Oil

Approaching  the end of the big oil meeting on November 30^th, Brent oil traded just above $63 whereas US light traded just below $58. Azeri light prices continue to trade for more than $64. Amid the meeting of global oil producers in Austria, several countries announced their willingness to prolong output cuts while also disclosing their concerns about potential upcoming disagreements regarding extension, quotas, the timeline for duration and end. The current agreement expires in March 2018. Though, if everything goes on expectedly at the meeting, it will be extended either till the next meeting in June 2018 or to the end of 2018. The agreement was first reached between OPEC and non-OPEC countries in late 2016 and extended in May 2017. The agreed amount of cuts go up to 1.8M bpd. Despite the concerns over the collective action problems, most countries abided by their production quotas and global inventories decreased down to 138M barrels from 338M right before the production cut was put in place. Although all oil producers would want higher prices in a perfect scenario, in the current market environment, the ministers in Austria will be cautious in order not to tighten the market too much. In a tight market, the shale surge in the United States could come back and flood it once again. Therefore, currently, there is a natural ceiling of prices although nobody, including the traders and the ministers, knows what that magic number is. Recently, US shale producers have already started to increase their rig count, given the rise in oil prices within the past few months. This hints for the fact that these price levels are enough for shale producers to record profits for their day to day transactions. Any sharp increase in prices due to prolonging price cuts and a decline in inventories could spike another shale boom in 2018. Even for budgetary concerns, producers have different preferences over the targeted oil price. While shale producers are price takers in this market, Russia is content with $60 oil. However, for Saudi Arabia the situation is more complicated. The kingdom needs $70 oil for a balanced budget and would certainly benefit from higher prices amid the IPO of Saudi Aramco for more profits.  

Russia, Turkey and Natural Gas

Turkey’s attempts to diversify its energy imports are slowly bringing the expected results. In September, just surpassing Iranian supplies, Azerbaijan became Turkey’s second largest natural gas supplier by selling 519 mcm of Turkey’s 3.68 bcm gas imports. Although the change is minuscule, it is also symbolic of Turkish-Azerbaijani relations and also signaling the improving energy trade between the two countries. So far, in the first nine months, the Caspian republic exported 4.74 bcm of gas to Turkey. With the commencement of TANAP, Azerbaijan will solidify its status of being the second largest supplier for the Turkish market, behind Russia. Coupling with country’s recent FSRU investments for LNG and storage capabilities as well as the potential completion of TANAP in late 2017, Turkey is taking solid steps towards assuring energy supply security. While the storage capacity will rise to 10 bcm, 20 percent of country’s natural gas consumption, TANAP will increase non-Russian gas supply. Still, despite these developments, Turkey will continue to have Russia as its major source of energy (both natural gas and nuclear) for the foreseeable future. Meanwhile, Russia is also taking steps towards making Turkish Stream an essential part of European energy network. Russian natural gas giant Gazprom is looking for opportunities to connect the pipeline with the Baumgarten hub in Austria through Bulgaria, Serbia, and Hungary. The EU objects to the pipeline altogether, calling Russia to either continue to sell its natural gas through Ukraine or abide by the rules of the Third Energy Package.  

Third PCI List: TCP Still Eligible for EU Funding, IGB Progress Leads To Alexandroupolis FSRU Reinclusion

