India records lowest crude oil production in nine years
India produced 31,349 Thousand Tonne (TMT) of crude oil in the first eleven months (April-February) of the current financial year (2018-2019), the lowest output recorded in the past nine years during the same period, according to fresh data sourced from the oil ministry. The declining trend in the country’s domestic crude oil production is coming at a time when the country’s oil import bill has already ballooned 29 per cent to $102.9 billion during the April-February period of the current fiscal. Also, the decline in domestic crude oil production has pushed India’s oil import dependence to 83.8 per cent, the highest recorded in the April-February period in the last five years for which data is publicly available. The government had earlier said it is working towards a plan to reduce the country’s crude oil import dependence by 10 per cent by 2022. India’s crude oil production in February 2019 declined 6.4 per cent to 2,564 TMT, as compared to 2,731 TMT produced in the corresponding month a year ago, primarily due to fall in production from fields operated by Oil and Natural Gas Corporation (ONGC), private players and fields operated under a Joint Venture, data showed.Cumulatively India’s crude oil production in April-February period declined 4 per cent to 31,349 TMT, as compared to 32,643 TMT recorded in the corresponding period a year ago. India’s oil production has declined over the past nine years mainly due to ageing fields leading to fall in output from nearly all the offshore and onshore blocks, data shows. ONGC ONGC’s crude oil production during February 2019 declined 5 per cent to 1,599 TMT mainly due to decreased production from Western Offshore fields. Cumulatively, the firm’s oil production during the first 11 months of the current fiscal dropped 5.38 per cent to 19,274 TMT. According to the the oil ministry, the reasons for reduced output include problems in Electric Submersible Pump (ESP) in some wells of NBP fields, loss of production from WO-16 fields due to absence of Mobile Offshore Production Unit, sub-sea leakage in some well fluid lines of Mumbai High and Neelam Heera asset. Oil India Oil India’ crude oil production during February 2019 declined 6.45 per cent to 244 TMT mainly due to fall in production from Assam fields. Cumulatively, the company’s oil output during the April-February period declined 3 per cent to 3,015 TMT. The reduced output was due to less than planned contribution from work-over wells and drilling wells and loss of production caused due to strikes and miscreant activities in operational areas. Pvt/ Joint Venture fields Oil production by private operators and JVs dropped 8.30 per cent to 721 TMT in February due to decline in Rajasthan fields as well as offshore fields. Cumulatively, oil production by private and JV operators during the April-February period slumped 1.29 per cent to 9,060 TMT. The decline is attributed to loss of production from Mangala due to delay in upgrade of Mangala Process Terminal (MPT) and delay in drilling, completion and hooking up online 45 wells, along with closure of around 98 oil wells at Cairn Oil and Gas’ assets due to various reasons like liquid handling constraint at MPT plant, pump failure, surface facility limitation.
UK’s National Grid forecasts Summer 2019 gas demand at 36.1 bcm
Britain’s National Grid forecast gas demand during the summer period will total 36.1 billion cubic metres, it said in its annual Summer Outlook on Tuesday. The figure is almost 6 percent higher than summer gas demand in 2018, once weather related adjustments were made, the report said. Electrcity demand is expected to peak at 33.7 gigawatts (GW) while the minimum summer electricity demand is forecast at 17.9 GW.
