Residents, environmentalists to fight Croatia’s LNG terminal
Residents and municipal authorities on the Croatian island of Krk, a major tourist destination, have vowed to fight the construction of a floating liquefied natural gas (LNG) terminal due to begin in a few weeks. The government decided in January to co-finance the terminal at the town of Omisalj with 100 million euros ($112.95 million). The European Union is also providing 101.4 million euros for a project that aims to reduce Croatia’s dependence on Russian gas imports. Omisalj mayor Mirela Ahmetovic said the floating terminal violated urban planning rules, which come under the control of the municipal authorities. The government had also not conducted a proper environmental study, she said. The town has asked the Constitutional Court to assess whether a law the government recently approved to accelerate the project is unconstitutional, she added. Environmentalists in Omisalj managed to halt plans to build a port at the town for Russia’s oil exports 15 years ago. Croatian Energy and Environment Minister Tomislav Coric insists the project will not harm the environment. The terminal is due to start operating on Jan. 1, 2021, despite weak initial demand. So far it has received binding bids for just 0.52 billion cubic metres (bcm) of gas per year. Its overall capacity is planned at 2.5 bcm. The terminal targets southeastern and central European markets, besides Croatia which consumes 2.7 bcm of gas annually. An environmental group from Krk said the negative environmental effects of the floating terminal were clear. “Some 8,000 cubic metres of underwater rock must be removed with dynamite. Also, we have no guarantee that chlorine would not be involved in the regasification process. Both are potentially harmful to sea life and to water quality,” said Vjeran Pirsic from Eko Kvarner. Croatia’s gas production is falling and some 60 percent of its consumption is covered by imports from Russia, leading to calls for it to find new sources of energy supply. “Over time, liquefied natural gas supply prices are likely to get close to the cost of gas from a pipeline, especially if LNG from North Africa becomes available,” said Miro Skalicki, an energy expert.
Bangladesh extends deadline to submit plans to build new LNG terminal
Bangladesh will extend the deadline by three months for companies to submit expressions of interest (EOI) to build the country’s first onshore liquefied natural gas (LNG) terminal, two sources familiar with the matter said on Thursday. Rupantarita Prakritik Gas Co, the part of state-owned energy company Petrobangla that oversees LNG supplies, on Jan. 3 requested interest from potential terminal developers for a land-based LNG regasification terminal at Matarbari in the Cox’s Bazar district of southern Bangladesh. The initial EOIs were supposed to be due by March 20 but the companies hoping to take part asked for more time. “The deadline for submission will be extended by three months as potential developers sought more time,” one of the sources said. The EOI is for the design, engineering, procurement, construction and commissioning of a land-based terminal that can handle 7.5 million tonnes per year of LNG, including receiving, unloading, storage and re-gasification facilities. The project is expected to be built on a build-own-operate basis for 20 years, with ownership then transferred to the Bangladeshi government or a company nominated by the government at no cost. “We are getting huge response from companies,” the second source said, adding that companies from Japan, South Korea and India have indicated their interest. The onshore terminal, which can be expanded to 15 million tonnes per year in the future, is part of Bangladesh’s strategy to develop its gas sector with private companies, according to the document. The project developer will be required to arrange the necessary financing. Bangladesh began importing LNG from Qatar on a regular basis in last year through the country’s first floating storage and regasification unit (FSRU). It has scrapped plans to build additional floating LNG import terminals after its second FSRU comes online.
PNG cooking gas, CNG may get costlier from next month; govt set to raise prices
Domestic cooking gas bill and auto CNG prices may be in for a hike, as the government will likely raise the natural gas price by as much as up to 18% next month, said a report. The government is all set to revise domestic gas prices with effect from 1 April 2019, per the New Domestic Gas policy, 2014, which suggests revising natural gas prices every six months. The expected up to 18 per cent hike in the domestic natural gas prices might have an impact on manufacturing, travel, energy and inflation, said a report by CARE Ratings. “We believe the prices of domestic natural gas for the April 2019-September 2019 period will increase from the current $3.36/mmBtu to approximately, $3.97/mmBtu, resulting in an 18% increase,” said CARE Ratings in the report. The government is also set to revise the prices of natural gas produced in deep water and high pressure high temperature. The move will likely adversely affect consumers by leading to an increase the prices of CNG (compressed natural gas) used as auto fuel, and PNG (piped natural gas) used in households as cooking gas. It may also lead to increase in cost of manufacturing of urea and petrochemical, where natural gas is used as a feedstock; and may also hit producers of power sector and sponge iron industry, where it is used for the generation of energy, the report added. An increase in prices of domestic natural gas will also lead to a rise in wholesale price index (WPI) inflation, which gives 0.46 per cent weightage to the natural gas of the total 2.46 per cent weightage given to crude petroleum and natural gas. However, it will increase revenues for upstream gas exploration companies such as ONGC, OIL India, Vedanta and Reliance, said the report. New Domestic Gas price formula takes into account the prices of natural gas in USA (Henry Hub), UK (New Balancing Point), Canada (Alberta Gas) and Russia (Russian Natural Gas), where prices are market linked in each hub.
