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.
Gunvor, DXT lowest bidders in Pakistan LNG tender
Trading houses Gunvor and DXT Commodities made the lowest bids to supply liquefied natural gas to Pakistan between May and June of this year in a six-cargo tender, according to Pakistan LNG tender documents on Wednesday. The documents showed DXT had the lowest bids for a cargo for May 1-2 delivery at 9.2783 percent of Brent crude oil prices, for May 27-28 delivery at 9.6816 percent and for June 29-30 delivery at 9.9201 percent. Gunvor had the lowest bids for a May 11-12 cargo at 9.5739 percent, May 16-17 at 9.7270 percent and June 14-15 at 9.9387 percent. The prices, expressed in the document as crude oil slope or the numerical percentage of Brent crude price, are a valuable pointer for the opaque LNG market. A cargo priced at 9.3 percent of Brent is about $6.23 per million British thermal units (mmBtu). Spot Asian prices for April were heard last week at $5.70 and below $6 for May.
Oil regulator hikes tariff of pipeline transporting Reliance gas by 37%
Oil regulator PNGRB has approved a 37 per cent rise in tariff from April 1 for the pipeline that transports Reliance Industries’ eastern offshore KG-D6 gas to customers. In its final tariff order, the Petroleum and Natural Gas Regulatory Board (PNGRB) in a March 12 order said transporting natural gas on the East-West pipeline would cost Rs 71.66 per million British thermal unit (mmBtu) on gross calorific value (GCV) basis from April 1 as compared to Rs 52.33 per mmBtu tariff charged for April 1, 2009, to March 31, 2019, period. The tariff approved is almost half of the tariff sought by East West Pipeline Ltd – the operator of the pipeline. It had sought the tariff to be raised to Rs 151.84 per mmBtu with effect from April 1, 2018. A rise in tariff would lead to increase in the price of fertiliser as well as city gas like CNG that uses gas brought through the pipeline starting from Kakinada in Andhra Pradesh and running up to Bharuch in Gujarat. The pipeline primarily transports KG-D6 gas, which has steadily dipped from 69.43 million standard cubic meters per day achieved in March 2010 to under 3 mmscmd. PNGRB in a 49-page order went into cost calculations and other parameters to fix the tariff. “The tariff has been worked out based on information provided by the entity and deliberations. However, PNGRB intends to verify/audit the information provided for tariff determination and method of cost allocation, etc. by an internal team of PNGRB or by an external agency,” the order said. The tariff, it said, will be subject to revision based on the audit of information and data. Originally, EWPL had proposed a levelised tariff of Rs 55.91 per mmBtu for transporting the gas beginning April 1, 2009 but PNGRB fixed a provisional tariff of Rs 52.53 per mmBtu. The company in October 2017 proposed a final tariff for the pipeline at Rs 78.72 effective from April 1, 2009, till the end of the economic life of the pipeline – up to March 31, 2034. When PNGRB sought clarifications, EWPL updated the tariff filing to state that Rs 52.23 per mmBtu would be the tariff till 2017 and Rs 151.84 would be charged from 2018-19 to 2035-36. The PNGRB order said the pipeline operator has claimed a total capex of Rs 18,307.37 crore under two heads – actual capex of Rs 16,347.96 crore and future capex of Rs 1,959.41 crore. PNGRB said when it first fixed the provisional tariff, it had assessed the pipeline’s carrying capacity of 85 million standard cubic metres per day including 21.25 mmscmd for use on a common carrier, open access and non-discriminatory basis by any third party. But the company challenged this first before the Appellate Tribunal of Electricity (APTEL) and then before the Delhi High Court. The Court had in April last year ordered fixing of the tariff once the quorum of PNGRB was complete. PNGRB became fully functional a year back when the government made appointments of Chairman and members of the Board. PNGRB sought views of stakeholders on EWPL’s tariff filing and gave a detailed order after considering all views.