All state-run oil companies exceed capex target
Indian Oil, Hindustan Petroleum, Bharat Petroleum, and GAIL have exceeded their capital expenditure targets for the current fiscal, having spent heavily on refinery upgrades, pipelines, and marketing infrastructure. The combined capex target set for all staterun oil producers, refiners and marketers for 2018-19 is Rs 89,335 crore, of which they have collectively spent Rs 82,711 crore, or about 93%, in the 11 months through February. Explorer Oil and Natural Gas Corp, which typically has much higher spending budget every year than the refiners, has spent about 80% of its annual target of Rs 32,000 crore. Its overseas arm, ONGC Videsh, has used up about 85% of its Rs 5,890 crore target, while another state-run producer, Oil India, has spent 78% of its target of Rs 4,300 crore. Gas marketer GAIL and refiners Indian Oil, HPCL and BPCL have surpassed their annual target in 11months. BPCL has spent Rs 8,993 crore, or 121% of its target. GAIL, which is investing heavily in laying a gas pipeline in eastern India, had spent Rs 5,059 crore until February, or 107% of its target for the year. HPCL has already used up Rs 8,938 crore, or 106% of its annual outlay. Indian Oil, the nation’s largest refiner and fossil fuel retailer, has invested Rs 23,492 crore, or 103% of its target. Refiners have been upgrading their facilities to produce lower-emission fuels that will help curb intense air pollution in cities. They have also been spending on setting up new pipelines, depots and retail outlets. Indian oil companies have been investing heavily in finding, refining and distributing oil and gas across the country for the last many years to meet mounting demand for fuel and feedstock. Meanwhile, economic expansion has pushed up oil demand by 3.2% during April-Feb of 2018-19. India is also hoping to increase its domestic oil output and reduce its dependence on import by making massive investments in exploration and production. Domestic crude oil output has been declining for years. India imports about 80% of the oil and about half of the natural gas it consumes. The import bill of crude oil is estimated to expand 27% from $88 billion in 2017-18 to $112 billion in 2018-19.
Oil companies have more expertise than GAIL in operating city gas business: Fitch
India’s state-owned oil marketing companies (OMCs) will have more expertise than GAIL in operating the retail-oriented business model required under the city-gas distribution (CGD) rights but GAIL would benefit more from the rising transmission volumes, said research and ratings agency Fitch Ratings. In a report on the recent award of city-gas distribution rights in India to state-owned OMCs, the firm said that the initiative would help them diversify from their oil refining and marketing business and maintain their strong market shares in the domestic cooking and auto fuel markets over the long-term. The government had last month awarded Indian Oil (IOC) and Hindustan Petroleum (HPCL) CGD rights to nine geographical areas (GAs) each and Bharat Petroleum Corp (BPCL) rights to two areas. BPCL had won the rights to 11 GAs in a previous auction in September 2018. The investment by the winners of each GA will depend on its physical size, as well as the number of natural gas stations for automobiles that must be built and length of PNG steel pipeline that must be laid under the terms of the distribution rights. “In any case, we expect the investments in city-gas distribution to remain relatively small over the medium-term relative to the overall investment plans of the state-owned oil marketing companies,” the report said. Other companies which had won the bids in the auction of rights for 50 GAs included state-owned gas processing and distribution company GAIL India, state-owned Maharashtra Natural Gas and Rajasthan State Gas apart from private companies Adani Gas and Torrent Gas. The expansion in gas distribution networks is likely to increase gas consumption over the medium to long term while industrial demand is likely to remain highly sensitive to prices. Natural gas consumption increased by around 3 per cent in April 2018-January 2019 period and 4.5 per cent last financial year (2017-18).
Brazil oil regulator announces details on October deepwater oil auction
Brazil’s oil regulator ANP on Monday announced details of the 16th-round auction of oil areas under the concession regime, stipulating a higher bonus amount for the CM-541 block in the Campos Basin, which surpasses 1 billion reais ($259 million). According to an ANP statement, the round must take place on Oct. 10, with the signing of the agreements in February 2020. There will be public consultation of the rules until April 9 and public hearing the next day in Rio de Janeiro. Registration for the tender ends on Aug. 20. The ANP added that a total of 29,300 square kilometers will be offered in the round, which will have 36 different blocks from the Campos, Jacuipe, Camamu-Almada, Pernambuco-Paraiba and Santos basins.
