Azerbaijan is experiencing difficulties in gas production and will struggle to fulfill its gas commitments around 2019-2020. Paris-based Petrostrategies consulting firm analyses the situation in its World Energy Weekly (September 12 issue).

The difficulties that Azerbaijan is experiencing in its attempts to restore equilibrium to its gas balance (between local consumption, reinjection into oilfields and exports) are raising concerns among its clients and partners. Baku has therefore made an increasing number of reassuring statements in recent weeks. The sooner than expected utilization of the production from the Absheron gasfield plays a key role in the Azeris’ reasoning. Thus, at the end of August, Socar stated (providing a rare amount of detail) that Absheron will now be able to start production as of 2019, rather than 2025, the date that had applied up to now. This new time horizon for a sooner than expected service start-up for Absheron corresponds to the planned start-up of production and exports for phase 2 of the Shah Deniz field. This coincidence of dates is no accident. A report that was published in July by the Oxford Institute for Energy Studies (OIES) expresses doubts as to Azerbaijan’s capacity to fulfill all of its gas commitments around 2019-2020.

According to the Oxford Institute for Energy Studies, Baku will struggle to fulfill its gas commitments around 2019-2020

Socar’s new roadmap for Absheron predicts a final investment decision as of the 4th quarter of 2017 and a fast-track development in the three years that follow. But the operator of this field (Total 40%), which is partnered with Socar (40%) and Engie (20%), has not yet given its go-ahead. The economic feasibility of a project of this scale would be difficult to ensure in the current market conditions. The FEED studies were carried out in July 2015. In principle, Total had 14 months in which to submit a development plan, but this deadline was postponed to November 2016 and a further deferment is likely. This field holds estimated recoverable gas reserves of 350 bcm and it is expected to produce 5 bcm/annum in phase 1, which could then hit 8 to 10 bcm/annum in phase 2 In Baku, it is no secret that Total is asking the government for “incentives”. Moreover, Engie’s financial situation is not very good and the French group might have to pull out of Absheron, rather than participate in a very big investment (in the region of $25 billion for both phases), which would aggravate its debt situation. If Engie were to pull out, who could take its place?

To obtain an idea of the economics of Absheron, one can look at the cost estimates for phase 2 of Shah Deniz. The characteristics of the two fields can be compared in terms of water depth, the thickness of the impregnated layers, distance from the coast, etc., but with one notable difference: Shah Deniz holds reserves that are three times bigger (1,200 bcm) than those of Absheron. According to BP (which operates Shah Deniz), the operating cost of the current phase 1 (which produces 10 bcm/annum) was $43/1,000 cu.m in the 1st quarter of 2016. The transit tariffs for phase 2 are believed to be $30/1,000 cu.m in Georgia, $103 in Turkey, along the Tanap gasline, and $70 for the TAP gasline, which is to form a link between the Greek-Turkish border and southern Italy. The Managing Director of Tanap contests the figure that has been provided for his gasline and says the transit tariff is set at $70/1,000 cu.m. Whatever the case may be, if the total production cost of Shah Deniz 2 (opex + capex) is put at $60-$70/1,000 cu.m, and if the transit tariffs are added to this, the following price band thresholds are obtained: $2.50 to $2.75/MMBtu for a gas delivered at the Turkey-Georgia border, $4.40 to $5.60 at the Greek-Turkish border and $6.35 to $7.55 on arrival in southern Italy. By way of comparison, the average price of the gas imported by Germany was $5/MMBtu in the 1st half of 2016 (PETROSTRATEGIES, September 5, 2016).

Last year, Baku had to draw from its gas inventories and replace gas with fuel oil in a number of power plants․

Azerbaijan’s gas balance started to get worse when it became necessary to increase the injection of gas into the oil reservoirs of the Azeri-Chirag-Deep Guneshli (ACG) fields, which are operated by BP, in order to boost the pressure there. The production from these fields peaked in 2011 without reaching the planned target and it then began to decline. Urged by President Ilham Aliyev to stop the decline, BP intensified the injection of gas. Thus, in 2015, according to Socar’s figures, 7 bcm of gas were injected into ACG. A total of 29.5 bcm of gas were produced at the wellhead during that year in Azerbaijan. 6.6 bcm were exported to Turkey, 2.2 bcm to Georgia and 10.9 bcm were earmarked for domestic consumption. The rest, i.e. around 2.8 bcm, was flared. 10 bcm of the working gas output (i.e. without flaring, but with reinjection) of around 26.7 bcm in 2015 was ensured by the associated gas from the ACG fields, while 9.8 bcm came from Shah Deniz 1 and 6.9 bcm was extracted from the fields operated by Socar.

The extremely tight gas situation in Azerbaijan at first forced the country to decline requests to raise gas deliveries to Georgia over the winter of 2015-2016, while Tbilisi was asking for this increase with insistence. Faced with the outcry in Georgia resulting from this refusal (and as the Georgians refused outright to purchase gas from Russia), Azerbaijan decided to increase its deliveries to its neighbor in the west, by opting to draw from its gas inventories and replace gas with fuel oil in a number of its power plants. Baku is also planning to import 3 to 5 bcm/annum of Russian gas. But the negotiations are stalling over the question of prices: the Azeris are asking for a very low price, arguing that this gas is going to be injected into oilfields. The Russians reply that the use of this is not their concern and are thus asking for the market price. In the meantime, at the beginning of 2015, Socar invited one of the biggest private gas consumers in Azerbaijan, methanol producer Azmeco, to purchase the gas that it needs directly from Russia: up to 2 bcm/annum in a normal year. In June 2015, the state-owned company also announced that the Oil and Gas Processing & Petrochemical Complex project (OGPC - 10 to 12 bcm/annum) has been postponed indefinitely. Although Socar claims the opposite, this project might never go ahead, unless Azerbaijan’s gas balance makes a marked improvement.

Apart from Absheron, Azerbaijan could also turn to the production of gas from deep layers located under the oil in the ACG fields. The reserves that are trapped there are estimated at around 235 bcm, but it is clear that at current prices, their exploitation would be difficult to justify. The production from Socar’s fields could be maintained, at best. Thus, no matter which way Baku turns, its own sources of additional gas volumes are limited. In May 2016, against all the evidence, the Azeri Deputy Energy Minister, Natig Abbasov, stated that his country could export 50 bcm/annum of gas! On the basis of the current and forecast uses of the gas in

Azerbaijan, such an export level would require a total output of around 70 bcm/annum. Adding up all of the sources known today (with projected volumes of 26 bcm on Shah Deniz 1 & 2, 10 bcm of associated gas on ACG and up to 10 bcm on Absheron), even supposing a stable production of 7 bcm is maintained from Socar’s fields, would give a maximum output of 53 bcm. OIES’s projections are not even this high. Its scenarios forecast an Azeri production of 30.7 to 42.2 bcm on the 2025 time horizon (see table).