Indranil Mittra takes over as Director Finance of Numaligarh Refinery Limited
Indranil Mittra has joined as Director (Finance) of Numaligarh Refinery Limited (NRL). Prior to his joining, he was holding the position of Chief General Manager ( Finance) of NRL. Mittra – a qualified CA & ICWA and a PG Diploma Holder from S P Jain Institute of Management & Research, Mumbai is a hard core finance man with experience spanning around 30 years in the oil industry in diverse areas of Finance such as Corporate Finance, Indirect Tax, Business Finance, including exposure in upstream, etc. According to the company Mittra has garnered experience in handling Commercial and ERP (Enterprise Resource Planning) roles. Mittra started his professional journey in Price Waterhouse, where he spent a little more than a year before joining Bharat Petroleum Corporation Limited (BPCL) Corporate Finance in December 1989. Thereafter, he has been associated with BPCL and its subsidiaries and has held various key positions. He was also involved in implementation of SAP in Bharat Oman Refineries Limited (BORL).
Adapt to changing times, IEA urges major oil, gas exporters
Your time is running out, the International Energy Agency (IEA) has effectively told major oil and gas exporters, noting that they need to address rising production from new sources such as shale and uncertainties over the growth in the demand for crude, a new report said on Thursday. “Outlook for Producer Economies”, in IEA’s World Energy Outlook series, examines six resource-dependent economies that are pillars of the global energy supply: Iraq, Nigeria, Russia, Saudi Arabia, the United Arab Emirates and Venezuela. It assessed how they might fare to 2040 under a variety of price and policy scenarios. The roller-coaster in oil prices over the last decade has brought into sharp focus the structural weaknesses in many of the major exporters. Since 2014, the net income available from oil and gas has fallen by between 40 per cent (in the case of Iraq) and 70 per cent (in the case of Venezuela), with wide-ranging consequences for economic performance. The volatility of hydrocarbon revenues presents dilemmas for countries whose budgets depend on them, especially if their economies and finances are not resilient. The extent to which producer countries steer through essential economic transformation can have major implications for energy markets, global environmental goals and energy security, according to the report. The report comes at a time of high oil prices, which are a double-edged sword. Higher revenues provide the means to reform, but they can also appear to reduce their urgency. However, as was seen in the past, higher energy prices encourage production elsewhere while accelerating structural changes in demand, which affect the producers’ long-term markets. “More than at any other point in recent history, fundamental changes to the development model of resource-rich countries look unavoidable,” IEA’s Executive Director Fatih Birol said. “Following through with the announced reform initiatives is essential, as failure to take adequate action would compound future risks for producer economies as well as for global markets.” The countries examined are very diverse, and the report considers a wide range of experiences and prospects. Many of them have pushed forward plans to boost investment and growth in the non-oil sectors of their economics. Venezuela, though, provides an example of how badly things can turn out when economic and energy headwinds gather strength. Some of the world’s largest producers face strong pressures from rising numbers of young people entering the workforce. More than 50 per cent of the population living across the Middle East is under the age of 30; the proportion is more than 70 per cent in Nigeria. In many major producers, income from oil and gas will not be large enough to provide for these growing populations, even in scenarios where oil demand continues to grow to 2040 and prices remain relatively robust. The energy sector has an important part to play in the reform agenda. The report focuses on six key responses: capturing more domestic value from hydrocarbons, for example via petrochemicals; using natural gas as a means to support diversified growth; harnessing the large but under-utilised potential for renewable energy, especially solar; phasing out subsidies that encourage wasteful consumption; ensuring sufficient investment in the upstream (the ability to maintain oil and gas revenues at reasonable levels is vital for economic stability); and playing a role in deploying new energy technologies, such as carbon capture, utilisation and storage.