Saudi Aramco building global gas business to cut carbon footprint
Saudi Aramco, the world’s biggest oil producer, was building an international gas business and converting more crude oil into chemicals in a bid to lessen its carbon footprint, Chief Executive Amin Nasser said on Tuesday. Aramco is building “an energy bridge” between Saudi Arabia and China to meet the Asian energy consumer’s increasing need for oil and gas as well as for chemicals and liquefied natural gas (LNG), according to a copy of Nasser’s speech at an industry event in Beijing. “We need to help our stakeholders – including here in China and the wider Asia region – realise that oil and gas will remain vital to world energy for decades to come,” he said. “We need to reassure them with our own long-term investments that the safety belt we have always provided is one they can continue to rely on.” Aramco’s gas expansion strategy needs $150 billion of investment over the next decade as the company plans to increase output and later become a gas exporter, Nasser had said in November. The state-owned company is pushing ahead with its conventional and unconventional gas exploration and production program to feed its fast-growing industries, freeing up more crude oil to export or turn into chemicals. Nasser said that the carbon footprint of Saudi oil is among the lowest in the world, and has the lowest greenhouse gas intensity of any supplier of crude oil to China. Aramco is a major investor in China’s energy sector. In February, Aramco inked a deal with Chinese defence conglomerate Norinco to develop a $10 billion refining and petrochemical complex and another agreement to buy a stake in Zhejiang Petrochemical. Saudi Arabia was China’s biggest crude oil supplier in February, data from the general administration of Chinese customs showed on Monday, reclaiming the crown from Russia after ranking no. 2 in January.
Regulator drops plan to force LNG terminals to reserve share for common use
The downstream regulator has scrapped its plan to force LNG terminals to reserve a share of their capacity for common use after industry opposed the move arguing the proposal was premature and would hurt local gas demand. In March 2018, the Petroleum and Natural Gas Regulatory Board (PNGRB) had published a draft regulation for LNG terminals in the country, requiring them to register with the board, follow certain safety standards and, most contentiously, offer some common carrier capacity. The draft mandated an LNG terminal to “offer at all times, after registration, 20 per cent of its short term (less than five years contract) uncommitted regasification capacity or 0.5 million metric tonnes per annum (MMTPA), whichever is higher, as common carrier capacity.” Uncommitted capacity means the part which is net of the entity’s own and contractual requirement. “We will bring regulation only to the extent of registration and safety,” PNGRB chairman DK Sarraf told ET, adding the proposal on common carrier capacity has been dropped. “We would like to support LNG terminals by keeping them away from regulatory burdens until they are fully established and their capacity utilisation goes beyond a level where some regulation becomes necessary to protect consumer interest,” he said. Regulator drops plan to force LNG terminals to reserve share for common use The draft provoked strong reaction from industry players, who felt proposed rules could upset the economics of LNG terminals as they may have to make additional investment for the capacity that will have to be reserved for common use. This would mean either longer payback period or higher toll for customers that could hurt demand for gas. “Industry told us that they respected the consumer protection intent of the regulator but it was unnecessary at this point in time,” Sarraf said. “They said so many new terminals were coming up that there will be a lot of capacity in the country, and utilisation will be low for a long time. Therefore, capacity will anyway be available to every customer. But a new regulation will place unnecessary financial burden on LNG terminals, they said.” India has added about 10 million tonnes a year LNG regasification capacity in the past six months to about 37 million tonnes now. This is expected to rise to 50 million tonnes a year by 2022. The capacity explosion and the government’s aim to push up gas usage in India’s primary energy mix to 15 per cent from 6 per cent had triggered temptation to regulate LNG terminals.
UAE’s ADNOC awards onshore exploration block to Indian consortium
Abu Dhabi National Oil Company (ADNO) said on Monday it had signed an agreement with an Indian consortium awarding the latter the exploration rights for an onshore block. Two Indian companies – Bharat Petroleum Corp Ltd and Indian Oil Corp – will together hold a 100 percent stake in the exploration phase for Onshore Block 1, ADNOC said in a statement. The Indian firms will invest up to 626 million dirhams ($170 million), including a participation fee, to explore and appraise oil and gas in the block. If successful, the consortium will be able to develop and produce any discoveries with an option for ADNOC to hold a 60 percent stake in the production phase. The agreements, which have a term of 35 years, conclude Abu Dhabi’s first-ever competitive block bid round, ADNOC said. “The onshore exploration block awarded to the Indian consortium will target, specifically, the conventional oil and gas opportunities in the area,” ADNOC said. The Onshore Block 1 area also covers the separate Ruwais Diyab Unconventional Gas Concession, where France’s Total has the exploration rights for tight gas in the Diyab formation. ADNOC has awarded Offshore Blocks 1 and 2 to Italy’s ENI and Thailand’s PTT Exploration and Production Pcl ; Onshore Block 3 to U.S.-based Occidental Petroleum; and Onshore Block 4 to Japan’s Inpex Corp.