Bengaluru: BBMP turns down GAIL’s request to lay gas pipelines
Residents of BTM Layout and Pattabhiramnagar wards, who are eagerly waiting for piped natural gas (PNG) to their homes, will have to wait longer. Reason: The Bruhat Bengaluru Mahanagara Palike (BBMP) has stopped GAIL India from laying pipelines in these areas. Bengaluru: BBMP turns down GAIL’s request to lay gas pipelines As per the Palike, roads in BTM Layout and Pattabhiramnagar wards have been recently laid and giving permission to dig them up would be against norms. It would be better for GAIL to wait for another year so that it can be allowed to lay pipelines, the agency said. GAIL is seeking to provide PNG supply to every household in the two wards for two years now. Last year, they were denied permission citing the legislative assembly polls. After BBMP south zone rejected its request for permission on the ground that the roads had been recently asphalted, GAIL approached chief secretary TM Vijay Bhaskar to resolve the matter, but to no avail. BBMP’s south zone chief engineer Prabhakar opined that roads are newly asphalted and their defect liability period is three years. According to sources in the BBMP, the contractor is under an obligation to maintain the road during the defect liability period. Any decision to permit digging up of the road could free the contractor of his obligations, they added. “BBMP has banned till next year digging up of recently laid roads so that people do not suffer. This was the main reason why GAIL was denied permission,” said an officer, who was part of the inter-department co-ordination committee, which met recently under the chairmanship of the chief secretary. GAIL has paid BBMP around Rs 18 crore towards road-cutting charges for a length of 127km in BTM Layout and Pattabhiramnagar wards. “We requested the transfer of this fee to take up works in other areas. But our request has not been granted. Once the ban period is over, we will again seek permission to lay pipelines in these wards,” said a GAIL official. Meanwhile, the chief secretary has directed BBMP commissioner N Manjunatha Prasad to consider GAIL’s request to transfer the road-cutting fee towards works in other areas and grant approval. The BBMP commissioner is yet to act on it.
US natgas output, demand seen rising to record highs in 2019
US dry natural gas production will rise to an all-time high of 90.73 billion cubic feet per day (bcfd) in 2019 from a record high of 83.35 bcfd in 2018, according to the Energy Information Administration’s Short Term Energy Outlook (STEO) on Tuesday. The latest March output projection for 2019 was up from EIA’s 90.16-bcfd forecast in February. EIA also projected U.S. gas consumption would rise to an all-time high of 83.57 bcfd in 2019 from a record high 82.06 bcfd in 2018. That 2019 demand projection in the March STEO report was up from EIA’s 82.53-bcfd forecast for the year in February.
Uniper says rising natural gas import demand to support its projects
Utility Uniper , Germany’s single biggest customer of Russian gas, on Tuesday said a widening import gap in Europe was supporting its strategy for pipeline and liquefied natural gas (LNG) projects, which were making good progress. “We assume that there will be additional gas import demand of 150 billion cubic metres per year by 2030 in Europe,” chief financial officer Christopher Delbrueck said at a news conference on the presentation of its 2018 earnings. He cited the loss of the major Dutch Groningen field, moves to shed coal burning and nuclear energy, and the intermittent nature of growing renewable energy that required more gas burning as a transition fuel towards a green future. Investment decisions for the Wilhelmshaven LNG terminal project, where Uniper will be a facilitator, would be taken by year-end, Uniper expects, hoping to arrange more prebooking of capacities soon. The Nord Stream 2 pipeline project for Russian gas, where Uniper is one of five western shareholders, was far advanced while needing further clearance by Germany’s energy regulator, Delbrueck said.