Qatar to boost LNG production capacity to 110 million mt/year by 2024-minister
Qatar, the world’s largest LNG producer, is on track to expand its LNG production capacity by around 43% to 110 million mt/year, Mohammad Bin Saleh Al-Sada, Minister of Energy and Industry, said at the LNG Producer-Consumer Conference in Nagoya. This is the latest update to Qatar’s LNG expansion plans and its largest production forecast till date compared to its current production capacity of 77 million tons/year. It had initially stated plans to reach 100 million mt/year by 2020, following the lifting of a 12-year moratorium on the development of its offshore North Field in 2017. The rapid pace of Qatar’s expansion will allow it to maintain its position as the world’s top LNG exporter despite competition from Australia that expects to have 88 million mt/year of nameplate LNG export capacity if all its 10 projects reach full capacity. Qatar’s plans to increase its LNG production to 110 million mt/year will help meet the forecasted shortage in global LNG supply starting from, or even earlier than, the mid-2020s due to emerging market demand growth, Al-Sada said. “This production is planned to commence by 2024,” he added. The International Energy Agency said in its Gas 2018 report that global LNG export capacity is ramping up by the end of 2020, but this oversupply could be short-lived due to the pace of LNG demand growth in Asian markets. “Without new investment, the continuous growth of the LNG trade could result in a tight market by 2023. Owing to the long lead time of such projects, investment decisions need to be taken in the next few years to ensure adequate supply through the 2020s,” according to the Paris-based energy think tank. Al-Sada said Asian economies will be the main contributor to LNG demand growth, and traditional LNG consuming markets like Japan, Korea and Taiwan will be supplemented by new LNG demand from China and India. “In 2017, China and India have increased their LNG imports by a combined 14 million tons per annum to reach 38 and 22 million tons/year respectively,” Al-Sada said, adding that China is expected to raise the share of natural gas in its energy mix to 15% by 2030. Demand growth for LNG in India and China is underpinned by environmental considerations and internal market reforms, and by 2040, LNG volumes are expected to exceed natural gas delivered by pipeline to make up the bulk of gas trades for the first time, Al-Sada said. He said, with regard to market fundamentals, the challenge for the LNG industry is to find a balance between buyers’ need for competitive prices and supply flexibility, and a healthy cash flow for producers.
India’s crude oil production declines 4.19%, pushes import dependence to 83.7% in Sept
India’s domestic crude oil production fell 4.19 per cent to 2,797.84 thousand metric tonne (TMT) in September as compared to the corresponding month a year ago, according to the recent oil ministry data. The decrease in domestic crude oil production pushed India’s crude oil import dependence to 83.7 per cent in the month of September, as compared to 83.3 per cent recorded in the corresponding month a year ago. India’s cumulative crude oil production in the first six months (April-September) of the current financial year fell by 3.42 per cent to 17,409.44 TMT as compared to 18,025 TMT produced in the year-ago period. ONGC Country’s largest oil and natural gas producer, Oil and Natural Gas Corporation’s (ONGC’s) crude oil production fell by 7.21 per cent to 1,711.27 TMT in the month of September, as compared to 1,844.25 TMT produced in the corresponding month a year ago. ONGC’s share in the country’s total crude oil production fell to 61.16 per cent in the month of September, as compared to a share of 63.15 per cent in the corresponding month a year ago. The government-owned upstream player’s cumulative crude oil production in the first six months (April-September) of the present financial year 2018-2019 fell by 5.54 per cent to 10,676.15, on the back of declining production of the company’s western offshore fields. The decline in crude oil production is attributed to problems in the electric submersible pump in the wells of N B Prasad-D1 field situated in the western offshore basin along with less than planned production from WO-16 and B-127 offshore fields, due to the absence of Mobile Offshore Production Units Sagar Samrat and Sagar Laxmi and sub-sea leakage in some well fluid lines of Mumbai High and Neelam Heera Asset, oil ministry said. ONGC’s total share in the country’s crude oil production fell to 61.32 per cent in the first six months of the present financial year, from a share of 62.70 per cent recorded in the corresponding period a year ago. Oil India Oil India, country’s second-largest government-owned oil and gas producer’s crude oil production in the month of September fell marginally by 0.91 per cent to 274.28 TMT, as compared to 276.79 TMT produced in the corresponding month a year ago. Oil India’s share in the country’s total crude oil production increased marginally to 9.80 per cent in the month of September, as compared to a share of 9.47 per cent in the corresponding month a year ago. The company’s total crude oil production in the first six months of