Oil exploration will remain a challenge for govts
Sector going through policy transition India’s hydrocarbon space will test the patience and policy consistency of the government of the day in the coming years as the country’s exploration policy enters a transition phase. Life of the New Exploration Licensing Policy (NELP) regime may remain only for the next 10-15 years, as the country’s entire oil and gas exploration as well as production business is shifting to Hydrocarbon Exploration Licensing Policy (HELP)-Open Acreage Licensing Programme (OALP). In many countries there are multiple models — revenue sharing, production sharing or customised — but these are places where the oil industry plays a dominant role. In India there are mainly three different categories — nomination basis: areas given prior to auction rounds; pre-NELP and NELP: where areas were given through auctions based on production sharing contracts; and HELP regime — a uniform licensing regime based on revenue sharing model and OALP. “Yes, all three can co-exist, but the challenge will be in implementation. The government of the day will be under pressure to ensure that there is no interruption in this high risk business due to policy issues,” an oil industry tracker said. But, the moot point is whether HELP will turn the tides for India in meeting its energy demand. HELP is just taking baby steps and by the time it stabilises it will take, conservatively speaking, a few years, said an analyst. Particularly when with growing consumption, India’s demand is also going to put pressure on the import bill. According to the Petroleum Planning & Analysis Cell estimates, the crude oil import bill is likely to increase by 27 per cent from $88 billion in 2017-18 to $112 billion in 2018-19 considering actual upto December 2018 and Indian basket (rate at which domestic refiners buy their requirement) crude oil price at $57.77 a barrel and exchange rate at ₹70.73 versus dollar for January 2019-March 2019. No uniform model The challenge is that India does not have a uniform licensing model for forming a base. Therefore, what will HELP mean economically, one will have to wait and watch, said an official in the know. Since NELP was introduced in the late 1990s, 314 blocks have been offered under various auction rounds, of which 254 have been awarded. There are 60 NELP blocks that are operational today by players such as ONGC, Reliance Industries and Oil India. From 2017 all new contracts have been signed under the HELP regime. Although most of the producing blocks in the country, at present, are those that have been offered before NELP or after NELP. All these production sharing contracts have a life. OALP is a continuous bidding process. In February, the government launched the third OALP bidding round offering 23 blocks. It has contracted for 55 blocks under OALP Bid Round-I. The second round was launched in January offering 14 blocks. The OALP adopts all features of HELP — reduced royalty rates, no oil cess, uniform licensing system, marketing and pricing freedom, revenue sharing model, exploration rights on all retained area for full contract life, among others. Discovered small field Parallely the government has been offering areas under Discovered Small Field policy. The second round of DSF is under way with the Empowered Committee of Secretaries (ECS) and Group of Ministers recently giving their nod for the award of 23 contract areas to highest ranked bidders. “The government is taking measures, but it has to ensure that market flexibility is taken care of and continuity in policy implementation remains. Besides, time taken to bring blocks offered under OALP into production will be at least eight-ten years,” said an industry player.
Piped gas to cover 70% of India’s population: Oil minister Dharmendra Pradhan
More than 70% of India’s population will get access to piped natural gas services, up from 20% five years back, once the projects awarded in the 10th auction of licences for setting up CNG and PNG networks are completed, oil minister Dharmendra Pradhan said. Handing over the latest batch of 12 LoIs (letters of intent) covering 50 geographical areas auctioned in the 10th round, Pradhan said the government is concentrating on increasing domestic production of gas along with the expansion of the gas distribution network. “This will greatly help India become self-sufficient for its energy needs, lower our import dependence and help save foreign exchange,” Pradhan said. The minister’s statement underpins the fact that CNG and PNG cost less than convention fuels – petrol or diesel and LPG, respectively – because these services are fully run on domestic gas, which is cheaper than natural gas imported in ships. Expansion of PNg networks will not only benefit consumers in terms of cost advantage and convenience, it will also free up funds of state-run fuel marketers that are locked up in LPG cylinders. The city gas projects in the 50 geographical areas underway will entail rollout of over 2 crore PNG connections and 3,578 CNG stations. During the current bid round, state-run IndianOil has won licences for 10 cities and HPCL for nine geographical areas. IOC won city gas distribution licences for nine cities, most of them in Bihar and Jharkhand, on its own and one in a joint venture with Adani Gas. A consortium of LNG Marketing Pte Ltd and Atlantic Gulf & Pacific Company of Manila Inc has bagged rights for setting up gas infrastructure and retailing nine cities in Andhra Pradesh, Karnataka and Kerala.
