Turkey's natural gas offers much needed energy options

New Black Sea gas play: challenges and opportunities

• The Sakarya gas field is located in the Turkish sector of the Black Sea in excess of 2,100 meters of water (wd), roughly 175 km offshore Eregli, Turkey. The discovery well was drilled in 2020; subsequent appraisal wells and new field finds increased discovered resources from 320 billion cubic meters (bcm) to 710 bcm of lean natural gas. 
• Plans include a first phase, onstream in 2023, and a second phase due by 2028. First phase called for 10 production wells delivering 10 mcm/d (3.65 bcm/y). Full phase development calls for another 30, hence total output of 40 mcm/d (14.6 bcm/y). 
• TPAO operates the field with 100% equity assuming all reservoir, operational and financial risk. Development incorporates a subsea natural gas production system (on the seabed), 170 km submarine pipeline to shore, and an onshore gas processing facility. The critical partners for TPAO are Schlumberger and Subsea 7.
• TPAO has never developed a deepwater field before, with shallow water/onshore experience only. There are only a small number of producing hydrocarbon fields at a depth greater than 2,000 meters in the world. Drilling an ultra-deepwater exploration well is one thing. Developing a field in 2,000 wd is quite another. From a risk management perspective, 100% equity in an ultra-deepwater field is rare. 
• Successful completion of the first phase and timely full phase achievement will be a major achievement for TPAO, confirming a major step change in institutional capacity. Once onstream, production performance over the coming months is critical. And then meeting the full phase critical path timetable over the next four years. Equally critical to fully capturing its Black Sea resource potential will be ongoing exploration activity and success. For maximum impact, TPAO’s new gas play will need to double or triple its discovered resource base, currently about 710 bcm (20 tcf).  
• Many exploration wells are needed to fully test the commercial limits of the new play. The only NOC (or IOC) that ever tested an entire deepwater basin’s potential, assuming sole risk, was Brazil’s Petrobras in the Campos Basin and first phase of the Santos Basin. When the pre-salt potential was confirmed in the Santos, Brazilian policymakers then decided to open up and bring in foreign equity partners to manage risk. 
• There are a number of deepwater operators active in the Eastern Med gas play, but all are unlikely to invest in the Black Sea alongside TPAO and potentially be hostage to the political pressure stemming from Turkish objectives and actions in Cyprus’ offshore. There are other deepwater-capable companies, but they are inactive in the region.
• Should Turkey wish for TPAO to fully exploit the new gas play, sole risk, this would be a major risk. A high cost deepwater exploration program will be required at the same time as the NOC proceeds with Sakarya development. Should Turkey wish to reduce risk it would require a different competitive landscape for the Black Sea, proceeding with selected partners and new contractual structures. TPAO will bear a heavy burden regardless; given the focus on control, the NOC will have equity in every contract and quite possibly be the operator by right of first refusal.         

Turkey: geostrategic energy player

• Domestic gas consumption was about 60 bcm/y in 2022, roughly one third of total energy consumption. Almost all gas is imported, about 55 bcm/y in 2022; of which around 40% is imported via the Russian pipeline (Blue Stream/TurkStream), 17% via the Iranian pipeline and 16% via the Azeri pipeline (TANAP). LNG from 10 different countries makes up the remainder. Russian and Iranian gas import volumes are not without risk; there have been interruptions planned or not. Azeri and Russian gas also transits Turkey reaching southern Europe via TANAP and TurkStream, respectively.
• At peak output by 2028, Sakarya output would represent 20% of Turkish gas demand, assuming some growth in the latter; it could back out imports, be leveraged for discounted pricing, or exported to higher value gas markets in Southern Europe (even LNG with sufficient volumes).
• The Turkish government envisions a commercial gas hub with multiple sources of natural gas and players, trading and selling, with enough independent activity to set a competitive price benchmark that buyers would trust. But Turkey does not have a competitive gas market (gas is subsidized, it is unclear what price will be paid for Sakarya gas; there are very few suppliers, mostly stated owned). Do southern European energy markets seek to access Russian gas via Turkey? Is Russia going to sell its gas cheaply to Turkey, in order for Turkey to turn around and realize a premium on that gas?
• And then there is trust. The one thing that Russia has taught European energy markets is that a trusted partner is the foundation for a reliable energy supplier or transit corridor. Why would European markets swap out their Russian risk in exchange for a reliance on Turkish gas which may be subject to the brinkmanship experienced in the Eastern Med and in other settings.   
• Maximum optionality for Turkey is created by an exploration effort intended to triple the current discovered resource, turning the new play into a natural gas province. To compare: discovered recoverable resource in the Eastern Med gas play is roughly 3,200 bcm (90 tcf);  Egypt’s Nile Delta Basin has about 2,650 bcm (75 tcf). This would provide Turkey with the ability to reduce import costs, buy advantaged gas from its neighbors at lower volumes, and consider an LNG export project.