset by population growth. In Algeria as a whole, however, service is patchy. According to the Ministry of Water Resources, only 45% of the population has 24-hour access to running water. Another 30% has supplies daily though not continuously, 16% has water one day in two and 9% one day in three or less. The shortages are aggravated by system losses: a leaky system means losses of around 30% as of 2013. Outsourcing of water management to private companies in four big cities – Algiers, Oran, Constantine and Annaba – may have improved management there. Around 8m other Algerians are served by regional authorities.

OUTLOOK: Dependent on high energy export earnings, Algeria’s energy sector is faced with difficulties in increasing production or even holding it stable, with foreign demand flagging and domestic demand for oil and gas rising rapidly. Instinctively inclined to tight central control, it is nevertheless being pushed to make things more attractive for the foreign investors it needs. There should also be opportunities for growth in Algerian investment. “Algeria will rank among the biggest investors in energy sector from the MENA region over the next five years,” Mohamed Fechkeur, the president of Algerian hydrocarbons firm RedMed, told OBG.

The sector also has the huge job of developing the capacity necessary to meet growing domestic electricity demand. These tasks are formidable for their sheer size, in respect of conventional electricity, and for their novelty, in respect of renewables.

Uncharted challenges await in shale and nuclear energy. The underlying assumption of policy – regarding domestic electricity and gas consumption at least – is that the state can substantially finance both development and use. The situation is difficult enough with hydrocarbons revenues still relatively high and the financial reserves they have enabled still ample. Erosion of either might dictate a more radical approach.