Rs 9,000 crore gas-grid project for North East, Bengal: Dharmendra Pradhan
A Rs 9,000 crore gas-grid project has been approved to transport natural gas among northeastern states and West Bengal, Union Petroleum and Natural Gas Minister Dharmendra Pradhan said here. “There is huge amount of natural gas available in Assam, Tripura, Arunachal Pradesh and other northeast states is being tapped into for the Rs 9,265 crore North East Gas Grid (NEGG). The government has okayed this project to transport gas among the northeastern states as well as West Bengal via Siliguri,” Pradhan said inaugurating the Rs 215 crore Sonamura Gas Collecting station of Oil and Natural Gas Corporation (ONGC). An ONGC official said the NEGG is a joint venture of five oil and natural gas companies — Gas Authority of India Limited (GAIL), Indian Oil Corporation Limited (IOC), Oil India Limited (OIL), Numaligarh Refinery Limited (NRL) and ONGC. Huge onshore gas reserves have been found in Assam, Gujarat, Andhra Pradesh, Tamil Nadu and Tripura, which is also the number one gas producing state for ONGC. The transportation and availability of cooking gas (liquefied petroleum gas — LPG) has been eased after the Centre signed a deal with the Bangladesh to ferry LPG via Chittagong international sea port and land route. “Carrying LPG tankers or cylinders by trucks through the northeast is a big problem due to its mountainous terrain. The ferrying through Bangladesh will not only be cost-effective but also consume less time,” the minister said. Use of Tripura’s gas reserve would also improve revenue and income of the state, he said. The ONGC should explore more gas reserves to develop new industries, power plants and other projects in the state to help create jobs, Chief Minister Biplab Kumar Deb said. The ONGC has been working in Tripura for the past five decades. It has drilled 225 wells and found gas in 116. A 726 MW power plant in southern Tripura is already using local reserves, the ONGC said. The gas-based power projects is supplying electricity to all the northeastern states and Bangladesh (160 MW). Resereves are also providing CNG to fuel thousands of vehicles and PNG for household and industrial consumption.
Oil regulator rejects Adani Gas’ application for CNG retailing in Jaipur, Udaipur
Oil regulator PNGRB has rejected Adani Gas Ltd’s application for authorisation to retail CNG to automobiles and piped natural gas to households in Jaipur and Udaipur, saying the company was not in compliance with regulations for a licence. In a 23-page order, the Petroleum and Natural Gas Board (PNGRB) on February 28 gave detailed reasons for rejecting Adani Gas Ltd’s (AGL) claim of having ‘deemed authorisation’ to operate a city gas distribution (CGD) network in the two cities before the regulator came into existence. “Based on the analysis and deliberations of the Board after hearing and considering the submissions of AGL and keeping in mind the observations/directions of the Supreme Court of India, the application of AGL for Jaipur and Udaipur cities for CGD authorisation is herby rejected,” it said. Adani Gas had, in response to a November 2005 invitation of Rajasthan government, bid for setting up the city gas distribution (CGD) network in Udaipur and Jaipur. The state government on March 20, 2006 gave a no objection certificate, subject to certain conditions, to the company for retailing CNG and piped natural gas in Udaipur and Jaipur. Adani Gas in the same month deposited the commitment fee of Rs 2 crore. Subsequent to this, the central government in October 2007 appointed PNGRB as the regulator for the sector. Soon after, PNGRB sought application from companies operating CGD networks before its appointment as the regulator. PNGRB on March 31, 2008 issued a notice to Adani Gas stating “it did not have the requisite authorisation from the central government,” the order said, adding the company submitted separate applications for authorisation for Jaipur and Udaipur to the regulator on August 28, 2008. On May 18, 2011, the Rajasthan government withdrew the NOC given to Adani Gas. Subsequently on May 19, 2011, PNGRB rejected Adani Gas’ application for both the cities. The company challenged the decision of PNGRB before Rajasthan High Court which dismissed its petition. It then filed an appeal before the Supreme Court. “Supreme Court vide order dated January 29, 2019 quashed the order dated May 19, 2011 passed by the Board and directed the Board to take a fresh decision in the matter within four weeks,” the order said. In compliance with the Supreme Court order, PNGRB held personal hearing with Adani Gas representatives. The company contended that “it was entitled to be granted authorisation by the Board in view of the provision of ‘deemed authorisation’ as contained in Section 16 of the (PNGRB) Act” for entities operating before the regulator came into existence. In its order, PNGRB said Adani Gas meets the minimum eligibility criteria but did not comply with the requirement of making committed investments and physical progress in rollout of CGD network in both the cities. Also, it had not tied up gas for supply through the CGD networks. “The conclusion of the Board is that Adani Gas is in non-compliance with a substantial part of the criteria,” it said. On the company’s claim of having made substantial investment in the two cities, PNGRB said “no documentary evidence has been presented by Adani Gas to show the mammoth expenditure it has supposedly incurred on the project.”
