Doubts hang over Azeri gas [NGW Magazine]
The announcement of a new oil and gas discovery in the Caspian Sea in mid-March was buried among reports of producers across the world implementing drastic cuts to their spending.
The find was made at the Karabagh (Karabakh) block off the coast of Azerbaijan, by Norway’s Equinor and Azeri national oil firm Socar. In a statement on March 19, Socar said the field contained enough oil and gas for cost-effective development. It did not say how much gas had been found but estimated the field’s oil reserves at over 60mn mt. Karabagh’s gas resources have previously been assessed at 28bn m3.
This is not the first well to have been drilled at Karabagh. US independent Pennzoil banded together with Socar, Russia’s Lukoil and Italy’s Agip to explore the area in 1995. The group entered a production-sharing contract and sank three wells, two of which found oil and one gas. But they abandoned the project in 1999, concluding that not enough hydrocarbons had been found for commercial production.
Equinor began undertaking studies at Karabagh in 2014 and signed a risk-service agreement with Socar in 2018 to develop the area. The Norwegian company confirmed the discovery to NGW, but without disclosing volumes.
“We are encouraged by this oil discovery. The KPS-4 well confirmed our [forecast] well result. We now need to perform more analysis of the well data to narrow the volume range,” Equinor told NGW. “Our intention is to continue to mature the field development project towards investment decision.”
Socar has been more bullish, indicating even before the new discovery that it wanted to bring Karabagh into production as early as 2021. Equinor told NGW it was working with the Azeri NOC to optimise project designs based on the latest results, while discussing a detailed project schedule. The company declined to say whether the development focus was oil only or both oil and gas.
“This topic is part of the project development work that we are undertaking at the moment,” it said.
Following the oil price collapse this year, however, Equinor has far more pressing concerns than advancing the Karabagh project. In line with similar moves by other major oil producers, the company has slashed its 2020 capital expenditure plan from $10-11bn to $8.5bn, while also reining in exploration spending from $1.4bn to $1bn.
Pennzoil and its partners withdrew from Karabagh in a year when Brent averaged $20/b. The benchmark is currently trading at $25-30/b, and is expected to remain within this range for some time, as coronavirus (Covid-19) lockdowns sap fuel demand and Opec+ producers gear up for what could be a lengthy supply war.
Karabagh’s development is also likely to be far down on Socar’s list of priorities. The company enjoys low production costs thanks to scale – a large share of its output comes from the giant Azeri-Chirag-Gunashli (ACG) oil project. But Azerbaijan depends on its profits to fund its national budget, which for this year needs $53/b oil to break even. Socar is yet to announce the extent of its spending reduction, but is very likely to take such steps for the national interest.
There are a number of factors that drive up the cost of Caspian Sea development, ranging from the harsh operating environment and reservoir complexity to logistical problems. Karabagh’s reservoirs are some 3.4 km under the seabed, although its location in shallow waters just 14 km from ACG, in which Equinor has a stake, works in the project’s favour. But until the market outlook brightens, its developers are unlikely to make serious progress.
Establishing new supply
Azerbaijan is heavily reliant on income from sales of oil from the BP-operated ACG project, but its production is expected to continue falling over the coming decades, save for a bump after the launch of a new platform in 2023. Faced with this decline, Baku is eager to develop new fields that can supplement ACG’s revenues.
Any new oil production can be exported westwards using existing infrastructure, such as the underutilised Baku-Tbilisi-Ceyhan pipeline. But commercialising new gas is more of a challenge. Domestic prices are low and the only route to market is the South Caucasus pipeline running to Turkey and the larger Southern Gas Corridor (SGC), due to start pumping gas to Italy this year. The combined 23bn m3/yr capacity is fully booked by the Shah Deniz field.
Socar and its partners have held market tests on an expansion of SGC that would enable the system to deliver an extra 10bn m3/yr of gas to Europe. The goal is to launch the project sometime in the mid-2020s.
