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Central Asia on the move

States are looking for energy output, Central European ones for diversification and integration

Kazakhstan's oil production in 2018 promises finally to get the boost that the government has been banking on since the Kashagan project was first meant to come on line in 2005. Assuming no repetition of problems that have delayed this Caspian Sea project by 12 years, Kashagan should see output rise to around 370,000 barrels a day in 2018, up from 270,000 b/d in the last quarter of 2017, and to 450,000 b/d within two years—the Phase 1 design capacity first envisaged by the consortium's partners (see map).

This Kashagan production will help reverse the decline in Kazakhstan's crude output, which the energy ministry says will end 2017 at around 1.7m b/d. That's in line with the quota it agreed last year with Opec. But in 2018, Kazakhstan will either flaunt its limit or, by then, have formerly abandoned its part in the deal. It certainly can't afford to keep Kashagan on the leash after waiting so long for it to come good.

In the region's other major oil producer, Azerbaijan, the story in 2018 will be about stabilising output. It's another participant in the Opec deal—making a virtue of output losses that were bound to happen anyway. It will do well to hold production at around 0.78m b/d.

A major part of this effort will stem from the new production-sharing agreement (PSA) between the government and the consortium operating the Azeri-Chirag-Deepwater Gunashli (ACG) oilfield in the Caspian Sea. The field represents about 75% of Azerbaijan's output. The new PSA, which will run until 2050, sees the Azeri state oil company, Socar, increasing its share from 11.65% to 25%, with stakes held by its eight international partners falling proportionally. The field's operator, BP, now holds 30.37%.

Production from ACG averages around 0.585m b/d, down from the 2010 peak of 0.835m b/d and well short of the 1m-plus b/d expected plateau. With the fresh PSA-related investments, output could start to rise again and enable deep-sea gas exploration. But 2018 will be too soon for any significant progress. Opec, which wants to keep Azerbaijan in the pact it agreed with a host of non-members, predicted in October that Azeri oil production would actually decline, to 740,000 b/d in 2018. If so, Azerbaijan will be hailed as another cutter doing more than it pledged: its agreed limit was about 0.795m b/d. (Like many other involuntary cutters, Azerbaijan was urging Opec to extend the deal in 2018.)

The year ahead will also see the first natural gas produced from Shah Deniz 2, a giant project in the Azerbaijan sector of the Caspian Sea that will add a further 16bn cubic metres a year of gas to the approximately 9bn cm/y from Shah Deniz-1. According to operator BP, around $28bn in capital investment will be spent bringing the project on line and building the transport links to the Georgia-Turkey border. The under-construction Trans-Anatolian Natural Gas Pipeline (Tanap) will deliver 6bn cm/y of the gas to Turkey, with a further 10bn cm/y pumped to markets in Europe via the Southern Gas Corridor.

16bn cm/y—Shah Deniz 2 output

Looming over the Caspian and Central Asia region are the intentions of China, which in 2018 is expected to increase further its hold over oil and gas production and exports—not just in Kazakhstan, but also in Uzbekistan, Turkmenistan and even Tajikistan. The International Energy Agency estimates that fully half of Central Asia's oil and gas exports could go east by 2020—a shift from historic flows to Russia and Western Europe.

In Central and Eastern Europe, the priority for the region's governments, along with the European Commission, will remain diversification of gas supplies. Russia's hold over Europe's gas markets has been steadily weakening for years, helped in part by the wide-ranging six-year probe by the Commission into the alleged abuse of Gazprom's dominant market position in the continent's east. In March 2017, the Commission presented the draft compromise reached with Gazprom, and since then the concessions offered by Gazprom have been tested to assess their impact in the market. Assuming the remedies are working, in first months of 2018 the anti-trust case may well be closed.

The European Commission has also encouraged member states to diversify their gas sources. As well as Shah Deniz 2 gas coming via Tanap in 2018, more liquefied natural gas will reach Europe from places like the US and Qatar, as they seek buyers for excess supplies.

Poland's LNG terminal in Swinoujscie will see imports from Qatar double from 2018, while the country's dominant gas firm PGNiG says it's looking to sign mid-term deals on LNG supplies from the US in the first or second quarter of 2018. Gazprom, which supplies around a third of Europe's gas and in 2017 is expected to have shipped another record annual amount, says it will defend its market share. With a potential LNG glut in the offing, a price war is a possibility in 2018.

Crucial to Russia's European ambitions is the start of construction in 2018 of Nord Stream 2, a parallel pipeline to Nord Stream 1 that runs under the Baltic Sea into Germany. Nord Stream 2 will double the capacity to 110bn cm/y, but it's being obstructed by Poland and Ukraine—and now the US, concerned about Europe's increasing reliance on Russian gas.

In 2018, construction should start of Brue—a pipeline to carry 1.75bn cm/y of gas from Bulgaria and Romania to Austria via Hungary by 2019 and 4.4bn cm/y once the second stage is completed in 2022. Twelve countries have pledged to embrace the so-called "Three Seas Initiative"—a project to develop better interconnections in various fields, including gas, along a north-south axis. One goal is to connect Poland's LNG terminal with a pending project in Croatia, where construction of an LNG terminal on of the island of Krk is on target for 2019 completion.

Finally, 2018 will see the shifting of Belarussian products exports from Latvian and Lithuanian ports to Russia's Baltic ports stepped up. This, it seems, was the precondition to the resolution of Russia's and Belarus's oil and gas dispute in 2017. Belarus got cheap gas supplies for three years, some crude, and some Russian loans to finance debt repayments; and Belarus would reorient its exports through Russian ports. Russian interests in Eastern Europe certainly won't disappear in 2018.

Kashagan 2018: get there in the end?

After more than a decade of delays and soaring costs, the giant Kashagan oilfield in Kazakhstan's part of the Caspian Sea, with 9bn-13bn barrels of recoverable reserves, will finally start producing oil in 2018 at something like the rate its developers once hoped for.

In the last quarter of 2017, Kashagan's output reached 270,000 barrels a day, according to operator North Caspian Operating Company (NCOC), comprised of Eni, KazMunaiGas, Shell, Total, ExxonMobil, China National Petroleum Corporation and Inpex. Assuming no problems with the newly deployed gas-reinjection facilities, Kazakh officials say further engineering and design work in 2018 should bring output to 370,000 b/d that year and 450,000 b/d within two years. That's the Phase 1 design capacity—just 13 years after Phase 1 was supposed to happen.

Still, the possibility of something going wrong can't be discounted. Kashagan, due to its complex development technicalities—sulphurous oil under shallow waters in a climatically volatile region—first came on stream in 2013, eight years late and at more than double the predicted cost of $20bn, only for cracked pipes to halt production within weeks. After replacing more than 200km of pipelines, production restarted in October 2016. Industry experts continue to warn of technogenic earthquakes caused by the drilling of offshore subsalt resources, as well as environmental catastrophes resulting from oil or gas leaks.

Talk now among the NCOC consortium is turning to Phases II and III, which should ramp up production to 0.9m b/d and then to 1.5m-plus b/d. The latest NCOC statement says: "Phase II is in the initial design phase", while "further phases are still under concept selection". In 2008, those two phases were estimated to cost $120bn; given the problems and associated cost inflation with Phase I, that figure is sure to rise.

Source: Petroleum Economist

NJ Watson is Contributing Editor at Business New Europe

This article is part of Outlook 2018, our annual book looking at energy market trends for the year ahead. To purchase a copy, click here

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