Australia planning to import LNG: What’s next? Coals to Newcastle?
Australia is on the verge of becoming the biggest exporter of liquefied natural gas, with dozens of tankers a week carrying fuel to North Asia. It could also soon be importing LNG as supply sources in its southern states run out. Five LNG import projects are vying to start up between 2021 and 2022, possibly forcing gas users in New South Wales, South Australia, Tasmania and Victoria into more direct competition with Asian buyers for gas from northern Australia. Those states represent a yearly market of 420 petajoules (PJ), equivalent to 7.8 million tonnes of LNG worth about $3 billion. That represents just 2 percent of global LNG trade, but import proponents say the terminals would be another key outlet for spot cargoes of the fuel, especially during periods of low demand in the northern hemisphere. Piping gas from Queensland in northern Australia to southern markets is expensive, making LNG imports potentially viable. Credit Suisse analyst Saul Kavonic says, though, if final investment decisions are delayed into 2020, the case for imports will weaken as pipeline tariff reforms are likely by then. “Based on the five proposals to date, Australia now appears to be planning to overbuild LNG import capacity in response to an overbuild of LNG export capacity,” Kavonic said. Eastern Australia has ample gas reserves to meet demand. The market outlook is tight, though, due to falling output from Exxon Mobil’s and BHP Group’s Gippsland Basin joint venture off Victoria, rising production costs and state restrictions on onshore drilling. “We definitely would see a rationale for one terminal to give another source of gas into the east coast market,” said Nicholas Browne, Asia gas and LNG director at consultancy Wood Mackenzie. “We think one terminal would be sufficient till the mid to late 2020s.” Import advocates need to be wary, however, of potential government moves to divert gas from exports to the domestic market and approvals for two long-delayed local gas projects, Narrabri and Surat. Gippsland Basin output could also prove more resilient than expected. AGL’s Crib Point project is the most likely to go ahead, industry executives and analysts say. Australian Industrial Energy’s (AIE) Port Kembla terminal is also possible, but that hinges on signing up industrial customers. Two other projects – Newcastle LNG, led by privately owned South Korean firm EPIK, and Venice Energy, set up by former executives of BHP Group now at Integrated Global Partners – have yet to submit applications for state approvals. Newcastle LNG and Venice Energy are looking to limit commercial risk by building import terminals and charging suppliers and traders to regasify LNG to sell to customers. “We aim to provide a cost-efficient infrastructure solution in markets that are in need of gas,” said EPIK founder Jee Yoon. Australian LNG producer Woodside Petroleum said gas for such pay-per-use terminals could come from Australia, the United States, Asia, wherever spot prices are cheapest. “We would take those cargoes out of our portfolio, and we would decide where they come from,” Woodside Chief Executive Peter Coleman told reporters in February. Exxon Mobil is a big wild card, as it is considering imports to protect its turf in southeastern Australia, where it has been the dominant supplier for nearly 50 years. Its infrastructure and experience selling into the southeastern market put it in a unique position, said Exxon Mobil Australia Chairman Richard Owen. “We’ve got some competitive advantage and probably have a little bit more time than some of the other players,” Owen said at a business event on Friday. ADVANTAGE TO AGL Importing LNG into a gas-rich country is not new. Both Malaysia and Indonesia, the third and fifth-biggest LNG producers, have import terminals because transporting gas between islands by ship makes more sense than pipelines. AGL, Australia’s No.2 energy retailer, is the furthest ahead with its import plan. Pending a state environmental review, it expects to make a final investment decision by early 2020, targeting first imports in 2021. Its advantage over AIE is that it has an existing customer base for its gas. AIE still hopes to be the first up and running, expecting approval from New South Wales this quarter for a mid-2020 start. “We think there’s a significant shortfall of gas in the domestic market,” said AIE Chief Executive James Baulderstone. AIE, working with the world’s biggest LNG buyer, Japan’s JERA, and Marubeni Corp on import plans at Port Kembla in New South Wales, has been talking to industrial customers for more than a year, without yet signing any buyers. “We’ve had oil prices moving around a fair bit and a lot of our LNG is priced to oil. That’s obviously a big issue,” Baulderstone said. At $60 a barrel for oil, several dollars below the current Brent price, AIE sees LNG imports as competitive with domestic pipeline gas. Industrial users are reluctant to commit to imports amid uncertainty over local gas developments, notably Narrabri in New South Wales, for which Santos Ltd hopes to win state approval this year. Royal Dutch Shell’s and PetroChina’s Arrow Energy Surat project in Queensland, Australia’s biggest undeveloped coal seam gas resource, aims to start producing by 2021, but has been delayed due to a spat between the partners. An international LNG trader said Australia could build up to two LNG import terminals, but called it absurd. The country just needs to lower pipeline tariffs to ease the flow of gas from north to south, he said. “As a trader, I think it’s really insane. When this kind of insanity happens, it doesn’t last for very long.”