Azerbaijan has enough gas reserves to justify the expansion. Both Shah Deniz and ACG could increase their production with additional investment phases. Most of the gas at ACG is associated with crude, and is reinjected to maintain reservoir pressure. But the aim in developing its deep gas layers is to boost commercial production.
Meanwhile in 2021, France’s Total is set to launch the first 1.5bn m3/yr phase of the Absheron project off Azerbaijan, although this gas will be sold locally. However, output could reach 5bn m3/yr under a second phase, and this additional supply is likely to be exported.
Equinor and Socar are also preparing to drill this year at the Ashrafi-Dan-Ulduzu-Aipar block – another site that was explored and then abandoned by an international consortium two decades ago.
BP, the biggest foreign investor in Azerbaijan, is exploring several new areas in the Caspian, including the Shafag-Asiman block, where it is hoping to find a large-scale gas reservoir. The company also aims to spud wells at the offshore Shallow Water Absheron Peninsula and D230 areas, as well as the onshore Gobustan block, but all of these projects may be put on hold in the present market conditions.
Azerbaijan also wants to attract foreign investors to realise the full potential of some of its existing fields. It has recently offered Russian private producer Lukoil a role at the Nakhchivan and Goshadash fields, and Socar is also seeking a partner at the Umid-Babek fields.
Export prospects
The next question is whether European consumers will want extra Azeri gas. While European gas demand is set to be flat or decline in the coming decades, its import dependency will increase as indigenous production – particularly at the swing Dutch Groningen field – falls.
“The region will need additional gas, but these additional gas imports will have to be very competitive,” Wood Mackenzie analyst Kateryna Filippenko told NGW.
With Russian gas and US LNG readily available over the long term, European prices will remain below $9/mn Btu until the end of the 2030s, WoodMac expects.
“Azerbaijan’s remaining gas resources are costly to develop because of their remoteness and technical complexity,” Filippenko explained. “Transport costs to Europe also add over $3/mn Btu, so new Azeri volumes will struggle to compete with Russian gas and LNG no matter how geopolitically attractive they may be for Azerbaijan and Europe.”
The $40bn SGC was realised thanks to significant financial and regulatory support from the EU and also had diplomatic backing from the US, anxious to dilute Russian influence in southeast Europe.
But as Brussels adopts a tougher stance against fossil fuels, Azerbaijan may not be able to count on this support for an expansion. The European Investment Bank was a major lender to the SGC but it will not lend to projects like this by the time any possible Azeri gas export projects are ready. Alternatively, SGC’s European leg, the Trans-Adriatic Pipeline, could end up being expanded in order to flow Russian rather than Azeri gas – giving Russia an alternative entry-point into a major gas market and precisely contradicting the point of the SGC.
“It has always been a possibility that Russia will book TAP expansion capacity for its own gas going via TurkSream, which would indeed be ironic given the initial diversification purpose of TAP,” Filippenko said. “Under EU rules, like any other shipper, Gazprom can seek to book expansion capacity in the upcoming binding phase of TAP’s market test.”
Without SGC being enlarged, prospects for gas development therefore remain weak in Azerbaijan, despite the country’s considerable reserves, estimated by BP at 2.1 trillion m3 proven. Given these conditions, Filippenko believes that in Karabagh’s case, Equinor and Socar are likely to target the field’s oil rim first, before considering its gas. Some of the gas produced may end up being reinjected to maintain pressure at some stage.
And while Azerbaijan has stranded gas assets as a result of export limitations, it is facing a supply squeeze at home. It has had to cover the shortfall with imports from Russia and Turkmenistan in recent years.
“The shortfall will be relieved when Absheron early production comes online in 2021, and longer term there are lots of options from the undeveloped resources,” Filippenko said.
Socar is also developing Azerbaijan’s gas-based petrochemicals industry, to facilitate investment in its resources. But it may struggle to advance this programme given the weak global economic outlook and the cutbacks it will have to make in response to low prices.