On November 24 the European Commission released a list of 173 priority projects aiming at the completion of a truly internal energy market. The key infrastructure projects, usually defined as Projects of Common Interest (PCI)[1] in the EU language, were made publicly available together with the annual Energy Union assessment report, both stressing the importance of a clean energy transition and improved interconnectivity, in order for countries to bear up under future gas cutoffs. As was the case with the previous two lists of 2013 and 2015, the whole Southern Gas Corridor system of mega-pipelines (SCPX, TANAP, TAP), meant to initially bring 10BCM of Shah Deniz gas to Europe, are once again designated as PCIs. After prompting by the Commission’s Vice President for the Energy Union, Maros Sefcovic, towards the international financial institutions to back the strategically crucial for the EU energy security SGC segments, the European Investment Bank now reportedly mulls loans of $1bn and $2bn loans for TANAP and TAP, respectively. The Commission itself has already allocated a modest amount of $16.6M to the Trans Adriatic Pipeline. However, what makes the EU approach regarding the SGC stand out is that the Bloc still considers the long-stuck Trans Caspian Pipeline (TCP) as an integral part of the supply route, has not removed it from this latest PCI list. Europe’s commitment to find a technical and legal basis for the implementation of a subsea line connecting gas from Turkmenistan, and possibly Kazakhstan, with Azerbaijani resources remains firm, despite opposition from Russia and Iran, who insist that the legal status of the Caspian should be settled prior to the start of construction works, and a series of questions related to the pipeline’s commercial viability, that have impeded progress on the TCP to this day. Presently, W-Stream Caspian Pipeline Company Ltd., the TCP promoter, plans to apply for CEF financing between 2017 and 2020. As for the floating storage and regasification unit (FSRU) in Alexandroupolis, northern Greece, projected to serve as an entry point for US LNG into the Balkans and further on to Ukraine, inciting competition amongst traditional low-cost providers, like Gazprom, it has regained its position on the third PCI list. Although included in the 2013 list, the project had been removed from the one of 2015. It is deemed that progress on yet another PCI, the 182km-long Interconnector Greece-Bulgaria (IGB), whose construction is expected to begin within 2018, as soon as decisions on its exemption from the tariff, ownership and third-party access rules are taken by both countries’ regulatory authorities and the EU, has won the Alexandroupolis FSRU a place into the 2017 list. The two projects are closely interrelated because the utilization of IGB’s full capacity will not only depend on supplies from TAP, but also from the LNG stored and re-gasified in the Northern Greece terminal. Besides, as noted in the Energy Union factsheet for Greece, once supply and distribution become fully unbundled in the soon to be liberalized Greek gas market, end-consumers will benefit from increased gas-to-gas competition stemming from both LNG and TAP gas volumes. Even though the Greek gas grid DESFA sees the Alexandroupolis FSRU as a rival project to the already existing, and currently under upgrade, Revithoussa LNG terminal, the US-supported project is not intended for the sole satisfaction of Greece’s energy demand but for exports towards Greece’s northern neighbors. This is why the rehabilitation, modernization, and expansion of the Bulgarian transmission system, now almost fully supplied with Russian piped gas, is equally numbered among the published PCIs. It should be reminded that the front-end engineering and design (FEED) study for the subsea aspects of the unit, awarded to the UK contractor Wood Group, will be partially EU funded. At the moment, the Greek Public Gas Corporation (DEPA) is carrying out due diligence in respect of the project, as well as a fair value evaluation process in order to acquire a 20% shareholding in Gastrade, the company licensed to develop the FSRU. Along with the Monaco-based LNG shipowner Gaslog, DEPA will make the third participant to the project, whose FID is expected by early 2018. Finally, the 150km-long reverse-flow pipeline from Sofia to Dimitrovgrad, or else the Interconnector Bulgaria-Serbia (IBS), is also listed among the European PCIs, proving the EU’s interest in the acceleration of the gasification procedure in the Balkans. Progress on IBS has been slow due to a lack of financing for the Serbian portion, in spite of EBRD loans, however, both countries have vowed to render the pipeline operational by 2020. The onshore/offshore East-Med pipeline, planned to transfer Israeli, Cypriot, Egyptian and possibly Lebanese gas to Europe via Greece, is as well on the list, although today’s price environment might not favor the implementation of such a large-scale project. Following the third PCI list publication EU has sought to grant enhanced regulatory treatment under the Trans-European Energy Networks (TEN-E) Regulation and right to CEF financing to projects promoting its core strategy regarding the security of supply with the help of diversified energy sources, mostly provided by the Caspian Sea and the US shale reserves. Southern Gas Corridor inclusion and Northern Greece LNG terminal reentry into the list clearly signify the Bloc will do its utmost to build an interconnected regional gas market in Central, Southeastern Europe and the Eastern Mediterranean that will serve as an example and a stimulus to move the common energy policy forward.  