AG&P plans to invest Rs 10,000 crore in India city gas business
Atlantic Gulf & Pacific Co of Manila Inc (AG&P) plans to invest Rs 10,000 crore in its city gas business in India over eight years. The company is confident of meeting the steep targets it had promised: to win 12 city gas distribution licences, the highest by a foreign bidder. In the recent tenth round that offered 50 licences, AG&P shared the top slot with Indian Oil and Hindustan Petroleum Corp, each winning nine geographical areas. Other winners included Gujarat Gas (six), Gail Gas (four), Indraprastha Gas (three), Torrent Gas (three), Adani (two) and Bharat Petroleum Corp (two). Eleven of the 12 geographical areas for which AG&P has licences— it won three in the ninth round last year— are in the four southern states, and their proximity to each other as well as to current and proposed liquefied natural gas (LNG) terminals in the region will facilitate easy and cheaper sourcing of gas for customers, said PPG Sarma, managing director for CGD and logistics at AG&P. Sarma, credited with building GSPC Gas’ vast city networks as CEO, said that the experience would come in handy in launching AG&P’s services. It’s planning a floating LNG storage unit in Puducherry by the end of next year and may also tap Petronet’s LNG terminal in Kerala and that of Indian Oil in Tamil Nadu. The government provides cheaper domestic gas for use by households and vehicles but industrial and commercial users pay market rates. Its ability to import LNG and control over import infrastructure can thus give AG&P the advantage. “The city gas areas awarded to AG&P in this round will benefit in the schedule, pricing and gas availability by leveraging our global project teams, our standard designs and our ownership of the full, integrated supply chain of LNG and gas,” said AG&P CEO Joseph Sigelman. AG&P plans to haul LNG via tankers from import terminals to planned satellite terminals in its licence areas to quickly launch CNG services without waiting for pipelines to be built. State-run GAIL operates a satellite LNG station in Bhubaneswar to serve customers in the absence of a pipeline. The Philippines company plans to launch a few CNG stations by the end of this year and piped gas services by next year-end, Sarma said. AG&P is confident of meeting its target of connecting 12 million households, building 1,500 CNG stations and laying 17,000 inch-kilometres of steel pipeline over eight years, he said, allaying apprehension that the company had been over-ambitious in its bids for licences. AG&P will try and move away from “conventional city gas models” and introduce measures that will create more value for customers, Sarma said, citing the possibility of providing a single platform for customer billing and payments, laying broadband fibre along pipelines, encouraging gas-based kitchen appliances and working with industrial customers for better efficiency.
Russia still choosing between TurkStream gas pipeline extension options
Russia is still considering various options to extend the second part of the TurkStream natural gas pipeline that Russia is laying under Black Sea to bypass Ukraine, Prime Minister Dmitry Medvedev said. In an interview with Bulgarian daily Trud released early on Monday ahead of a visit by Medvedev to Bulgaria, Russia’s head of the government said the future of the pipeline extension depends on the interest of other countries and steps they take. “The final decision does not depend solely on us. Choosing between various options for the TurkStream extension will be, to a large extent, determined by the readiness of gas transport infrastructure,” Medvedev said. Russian gas giant Gazprom, which supplies about 34 percent of the European gas market, built the first line of the TurkStream pipeline to Turkey for local gas consumption. The extension is part of the Kremlin’s plans to bypass Ukraine, currently the main transit route for Russian gas to Europe, and to strengthen its hold on European gas markets. Bulgaria launched a tender for the new gas link with Turkey in mid-2018 in a move to persuade Russia to extend the second part of the TurkStream pipeline to its border rather than Greece.