ONGC’s biggest oil fields including Mumbai High came close to being sold to private, foreign firms
State-owned ONGC’s nine biggest oil and gas fields including Mumbai High and Vasai East came tantalizing close to being sold to private and foreign companies but the plan was nixed after strong opposition from within the government, sources said. A high-level committee headed by Niti Aayog Vice Chairman Rajiv Kumar late last year considered “transferring” western offshore oil and gas fields of Mumbai High, Heera, D-1, Vasai East and Panna as well as Greater Jorajan and Geleki field in Assam, Baghewala in Rajasthan and Kalol oilfield in Gujarat to private/foreign companies. Multiple sources in Niti Aayog and government said, the plan to give away fields producing 95 per cent of India’s current oil and gas could not go through because of very strong opposition from Oil and Natural Gas Corp (ONGC) as well as some quarters within the government who found something amiss in the proposal. Besides the 9 fields, 149 marginal fields, that contribute about 5 per cent of the domestic production, were to be clustered and bid out. While ONGC opposed giving away on a platter to private/foreign sector what it discovered after years of toil and spending billions of dollars over last four decades, some in government were not convinced by the incremental potential toyed to get the proposal through, they said adding it wasn’t clear how the incremental output numbers were arrived at in absence of any real basin or field study by the panel. The proposal brought before the panel, which was appointed by Prime Minister Narendra Modi in October last year to boost stagnant output from aging fields of public sector oil companies, was to give private/foreign companies complete marketing and pricing freedom after getting from them an enhanced production profile for the fields. National oil companies (NOCs) were to get 10 per cent of incremental output over business as usual (BAU) scenario, sources said. Private and foreign companies have generally shied away from taking up exploration blocks and have instead been lobbying for getting a stake in producing oil and gas fields of ONGC and Oil India Ltd (OIL) saying they can raise output by bringing in capital and technology. NOCs, on the other hand, contend that they do not have pricing and marketing freedom and they too can get the technology provided the same is provided. The final report that the committee submitted on January 29, had watered down the proposal by recommending freedom to NOCs to choose field specific implementation model including farm out, joint venture or technical service model for raising output from the fields that contribute 95 per cent of the current output. Pricing and marketing freedom for any new field development plan that they bring was also recommended. Sources said, 64 small and marginal fields of ONGC and two of Oil India Ltd (OIL) were recommended to be bid out within four months and NOCs allowed to retain 54 others (49 by ONGC and 3 by OIL) where enhanced oil recovery/improved oil recovery schemes were under implementation. The recommendations have been accepted by the government. The overhauled policy notified by the government provides for complete marketing and pricing freedom for oil and gas produced from areas bid out in future bid rounds. Oil and gas acreage or blocks in all future bid rounds will be awarded primarily on the basis of exploration work commitment, it said adding companies will not have to share any profit with the government on oil and gas produced from less explored areas.