the present financial year fell marginally by 0.49 per cent to 1,685.69 TMT, due to less than planned contribution from work over wells and drilling wells. Also, Oil India’s share in the country’s total crude oil production in the first six months of the present financial year increased marginally to 9.68 per cent, as compared to share of 9.39 per cent recorded in the corresponding period a year ago. PSC fields Crude oil production from fields operated by private players and joint ventures increased 1.65 per cent to 812.30 TMT in September, as compared to 799.09 TMT produced in the same period last year. Share of Production Sharing Contract (PSC) fields in the country’s total crude oil production increased to 29.03 per cent in September, as compared to a share of 27.36 per cent recorded in the corresponding month a year ago. Cumulative crude oil production from PSC fields in the first six months of the present financial year increased marginally to 5,047.61 TMT, as compared to 5,029.13 produced last year in the same period. Share of PSC fields in the country’s total crude oil production increased to 28.99 per cent in the first six months of the present financial year, as compared to a share of 27.90 per cent in the year-ago period.
BP expects to start exploration in Libya with Eni in Q1
BP expects to begin exploration with Italian oil major Eni in Libya in the first quarter of next year, CEO Bob Dudley told Reuters on Thursday. “I’m not sure about this year since it takes time to set up offshore rigs but Q1 for sure,” Dudley said on the sidelines of the Eurasian Economic Forum in Verona. Eni agreed in October to buy half of BP’s 85 per cent stake in a Libyan oil and gas licence and become the operator of the exploration and production sharing agreement in the country. Dudley said the agreement with Eni did not mean BP was thinking of pulling out of Libya. “We remain committed and have plans to expand,” he said. BP does not produce any oil or gas in Libya. It signed the EPSA agreement in 2007 to explore onshore in the Ghadames basin and offshore in the Sirte basin. Its exploration programme was interrupted in 2011 when civil war broke out and remains under force majeure. Dudley said he was very pleased with the deal with Eni, adding the two groups could soon be working on other projects. “We are looking at a couple of other things with Eni around the world,” he said, but declined to say where. Dudley said BP was also looking to grow in Egypt where it is developing the West Nile Delta project. He said the expansion plans for the project were expected to be completed at the end of the year with more expansion further down the road. BP bought a 10 per cent stake in the giant Zohr gas field that Eni discovered in Egypt and had an option to raise that stake. “The option expired… We won’t be raising our stake for capital employment reasons,” he said.
Government to rank oil and gas fields to boost output, promote Competition
The Directorate General of Hydrocarbons (DGH) has begun ranking the country’s oil and gas fields in a bid to induce competition among its managers and help boost domestic output stagnant for years now. The ranking is based on a field’s performance on 10 key parameters such as output, infusion of new technology, energy efficiency, reduction in flaring, safety standards and financial audit, an official said. Each parameter has been assigned a different weight. DGH is the technical arm of the oil ministry. State firms have already joined the DGH’s ranking programme and have begun sharing all data needed for the purpose, the official said, adding that private companies too will likely join the exercise in about a month. “This is just benchmarking. People should know where they stand vis-à-vis others. This would help them improve,” the official said. “This is to bring in a positive competition, not to show anyone in bad light or act against anyone who is a laggard.” The ranking would initially be shared only with producers but once the process stabilizes, it could also be made public. Ranking oilfields is just one of the many measures the government has initiated in recent years to raise local output that has contracted this year. A combination of ageing oilfields, inadequate field management and policy issues has ensured a steady decline in crude output since 2011-12, pushing up India’s dependence on import to 83.2% of its requirement. DGH has also recently undertaken measures to beef up its manpower. It is filling up positions vacant for some time, and reshuffled responsibilities among its people. Some of its executives, who are mostly drawn from ONGC and Oil India, are being sent back to their parent companies while others are being brought on deputation to fill those places. “Work has expanded at DGH as it has auctioned so many blocks. So, we can’t leave positions vacant anymore,” an official said, adding that transfers are just routine. DGH monitors all exploration and production activity in the country, receiving and analysing data from producers, answering their queries and resolving their issues. Its executives study and approve field development plans of companies and sit in the management committee meetings that approves work programmes and annual budgets for every field.