US Emerging as a LNG Powerhouse
Last month month, ExxonMobil and Qatar Petroleum announced that they will proceed with construction of the >$10 billion Golden Pass liquefied natural gas (LNG) export facility on the Texas Gulf Coast. This project would export up to 2.2 billion cubic feet per day (Bcf/d) of LNG, and is just one of more than 50 LNG export projects to be approved by the U.S. Department of Energy (DOE). According to the DOE, since the startup of Cheniere Energy’s Sabine Pass LNG export terminal in February 2016, about 2 trillion cubic feet (Tcf) of domestically-produced LNG have been exported to 34 different countries. Cheniere Energy was the first major LNG exporter, but they were joined last year by Dominion Energy, which opened its Cove Point LNG export terminal. This is just the tip of the iceberg, however, as the LNG export market is projected to surge over the next three decades. You can thank the shale boom for that. The Shale Boom Upended Energy Markets LNG export growth is the latest example of how the U.S. shale boom has disrupted global oil and gas markets. Advances in hydraulic fracturing and horizontal drilling turned an expected natural gas deficit into a huge surplus. Following years of stagnant production, U.S. natural gas grew 50% from 2005 to 2015 to reach 72 Bcf/d. In the process, the U.S. became the world’s largest natural gas producer, with 20 percent of the global production share. This surge of production kept U.S. natural gas prices in check. Natural gas spot prices that had regularly spiked above $10/MMBtu fell below that level in 2008, and since 2010 have only been above $5/MMBtu during brief cold weather events. Natural gas demand has kept pace. Natural gas exports to Mexico have now exceeded 5 Bcf/d, equal to about 7 percent of U.S. daily production. Consumption by the electric power sector increased by nearly 50 percent from 2005 to 2016, reaching 27 Bcf/d. Industrial demand has also increased by 30 percent as some manufacturing relocated to the U.S. to take advantage of low gas prices. The Coming LNG Export Flood But the Energy Information Administration (EIA) is betting that the next big surge of demand is going to come from LNG exports. In its Annual Energy Outlook (AEO) 2019 with projections to 2050, the EIA projects that U.S. LNG exports will quintuple from an average of 2.8 Bcf/d in 2018 to 14 Bcf/d by 2050. The EIA projects a 5.1 percent annual growth rate in LNG exports from 2018 to 2050. If that outlook is correct, in 2050 LNG exports would consume an estimated 12 percent of U.S. natural gas production, which itself is forecast to rise by nearly another 50 percent between now and 2050. The global LNG trade is currently dominated by Qatar and Australia. In recent years, Qatar has been comfortably in first place, exporting about 10 Bcf/d. But the EIA projections would put U.S. exports about 40 percent ahead of Qatar’s current export level. Can Production Keep Pace? To date, most of the U.S. natural gas production growth has been in the Appalachia Region. Appalachia production has exploded from below 2 Bcf/d in 2009 to more than 30 Bcf/d in 2018. The EIA forecasts that the Appalachia will continue to produce 52 percent of cumulative production of U.S. shale gas through 2050. But the associated natural gas (co-produced with oil) in the Permian Basin is also soaring. Natural gas production in the Permian Basin has reached 13 Bcf/d, the same level as the Appalachia Region in 2013. Permian gas production has doubled in just over two years and is now second only to the Appalachia Region. Further, Permian Basin gas production should continue to grow along with the region’s oil. A new assessment by the U.S. Geological Survey (USGS) estimated that there are 281 trillion cubic feet of undiscovered, technically recoverable natural gas in the Permian. That’s enough gas for 58 years of Permian production at 2018 rates, which should help feed the monster LNG demand growth that is forecast in coming decades. Conclusions The implication of this surge in LNG trade will be to make natural gas a more globally traded commodity, which should decrease some of the natural gas price disparity seen around the world. U.S. natural gas prices should increase, while those in Asia and Europe should decline. The beneficiaries will be U.S. natural gas producers and LNG exporters, global natural gas consumers, and the environment — as natural gas displaces coal in many Asian markets.