India’s petroleum products exports to hit 8-year low in 2019
India’s total exports of petroleum products, which account for over a tenth of the gross value of outbound shipments, are set to drop below the 1.2 million barrel per day (mbpd) mark in the current calendar year, the lowest level of annual exports in the past 8 years. The worrisome trend for export earnings is attributed to a robust rise in domestic demand coupled with a mega maintenance-led refinery shutdown slated for 2019. The country exported petroleum products – mainly petrol, diesel, naphtha, fuel oil and lubricants — worth $35 billion last financial year (2017-18). “Overall, heavier maintenance program is to be expected this year, which will affect refinery throughput. This, coupled with robust domestic demand (expected to grow at 235 mbpd for the year as a whole), would likely pull India’s total oil product exports below the 1.2 mbpd mark this year for the first time since 2010,” Jy Lim, Director of Asia-Pacific oil market analysis at S&P Global Platts told ETEnergyworld. He added domestic refinery upgradation will be required as India plans to shift to Bharat-VI standard fuel in April 2020 coupled with the upgradation required to meet the International IMO 2020 bunker fuel specifications. Refiners with planned maintenance in 2019 include Reliance Industries, Bharat Petroleum (BPCL), Hindustan Petroleum (HPCL) and Indian Oil Corp (IOC), according to S&P Global Platts. IOC, the largest refiner, will complete its refinery upgradation activity by the second half of next fiscal (2019-20), B V Rama Gopal, the firm’s Director-Refineries told ETEnergyworld in an interview in February last month. According to Platts, India’s domestic petroleum product consumption reached 210 Million Tonne (MT) in 2018 and is expected to rise 4.8 per cent in 2019 on the back of increased demand for petrol, diesel and Liquefied Petroleum Gas (LPG). The impact of the twin factors – robust demand and refinery upgradation activities – is already visible in the export numbers of the current financial year. “India’s total oil product exports dropped by 355 mbpd (or 24 per cent) year-on-year to 1.1 mbpd in January 2019, marking it the sharpest year-on-year decline in 9 months and the lowest monthly level since April 2018,” Lim said. Data on exports sourced from Petroleum planning and Analysis Cell (PPAC), an arm of the oil ministry, shows the country’s petroleum products exports in January 2019 slumped 25 per cent to 4.5 Million Tonne (MT) as compared to 6 MT exported in the corresponding month a year ago. Overall, in the April-January period of 2018-19, the country’s petroleum products exports have suffered a drop of 8.70 per cent at 51.4 MT, as compared to 56.3 MT exported in the same last fiscal. PPAC attributes the hit suffered by petroleum product exports to a drop in out-bound shipments of petrol, naphtha, diesel, LOBS/lube Oil, Fuel Oil, bitumen and Vacuum Gas Oil due to increased domestic consumption of petrol, naphtha and diesel recorded this fiscal year. However, in value terms, petroleum exports increased 14 per cent to $32.6 billion during the April-January period of current fiscal as against $28.7 billion worth of exports recorded in the corresponding period of 2017-18. Largest export destinations for India’s petroleum products include Singapore, United Arab Emirates, Netherland, Malaysia, United States, Israel and Nepal, according to data sourced from the Directorate General of Commercial Intelligence and Statistics (DGCIS), an arm of the commerce ministry. India exported 8.96 MT of petroleum products to Singapore in the first ten months (April-January) of 2018-2019, as compared to 10.55 MT exported in the corresponding period last fiscal. During the same period, petroleum Products exports to UAE increased to 8.18 MT from 6.72 MT while exports to Netherland rose to 5.68 MT from 3.03 MT.
Indian Oil to receive second LNG cargo for new LNG terminal in May
Indian Oil Corp is set to receive a second liquefied natural gas (LNG) cargo for its new Ennore terminal in south India in May, two industry sources said. The 5 million tonnes per annum (mtpa) import facility at Kamarajar port on the outskirts of Chennai discharged its commissioning cargo more than a week ago, the sources said, with the next due in two months. It was not immediately clear if the company will issue a tender for the cargo. State-owned IOC bought a partial LNG cargo for delivery in late February from Swiss trader Gunvor. The commissioning cargo was delivered through the LNG tanker ‘Golar Snow’ from Qatargas. IOC could not immediately be reached for comment outside business hours. The company said in a statement on March 6 that the terminal had received all necessary clearances to start commissioning. Ennore is owned by IndianOil LNG, a joint venture of IOC, private equity fund IDFC Alternatives and ICICI Bank, according to IndianOil LNG’s website. The 51.5 billion rupees ($741 million) terminal is India’s fifth, and the first to be located on the east coast in south India. Currently, there is limited gas infrastructure in Tamil Nadu. The terminal is expected to spur industrial growth in the area with the re-gasified LNG to be distributed to power generation plants, fertiliser plants and other industrial units.