Russia, Azerbaijan: SOCAR, Gazprom Agree to Up Gas Deliveries to Baku

Gazprom Export and SOCAR have reached an agreement to augment natural gas supplies to Azerbaijan up to 1.6BCM, starting from November 22. The new sales and purchase contract, signed last week in Moscow, can be interpreted as a strategic move of Baku in order not to be left in the cold ahead of the winter season. Undeniably, Azerbaijan poses as a game-changer in the European ‘’energy map’’ via the Southern Gas Corridor network and thanks to its ‘’2.6TCM of confirmed gas reserves’’, as put by President Aliyev at Friday’s (November 24) Eastern Partnership summit. However, domestic natural gas shortfall represents a perpetually ill-resolved problem for the country’s economy, often leading towards political and social upheaval as a result of the price hikes. Apart from the ongoing development of Shah Deniz, whose second stage has been presold for westward export due by 2020, SOCAR first Vice President Khoshbakht Yusifzadeh has already elaborated on the state-run company’s target to raise gas output in the years to come through the development of several new gas fields, including Absheron, Umid, Babek and Bulla Deniz. But until the so-called ‘’next wave’’ of gas from other offshore Azerbaijani fields is secured, SOCAR has throughout 2016 been holding talks with Gazprom representatives on future cooperation, a process topped by the Russian firm’s latest decision to open a representative office in Azerbaijan. In 2015, within the previously established 5-year contract by Gazprom Schweiz AG, a subsidiary of Gazprom Export, and Azerbaijan Methanol Company (AzMeCo), around 107.4MCM of gas had been delivered to Baku. Russia had, in its turn, also entered into a mid-term contract with SOCAR in late 2009 for the supply of Dagestan via the Shirvanovka custody transfer point on the Azeri-Russian border. From 2010 to 2015 Gazprom purchased 5.4BCM of Azeri gas, but deliveries were often interrupted in 2013 and 2014 due to repair and maintenance works, while in 2015 they were totally suspended. The significance of this fresh SOCAR-Gazprom gas deal is further highlighted by the fact that not even supplies from neighboring Turkmenistan, transported via Iranian territory despite the pricing conflict between Tehran and Ashgabat, can fill the gap for Azerbaijan in due course. That is because Baku only buys minor gas volumes from Turkmenistan during summertime, taking advantage of the low prices, in order to fully utilize the commercial potential of SOCAR storage facilities, and resells them in the winter to profit from the higher seasonal prices. Nevertheless, current state of affairs is subject to change in the aftermath of a strategic partnership agreement, inked in August by Presidents Aliyev and Berdymukhamedov, that paves the way for more direct bilateral energy collaboration, even though the stumbling rock of the disputed Kyapaz/Serdar hydrocarbon deposit continues to divide the two Caspian littoral states.  