Asian jet fuel profit margins hit over eight-month low on weak demand
Asian refining margins for jet fuel dropped for a second straight session on Wednesday to their lowest levels in more than eight months, as crude prices firmed and demand for the distillate fuel remained weak. Refining margins for jet fuel, which also determine the profitability of closely-related heating kerosene, plunged to $13.19 a barrel over Dubai crude during Asian trading hours, their lowest since June last year. They were at $13.45 a barrel on Tuesday. The price for crude oil, a refinery’s most important and costly feedstock, on Wednesday, pushed up by ongoing supply cuts from producer cartel OPEC and U.S. sanctions against Iran and Venezuela. Jet fuel cracks have shed about 9 percent in the last one week, and are currently about 7 percent weaker than this time last year, Refinitiv Eikon data showed. Despite strong demand growth from the Asian aviation sector, the margins lacked the usual boost from seasonal heating demand this year due to a warmer winter, market watchers said. Airlines in the Asia/Pacific region posted a demand increase of 7.1 percent in January, compared to the same month last year, while domestic passenger demand grew about 12 percent in India and 14 percent in China, the International Air Transport Association (IATA) said in a March report. “Jet fuel demand per se is weak. Given the strong passenger statistics it may be more apt to say ‘kerosene’ demand is weak, leading to the stock surplus,” said Sukrit Vijayakar, director of energy consultancy Trifecta. “Jet has two uses — the first as aviation turbine fuel and the second for heating purposes. The second use does not seem to be holding its end of the bargain… I have often seen traders play the regrade suppressing jet prices further,” Vijayakar added. The regrade, the price spread between jet and gasoil, for April stood at a discount of 38 cents a barrel on Wednesday. Meanwhile, cash differentials for jet fuel cargoes in Singapore were at a discount of 25 cents a barrel to Singapore quotes on Tuesday amid lacklustre buying interests in the physical market. Seasonal refinery turnarounds in the region, however, is expected to keep a lid on supplies in the near term and upcoming summer travelling demand would likely offer some support to the aviation fuel in the next couple of months, trade sources said.
Shell, HES to resurrect German oil refinery ahead of IMO 2020 shipping rules
Royal Dutch Shell has struck a deal with Dutch tank terminal firm HES International to partially restart a German oil refinery mothballed since 2011 in response to new restrictions on marine fuels, two trading sources told Reuters. A new cap set by the International Maritime Organization (IMO) that will cut the sulphur content in shipping fuel to 0.5 percent from 3.5 percent from next year is set to be one of the biggest fundamental events to hit oil markets in years. HES Wilhelmshaven Tank Terminal is in the process of reinstalling the vacuum distillation unit (VDU) at Wilhelmshaven to produce low-sulphur bunker fuels ahead of the implementation of the IMO rules, a spokeswoman for the company said. HES said it had “reached a tolling agreement with a customer,” but declined to comment on the parties involved. However, two trading sources with knowledge of the matter told Reuters the customer in question is Shell. Shell declined to comment. The agreement is akin to a processing deal, whereby Shell brings in the feedstock and handles the end product, one of the sources said. HES bought the 260,000 barrel per day (bpd) refinery from ConocoPhillips in 2011 and converted it into a large-scale tank terminal facility with capacity of 1.3 million cubic metres. The plant’s refining capacity was shuttered at a time when several European refineries were finding it uncompetitive to remain operational, as newer, more complex mega-refineries emerged in other regions like the Middle East and Asia. But as the new IMO rules dictate a massive shift in oil product slates from higher to low sulphur, the economics are shifting and oil companies and traders are resorting to creative ideas to meet the new demand. The IMO sulphur restrictions will lead high-sulphur fuel oil demand to fall 60 percent to 1.4 million bpd next year, while marine gasoil demand will more than double to 2 million bpd, the International Energy Agency forecast this week. Vacuum distillation is an integral part of the refining process. VDUs typically run on residual fuel produced from distilling crude to produce vacuum gasoil which is then used to feed upgrading units that make gasoline and diesel. However, the Wilhelmshaven VDU will not be running on residual fuel, HES said. One of the sources said the plan is to process heavy, low-sulphur crudes like Brazilian grades to produce a range of products, including maximum 0.5 percent sulphur fuel oil or distillate marine fuels. HES is 70 percent owned by private investment firm Riverstone, with the remaining 30 percent held by the Carlyle Group. Infrastructure funds managed by banks Macquarie and Goldman Sachs agreed in principle last year to buy the company.