Brazil’s Petrobras fires up new platform in offshore Lula field
State-controlled oil company Petroleo Brasileiro said on Wednesday it had started production on its eighth platform in the offshore Lula field, Brazil’s most productive, as it ramps up output from the Santos basin in the coveted pre-salt oil play. Platform 69 will be able to produce up to 150,000 barrels of oil per day and 6 million cubic meters of gas from the field, which already accounts for 30 percent of production in Brazil, now Latin America’s top producer. The platform features eight production wells and seven injection wells to extract oil and gas from the field, which was discovered in 2006 and where production began four years later. Petrobras operates the field and owns a 65 percent stake. Royal Dutch Shell and Galp have 25 and 10 percent stakes respectively. In the pre-salt offshore area, billions of barrels of oil are trapped beneath a thick layer of salt under the ocean floor. The Santos basin already accounts for over half of production in Brazil. A Shell executive told Reuters last month that Lula should hit peak production in 2020 or 2021, after reaching 1 million barrels of oil and gas per day next year.
Exxon, Rosneft to build LNG plant with ONGC and Japan’s SODECO: Sources
Russia’s Rosneft and US ExxonMobil plan to build a liquefied natural gas (LNG) plant in a consortium with Indian and Japanese partners, spreading the estimated $15 billion cost, two sources familiar with the talks said. The four companies – Rosneft, Exxon, Japan’s SODECO and India’s ONGC Videsh – are partners in the Sakhalin-1 group of fields that will supply the gas, but Exxon and Rosneft had initially planned to build the LNG plant without the other consortium members. As well as spreading the costs among more stakeholders, the broader involvement of the participants may mitigate sanctions risk. Initially, Rosneft and Exxon unveiled their joint plans to build an LNG production site in Russia’s Far East to President Vladimir Putin in 2013. But production of the super-cooled, seaborne gas has so far failed to materialise for many reasons, including international sanctions against Moscow for its role in the Ukraine conflict. LNG production itself is not subject to sanctions, but Russian companies have limited access to financial markets due to the restrictions. Exxon had to leave most of its other new joint projects with Rosneft due to the West’s punitive measures against Moscow. Two sources – one person close to Exxon, and a high-ranking Rosneft executive not authorised to speak publicly – said both firms are committed to carrying out the LNG plant project within the framework of the Sakhalin-1 agreement. Sakhalin-1, a hydrocarbon project, is led by Exxon with a 30 per cent stake. Twenty per cent belongs to Rosneft, with the rest split between SODECO (30 per cent) and ONGC Videsh (20 per cent). “No one is interested in financing such a project alone,” the source close to Exxon said. Asked how the LNG plant deal would be structured, the senior Rosneft executive said: “It will be Sakhalin-1.” The sources did not say how the financing of the LNG plant would be shared between the participants. The source close to Exxon said a decision whether to go ahead with the LNG project was expected in 2019, otherwise the project risked losing its market amid growing competition. Currently, two LNG plants, Novatek’s Yamal LNG and Gazprom’s Sakhalin-2, are producing the frozen gas in Russia, which has set an ambitious target of more than doubling its global LNG market share to 20 percent in the next decade. Sakhalin-1 is pumping close to 300,000 barrels of crude oil per day, a record high, as well as natural gas that it has been unable to sell abroad. Gazprom has the exclusive rights to export pipeline gas from Russia. Sakhalin-1 has to pump most of the gas back into the ground, while a small amount goes to local customers in the sparsely populated region. Decade-long talks with Gazprom and the consortium over gas sales have not yet yielded any results. Rosneft, ONGC and SODECO declined to comment. The Russian Energy Ministry and the government also declined to make any immediate comment. “The Sakhalin-1 consortium continues to explore every opportunity to monetize Sakhalin-1 gas resources,” an ExxonMobil spokeswoman in Moscow said in emailed comments sent in response to Reuters questions. SITE LOCATION Igor Sechin, Rosneft chief executive, said in June that the LNG plant would be built just across the Tatarsky strait in the port of De Kastri in Russia’s Khabarovsk region, where Rosneft already has an export terminal for Sakhalin-1 oil. Sechin said then that the plant’s annual capacity was seen at 6 million tonnes of LNG, with supplies aimed at starting in 2025. Gazprom’s Sakhalin-2 has an annual capacity of 10 million tonnes. The source close to Exxon confirmed the technical plans for the plant and said the project partners are considering the option of laying a gas pipe along the existing oil pipeline from Sakhalin-1 to the LNG plant in De Kastri.