Azerbaijan: ACG Work Program and Budget to Be Determined in December

Steering Committee in charge of managing the Azeri-Chirag-Gunashli (ACG) oilfield cluster, located in the Azerbaijani sector of the Caspian Sea, is going to convene in December with the aim of deciding on an annual work program and budget for 2018, BP-Azerbaijan Vice President for communications, external affairs, strategy and region Bakhtiyar Aslanbayli announced November 24. As for the new production platform, to be constructed in the contract area under the recently amended and extended ACG agreement, Mr. Aslanbayli noted that consultations on the issue are still underway. He specified that BP is at the moment carrying out engineering development work without third-party involvement. According to the terms of the most referred to as the ‘’Contract of the New Century’’, restated by SOCAR and Western energy partners in September and ratified by the Azerbaijani parliament in October, an additional platform, going by the name of Azeri Central East, will be built on ACG block. Oil production from this platform, investment decision on which is expected by 2019, may begin in 2023, SOCAR has said. ACG operations currently consist of 8 offshore platforms, 6 production platforms and 2 process facilities (gas compression and water injection). Hydrocarbons are afterward exported from the platforms to the Sangachal Terminal, 55km south of Baku. BP-Azerbaijan last week reported a stable average output of 585,000bbl/d from ACG between January and September 2017. During those same months, BP is said to have spent more than $339M in operating expenditure and about $890M in capital expenditure on ACG activities. Following an 820,000bbl/d peak back in 2010, ACG production has since then shown a downwards trend, never achieving to reach its plateau of 1Mbbl/d. However, an extension of the initial 1994 ACG production sharing agreement (PSA), 7 years prior to the planned 2024 expiration date and despite falling oil prices, proves the companies’ confidence that there are still appreciable volumes of Azeri Light to be obtained and extra capital investments to be made. Shares of participants in the new PSA are: BP (30.37%), SOCAR (25%), Chevron (9.57%), INPEX (9.31%), Statoil (7.27%), ExxonMobil (6.79%), TPAO (5.73%), ITOCHU (3.65%), ONGC Videsh Limited (OVL) (2.31%).  

Turkmenistan: The US Westport Trading Europe Limited and WTL (FZE) to build delayed coking unit at TCOR

New York-based Westport Trading Europe Limited and WTL (FZE) group from the United Arab Emirates have won an international tender to build a delayed coking unit at the Turkmenbashi Complex of Oil Refineries (TCOR). The conclusion of the $140M deal was first announced by Turkmenistan’s Deputy Prime Minister for energy Maksat Babayev during the government session of November 17, however, no company names were disclosed at the time. The new installation is to help deepen oil refining at TCOR by 94% and will be on an annual basis producing some 416,000T of diesel fuel, 191,000T of petroleum coke, 16,400T of liquefied gas and 148,000T of gasoline. This development constitutes proof of Ashgabat’s determination to stick to the Program on Social and Economic Development of the Country in 2018-2024, outlined by President Berdymukhamedov, which calls for the technical upgrade of national energy facilities by means of modern infrastructure projects and effective application of science for the production of oil and gas products. Westport Trading Europe Limited is no stranger to the Turkmen energy industry, demonstrating noteworthy US investment interest in the region. Together with WTL (FZE) the technology corporation had reconstructed a catalytic reforming unit at Seydi Oil Refinery in 2016, as well as a Euro 5 gasoline component installation in early 2017.  

Strategy 2025: Kazakhstan’s Strategic Development Plan

Kazakhstan published its strategic development plan for 2025. Basic parameters of the plan included growing the national income of the country up to $46K and decreasing the regional disparities from 3.2 times to 2.7. The country also aims to be part of the top 30 developed nations in the world. The plan is intended to provide guidelines and plans to move the country towards these milestones and goals. The president of the country, Nursultan Nazarbayev has coined the strategy as the third modernization of Kazakhstan. Expectedly, like many other oil-producing countries in Central Asia and beyond, Kazakhstan also wants to diversify its economy away from its most dominant sector: raw materials. Following the sharp decline in oil prices, starting mid-2014, several oil-producing countries experienced economic crises and Kazakhstan could not escape it, being too dependent on its national oil sector. Currently, natural resources account for more than 55 percent of the economy and Kazakhstan aims to decrease it down to 50 percent. Accordingly, the state also wants to include an increase in small and medium enterprise’s share of GDP, from 27 percent to 35 percent. PCI status does not imply immediate financial support, but allows for the selected projects, except for the oil-related ones, to apply for funding under the Connecting Europe Facility (CEF) framework at a subsequent stage.