India’s Gail CEO calls for more flexibility in U.S. LNG contracts
Gail India called on U.S. liquefied natural gas (LNG) producers to offer more flexible contract terms as the state-owned gas distribution gas company hunts for supplies from the middle of the next decade. India last year was the fifth largest importer of U.S. LNG and natural gas is projected to double its share of the nation’s energy mix by 2030 as oil-fired power plants convert. Shri B.C. Tripathi, chairman and managing director of Gail India, said on Wednesday at the CERAWeek energy conference his company is in discussions with U.S. gas exporters to acquire new LNG supplies from 2024-2025. “Traditional suppliers like Qatar or Russia have shown a lot of flexibility in recent past where they have modified their contracts, re-negotiated their contracts, aligned them to the market,” Tripathi said in a brief interview. “However, the U.S. contracts are purely a tolling model. Their tolling fee is fixed,” he said, adding that U.S. LNG becomes less competitive against traditional supplies when oil prices drop. The company has 20-year LNG contracts to buy 5.8 million tonnes per year of U.S. LNG, split between Dominion Energy Inc’s Cove Point plant and Cheniere Energy Inc’s Sabine Pass facility in Louisiana. Gail currently sends up to 75 percent of its U.S. LNG supplies back to India, Tripathi said, and sells the rest into the spot market. All the LNG will eventually be shipped to India when more gas pipelines and regasification terminals are completed, he said. Natural gas is expected to account for 15 percent of India’s energy mix by 2030, up from the current 6.2 percent, MM Kutty, secretary of India’s Ministry of Petroleum and Natural Gas, said earlier in the week. Half of that demand will be met by LNG imports, he said. The world’s fourth largest energy consumer is replacing oil-fired power plants with gas and is building pipelines so that piped gas can reach 70 percent of its population. India also aims to expand the number of compressed natural gas (CNG) refueling stations by 10-fold to 10,000.
First coal, now LNG jolted by climate change measures in Australia
The concept that producers of fossil fuel will have to pay for the carbon emissions created by their use is something the industry will no doubt fight tooth and nail, but two recent developments in Australia show the battle may be starting. Australian liquefied natural gas (LNG) major Woodside Petroleum reacted angrily to recent moves by the environmental regulator in Western Australia state to require that projects offset their emissions. The Environment Protection Authority in the state announced new guidelines earlier this month that would mandate projects with more than 100,000 tonnes a year of emissions to offset them through programmes aimed at mitigating the impact of climate change. The proposed measures would add billions of dollars to the costs of operating the six massive LNG plants in the state, which have a combined annual capacity of about 57.8 million tonnes of the super-chilled fuel – more than the annual demand of the world’s number two consumer China. Woodside Chief Operations Officer Meg O’Neill told a conference in Perth on Wednesday that the proposed rules were “wrong” and would disadvantage Western Australia. The federal Resources Minister Matt Canavan went further, saying the rules were a “brain explosion” that “defied common sense,” according to a report in the Sydney Morning Herald newspaper. Canavan called on Western Australia to scrap the proposals, something the state government has indicated it may do. Even if the measure is scrapped, the mere fact that it was raised in the first place has raised question marks over the future of LNG projects in Western Australia, where Woodside is considering investments of more than $20 billion to build new ventures. COAL MINE REJECTED The focus on carbon emissions from LNG comes on the heels of a similar issue for coal mining in Australia, which is the world’s largest supplier of the polluting fuel to the seaborne market. A proposed coal mine in Australia’s New South Wales was rejected by the state’s Land and Environment Court in February, with the judge citing its potentially “dire” environmental impact as part of his reasoning. The Rocky Hill mine was proposed by privately held Gloucester Resources, but Judge Brian Preston ruled that burning the mine’s coal would add to greenhouse gas emissions “at a time when what is now urgently needed, in order to meet generally agreed climate targets, is a rapid and deep decrease in GHG emissions.” The court ruling was viewed by environmentalists as a landmark judgment that put coal miners on notice that they were going to have to account for the emissions caused by the use of their product, even if it was consumed in another country. However, before popping champagne corks, environmentalists should probably realise that both the decision by the New South Wales court on the coal mine and the proposed offset rules in Western Australia for LNG projects are unlikely to have much practical impact. The coal mine was likely to fail to proceed on a number of grounds, including its proximity to a residential area, and the judgment doesn’t mean that all future projects will suffer the same fate. The Western Australia government is likely to reject the advice of its own environmental regulator and not impose carbon emission offset requirements on the state’s economically important LNG sector. But it is becoming clearer that the next phase in the green battle against fossil fuels is likely to be regulatory, with activists increasingly taking to the courts and putting pressure on governments to take action by imposing rules. It may take several years, but oil and gas companies and miners should be prepared to have to add the cost of carbon emissions into their new, and perhaps even their existing, projects.