LNG supply glut, price slump should raise questions over future projects
The slump in the spot price of liquefied natural gas (LNG) in Asia to its lowest in three years should give pause for thought to the slew of companies planning new ventures to produce the super-chilled fuel. But it probably won’t. The spot price for LNG delivered to Northeast Asia dropped to $4.65 per million British thermal units (mmBtu) in the week to March 21, the lowest since May 2016. It’s been an unusual northern winter for LNG, with the price peaking at $10.90 per mmBtu in November and steadily sliding since then. The more normal seasonal pattern is for spot LNG prices to peak around January before slipping in the shoulder season of spring, with the seasonal winter climb starting sometime in the third quarter. The fact that LNG prices have performed poorly over winter is more a reflection of excess supply, rather than weak demand, with Refinitiv vessel-tracking and port data confirming that consumption has been quite robust. LNG deliveries in Northeast Asia, which includes top three importers Japan, China and South Korea, were about 73.3 million tonnes for the four months from November to February. The previous winter, imports for those months totalled 70.3 million tonnes, meaning that LNG demand in the top-consuming region was actually 4.3 percent higher in the winter period of 2018-19 than the same period in 2017-18. The issue for LNG is supply, with the last of the eight major Australian projects built over the past decade coming on stream, and more volume becoming available from the United States. It’s a problem that is likely to get worse rather than better for the rest of 2019, with capacity additions likely to swamp demand growth, at least in Asia. About 70 million tonnes of new LNG capacity will reach the market this year and next, Wood Mackenzie analyst Nicholas Browne told the LNGgc Asia conference in Singapore last month. While estimates of the likely increase in demand vary, none are as high as 70 million tonnes over the next two years, with a figure around half that viewed as more likely. This means that either LNG producers will have to cut back on output, or the price will have to be low enough for the fuel to replace pipeline natural gas in markets such as Europe. ARE NEW PROJECTS STILL VIABLE? The current supply glut and price weakness may also cast a shadow over the next wave of LNG projects, with the frontrunners expected to start taking final investment decisions (FIDs) this year. It’s easy to dismiss the price slump as merely seasonal, and point to expectations of strong demand growth in China and other parts of Asia in coming years. The more optimistic versions of these forecasts see world LNG demand at least doubling in the next decade from the 321 million tonnes shipped in 2018. Much of this demand growth is focused on Asia, with India, Pakistan and various Southeast Asian countries playing the major role alongside China. LNG Canada, a 10 million tonne per annum project led by Royal Dutch Shell, has already taken its FID, becoming the first cab off the rank in the new wave, with first output expected in 2024. There are 14 more U.S. and Canadian ventures slated to take FID this year or next, and they will be joined by projects in Mozambique, Russia, Qatar and possibly Australia. The traditional model of approving multi-billion dollar projects only when offtake agreements for most of the production are finalised is also being upended, with several ventures planning on going ahead on the basis that the spot market for LNG will grow and be deep and liquid enough to absorb all the planned output. This may be somewhat optimistic as this view relies heavily on all the emerging consumers of LNG actually building the import and re-gasification capacity, and the downstream facilities to consume the natural gas. It is worth noting that the outlook for Japan, the world’s top buyer, is for demand to drift lower in coming years. It’s also expected that China’s rapid growth of recent years will start to temper, especially given the likely completion of a natural gas pipeline from Russia in the next couple of years. South Korea, which ranks behind Japan and China, is also uncertain for LNG demand in the future, given the country is now emphasising renewable energy for its future needs. The risk for LNG producers is that if all, or even a majority, of the planned projects take FID this year or next, is that a tsunami of supply will arrive at more or less the same time, and it will be enough to swamp even the most optimistic demand growth scenarios.