Small Canadian LNG project set to go ahead in early 2019
A small liquefied natural gas project north of Vancouver is poised to move to construction in the first quarter of 2019, adding momentum to Canada’s efforts to become a significant exporter of the supercooled fuel. The C$1.6 billion ($1.2 billion) Woodfibre LNG project, backed by Indonesian billionaire Sukanto Tanoto’s RGE Group, would be Canada’s second LNG project to go ahead, following the approval of the massive LNG Canada project earlier this month. “We’re hoping to move to a notice to proceed to construction in Q1 (of 2019),” Woodfibre LNG President David Keane told Reuters on Tuesday. “It will be sometime in February or March.” Woodfibre LNG is a relatively small project at 2.1 million tonnes per annum (mtpa), but was long touted as the front runner to get Canadian natural gas to Asian markets, where demand for the fuel is booming. It was given the go-ahead in 2016, but then delayed as the company worked through a number of issues. Keane said the project is nearly there – the company is just working with engineering contractor KBR Inc on reducing costs and awaiting a November decision on import tariffs on fabricated steel components, used for LNG liquefaction units. “We’ve been very clear as an industry that there is no capability in Canada to build these large, complex modules,” Keane said. “We feel that the federal government will be fair.” Woodfibre also needs to finalize its benefit agreement with the local Squamish Nation, which Keane said has been initialed, but needs to be formally signed by council. He hopes that will be done by year end. Once a construction decision is made, the project will be completed in roughly five years, ensuring first shipments of the supercooled fuel by 2024. LNG Canada, which will produce some 14 mtpa further north in the town of Kitimat, British Columbia, has said it expects to be shipping fuel before 2025. Woodfibre has sold 100 percent of its first phase output and financing for the build is in place, said Keane. The project has also secured its gas supply and is working with utility FortisBC on a 47 kilometre (29 mile) pipeline connection.
India relaxes curbs on petcoke imports
India relaxed some restrictions on imports of petcoke for use as feedstock in some industries, the Directorate General of Foreign Trade (DGFT) said on Twitter on Wednesday. India allowed imports of 500,000 tons of petcoke per year by aluminium companies and 1.4 million tons of petcoke by calcined petcoke makers, a trade ministry notification posted by the DGFT on Twitter showed. Usage of petcoke, a dirtier alternative to coal, in India has come under scrutiny due to rising pollution levels in major cities. India’s imports of petcoke have declined this year as cement companies substituted some of their petcoke with coal to avoid production delays due to pollution-related policy changes. As the world’s largest consumer of petcoke, India imports over half its annual petcoke consumption of about 27 million tons, mainly from the US. Local producers include Indian Oil Corp, Reliance Industries and Bharat Petroleum Corp. India is the world’s biggest consumer of petroleum coke, which is a dark solid carbon material that emits 11% more greenhouse gases than coal, according to the Carnegie–Tsinghua Center for Global Policy.